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{{#Wiki_filter:Exhibit 8 Power Purchase Agreements for NMP 1 and NMP 2 Execution Copy PRODUCER -CUSTOMER NMP -2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Niagara Mohawk Power Corporation
{{#Wiki_filter:Exhibit 8 Power Purchase Agreements for NMP 1 and NMP 2
("CUSTOMER"), a New York company with offices located at 300 Erie Boulevard West, Syracuse, NY 13202 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
 
Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Niagara Mohawk Power Corporation ("CUSTOMER"), a New York company with offices located at 300 Erie Boulevard West, Syracuse, NY 13202 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
WITNESSETH:
WITNESSETH:
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA"); WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in Nine Mile Point Unit No. 1 Nuclear Generating Station ("NMP-1I"), dated December 11, 2000 (the "NMP-2 APA"); WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");
("Niagara Mohawk") and New York State Electric & Gas Company ("NYSEG")
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in Nine Mile Point Unit No. 1 Nuclear Generating Station ("NMP-1I"), dated December 11, 2000 (the "NMP-2 APA");
have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA"). NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows: 1. DEFINITIONS.
WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &
In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").
1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include-1-DCLAN01:1!28365.
NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:
I scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves), and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.4. "Closing" shall have the meaning set forth in the NMP-2 APA. 1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months. 1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A. 1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time. 1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and DCLANOI:128365.1 transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output. 1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA. 1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and- Control Area Services Tariff, as amended or superseded from time to time. 1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time. 1.12. "Effective Date" shall mean the date of the Closing.
: 1.       DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, ortransmitted over a period of time, and measured or calculated in megawatt hours (MWh). 1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour. 1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations.
1.1.     "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include DCLAN01:1!28365. I scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),
Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry.
and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council ("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC")
1.2.     "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
criteria, guidelines, rules DCLANO I: 128365.1 and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities.
1.3.     "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
When applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.4.     "Closing" shall have the meaning set forth in the NMP-2 APA.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules. 1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates". 1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective -Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.5.     "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.
1.6.     "Contract Year Base Price" shall mean the prices so identified in Schedule A.
1.7.     "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.
1.8.     "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and DCLANOI:128365.1 transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.
1.9.       "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.
1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and-Control Area Services Tariff, as amended or superseded from time to time.
1.11.       "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.
1.12. "Effective Date" shall mean the date of the Closing.
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, ortransmitted over a period of time, and measured or calculated in megawatt hours (MWh).
1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.
1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council
("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules DCLANO I: 128365.1 and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.
1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".
1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the Off-Peak Monthly Price Factor for the respective
              -Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.DCLANOI:128365.1 4-1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time. 1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero. 1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m., prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO. 1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m. inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO. 2. CONDITION PRECEDENT.
1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is =exactl ten years after the lastday of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
DCLANOI:128365.1                                 4-
 
1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.
1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.
1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,
prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.
1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.
inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.
: 2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is
      =exactl ten years after the lastday of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
: 4. INSTALLED CAPACITY.
: 4. INSTALLED CAPACITY.
4.1. Sale of Installed Capacity.
4.1.       Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum DCLANOI:128365.1 of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.
PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum DCLANOI:128365.1 of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period. 4.2. Performance.
4.2.     Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.
PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests. 5. ENERGY. 5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh. 5.2. Performance.
: 5.     ENERGY.
Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
5.1.     Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) forty-one percent (41%) times (ii)ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.
If for any reason which is not-prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy. 5.3. Scheduling.
5.2.     Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below. 5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement.
If for any reason which is not-prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.
PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by DCLANOI:128365.1 PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.
5.3.     Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.
5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by DCLANOI:128365.1 PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.
5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
5.3.3. Mitigation.
5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.
The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party. 5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point. 5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point. 5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other .thantaxes based on PRODUCER's and/or CUSTOMER's net income), shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output. 5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings.
5.4.       Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.
Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
5.5.       Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.
5.6.       Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other
                .thantaxes based on PRODUCER's and/or CUSTOMER's net income),
shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.
5.7.       Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
DCLANO1: 128365.1
DCLANO1: 128365.1
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 8. BILLINGS AND PAYMENTS.
: 8. BILLINGS AND PAYMENTS.
8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5k" day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5 th) day of the calendar month in which the invoice is rendered.
8.1.     Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5k" day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth ( 2 5 th) day of the calendar month in which the invoice is rendered. In the event the 25t" is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.
In the event the 25t" is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day. 8.2. Overdue Payments.
8.2.     Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
8.3.     Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.DCLAN01:128365.I 8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s) (such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note in relation to the NMP-1 APA and the NMP-2 APA against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement, or the NMP-1 Power Purchase Agreement.
DCLAN01:128365.I
CUSTOMER hereby acknowledges and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
 
8.4.       Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)
(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note in relation to the NMP-1 APA and the NMP-2 APA against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement, or the NMP-1 Power Purchase Agreement. CUSTOMER hereby acknowledges and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
: 9. DEFAULT, TERMINATION AND LIABILITY.
: 9. DEFAULT, TERMINATION AND LIABILITY.
9.1. Breach, Cure and Default.
9.1.       Breach, Cure and Default.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law. 9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such DCLANOI :128365.1 breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii) where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the breach cannot be cured within any commercially reasonable period of time. 9.1.4. Remedies upon Default Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof. 9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.
No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights. 9.2. Termination.
9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such DCLANOI :128365.1 breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii)where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the breach cannot be cured within any commercially reasonable period of time.
If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.1.4. Remedies upon Default Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof.
9.3. Additional Remedies.
9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.
A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.DCLANO i: 128365.1 9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.2.         Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
9.3.         Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
DCLANO i: 128365.1 9.4.       Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.5.       Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
10.1. Party Representatives.
10.1.       Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.
The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access. 10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows: If to PRODUCER:
10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:
Constellation Nuclear, LLC 39 West Lexington Street DCLANO 1:128365.1 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile:
If to PRODUCER:
(410) 234-5323 If to CUSTOMER:
Constellation Nuclear, LLC 39 West Lexington Street DCLANO 1:128365.1 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 If to CUSTOMER:
Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse, NY 13202 Title: Director of Energy Transactions Attn.: Scott Leuthauser Phone: (315) 428-6006 Facsimile:
Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse, NY 13202 Title: Director of Energy Transactions Attn.: Scott Leuthauser Phone: (315) 428-6006 Facsimile: (315) 428-6129 If given by electronic transmission (including telex, facsimile or telecopy),
(315) 428-6129 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery.
notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.---
PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.---11. BUSINESS RELATIONSHIP.
: 11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage.
: 12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
: 13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
: 12. CONFIDENTIALITY.
In addition, the rates, terms, and conditions contained in this Agreement are not DCLAN01:128365.1                               'a
Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
 
: 13. GOVERNMENT REGULATION.
subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
In addition, the rates, terms, and conditions contained in this Agreement are not DCLAN01:128365.1 'a subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
: 15. DISPUTE RESOLUTION.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION.
This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York. 15. DISPUTE RESOLUTION.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.
The arbitration process shall be concluded not later than six (6) months after the date that it is initiated.
The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.
Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
: 16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be DCLANOI:128365.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes.
                                                                                                  -
Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party. 16. WAIVER AND AMENDMENT.
 
Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be DCLANOI:128365.  
construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
-
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
construed as a bar to, or a waiver of, any right either Party has under this Agreement.
: 18. ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
: 19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poors Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are DCLAN01:128365.1 satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS.
    -Assignee-Entity may have any control or management or operational rights or role with respect to the Assignee Entity, and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
: 18. ENTIRE AGREEMENT.
This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter. 19. ASSIGNMENT.
CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poors Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment);
and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are-14-DCLAN01:128365.1 satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the -Assignee-Entity may have any control or management or operational rights or role with respect to the Assignee Entity, and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
: 20. SIGNATORS' AUTHORITYICOUNTERPARTS.
: 20. SIGNATORS' AUTHORITYICOUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.
The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party. This Agreement may be executed in two or more counterparts, each of which shall be an original.
This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
: 21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
: 21. NO DEDICATION OF FACILITIES.
: 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.
No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity. 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.DC LANO1:128365.1 DE:ý-'-C TUE -2;,10 AM ECONO LODGE FXN.3~412 P. 06/,l-, 41 R'M vSkC W'&.C:H7 (N1i2. 11!' 19: 15/ST.7 19 14;/-N0 4E6 '79 ',20cE ? 4 IN WITNESS WHEREOF,.
DC LANO1:128365.1 DE:ý-'-C     TUE - 2;,10 AM   ECONO LODGE                   FXN.3~412 FAX NO. 3IS3431222                          P. 06/,l-,
2nd intending to be levelty bound, the Parties hav'e W~ecuted this Agreement by the undersigned duly auihorized representatives as of the date first stated above.CUSTOMER By: Namne: TM*t: DATE: December 11. 200 0 TT0~ ~ozz9zGzzzTe
R'M vSkC W'&.C:H7 41                                                (N1i2. 11!'     19: 15/ST.7 19 14;/-N0 4E6 '79 ',20cE ? 4 IN WITNESS WHEREOF,. 2nd intending to be levelty bound, the Parties hav'e W~ecuted this Agreement by the undersigned duly auihorized representatives as of the date first stated above.
(-- SIdflOd i03fO~d FAX NO. 3IS3431222 PRODUCER By: Name* 4UT Title: PRF5ioecWfr
PRODUCER                                    CUSTOMER By:                                         By:
%;w 6-77-ON TTW ZVV'0N GT:00 0002/ZT/ET DEC-11-00 MO0N 21:38 1Rov S&C WASHINGTON
Name*        4UT                            Namne:
: r. MKON) 12. 11' 00 IS8:-53/ST.
Title:      PRF5ioecWfr                      TM*t:
18:52WK. 4861798207 P 2 I P~RODUCER Name: CUSTOMER Name: WiILLIAM F. r~J.RDW-lP TMtl: "a;r VIC. ?rplvAT A-L~DATE. Dmmber 11, 2000 INd WITNE88 WHUIRCOF, and Intending to be legaib' bound, the Paitle hawe 6www~tad thts Agreement by the undersigned duly authoFIlmd representmatie as of the SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLANO 1: 128365.I SCHEDULE B "Monthly Price Factors" DCLANOI:128365.I Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 Execution Copy PRODUCER -CUSTOMER NMP -2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and New York State Electric & Gas Corporation
DATE: December 11. 200 0
("CUSTOMER"), a New York company with offices located at Corporate Drive, Kirkwood Industrial Park, Binghamton, NY 13902-5224 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
  %;w     6-77-ON TTW   ZVV'0N                                 TT0~    ~ozz9zGzzzTe
(-- SIdflOd    i03fO~d      GT:00       0002/ZT/ET
 
r.
DEC-11-00 MO0N 21:38 I                                                      MKON) 12. 11' 00 IS8:-53/ST. 18:52WK.4861798207 P 2 1Rov S&C WASHINGTON INd WITNE88 WHUIRCOF, and Intending to be legaib' bound,        the Paitle hawe duly  authoFIlmd    representmatie  as of the 6www~tad thts Agreement by the undersigned CUSTOMER P~RODUCER Name:                                         Name:     WiILLIAM     F. r~J.RDW-lP TMtl:   "a;r       VIC.   ?rplvAT         A-L~
DATE. Dmmber 11, 2000
 
SCHEDULE A "Contract Year Base Prices" Contract         Price Year       ($ per MWh) 1             $35.70 2             $35.32 3             $33.95 4             $33.60 5             $33.56 6             $33.23 7             $33.91 8             $34.61 9             $35.32 10           $36.05 DCLANO 1:128365.I
 
SCHEDULE B "Monthly Price Factors" Month     On-Peak             Off-Peak January       1.1865             0.6746 February     1.1865             0.6746 March       0.9492             0.6133 April     0.9492             0.6133 May         1.4238             0.7052 June       1.6611             0.7359 July       2.1357             0.7666 August     2.1357             0.7666 September     1.6611             0.7359 October     0.9492             0.6133 November     0.9492             0.6133 December     1.1865             0.6746 DCLANOI:128365.I
 
Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and New York State Electric & Gas Corporation ("CUSTOMER"), a New York company with offices located at Corporate Drive, Kirkwood Industrial Park, Binghamton, NY 13902-5224 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
WITNESSETH:
WITNESSETH:
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA"); WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");
("Niagara Mohawk") and New York State Electric & Gas Company ("NYSEG")
WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &
have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA"). NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows: 1. DEFINITIONS.
Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").
In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:
1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves), DCLAN 128366.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.4. "Closing" shall have the meaning set forth in the NMP-2 APA. 1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months. 1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A. 1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time. 1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN128366.1 shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output. 1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA. 1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time. 1.12. "Effective Date" shall mean the date of the Closing.
: 1.       DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh). 1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour. 1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations.
1.1.   "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),
Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry.
DCLAN 128366.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council ("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC")
1.2.     "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities.
1.3.     "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
When DCLAN128366.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.4.   "Closing" shall have the meaning set forth in the NMP-2 APA.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules. 1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates". 1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.5.   "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.6.   "Contract Year Base Price" shall mean the prices so identified in Schedule A.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time. 1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.DCLAN128366.1 4-1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero. 1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m., prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO. 1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m. inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO. 2. CONDITION PRECEDENT.
1.7.   "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.
It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
1.8.   "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN128366.1
 
shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.
1.9.   "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.
1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
1.11.   "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.
1.12. "Effective Date" shall mean the date of the Closing.
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).
1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.
1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council
("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When DCLAN128366.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.
1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".
1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
1.21.   "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.
1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.
DCLAN128366.1                                   4-
 
1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.
1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,
prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.
1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.
inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.
: 2.     CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
: 4. INSTALLED CAPACITY.
: 4. INSTALLED CAPACITY.
4.1. Sale of Installed Capacity.
4.1. Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.
PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period. 4.2. Performance.
4.2. Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the DCLAN128366.1 Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.
PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the DCLAN128366.1 Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests. 5. ENERGY. 5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh. 5.2. Performance.
: 5.     ENERGY.
Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
5.1.     Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.
If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy. 5.3. Scheduling.
5.2.     Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below. 5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement.
If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.
PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.DCLAN128366.1 5.3.2. Net Electric Output CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
5.3.     Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.
5.3.3. Mitigation.
5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.
The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party. 5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point. 5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point. 5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income), shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output. 5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings.
DCLAN128366.1 5.3.2. Net Electric Output CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.
5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.
5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.
5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income),
shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.
5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN128366.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN128366.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 8. BILLINGS AND PAYMENTS.
: 8.     BILLINGS AND PAYMENTS.
8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5 th) day of the calendar month in which the invoice is rendered.
8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth ( 2 5 th) day of the calendar month in which the invoice is rendered. In the event the 2 5th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.
In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day. 8.2. Overdue Payments.
8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s) (such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement.
8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)
CUSTOMER hereby acknowledges DCLAN128366.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement. CUSTOMER hereby acknowledges DCLAN128366.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
: 9. DEFAULT, TERMINATION AND LIABILITY.
: 9. DEFAULT, TERMINATION AND LIABILITY.
9.1. Breach, Cure and Default.
9.1.     Breach, Cure and Default.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law. 9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii) where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN128366.1 breach cannot be cured within any commercially reasonable period of time. 9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof. 9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.
No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights. 9.2. Termination.
9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii)where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN128366.1 breach cannot be cured within any commercially reasonable period of time.
If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof.
9.3. Additional Remedies.
9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.
A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
9.2.     Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.3.     Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN128366.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
9.5.     Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN128366.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
10.1. Party Representatives.
10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.
The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access. 10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows: If to PRODUCER:
10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:
Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile:
If to PRODUCER:
(410) 234-5323 DCLAN128366.1 If to CUSTOMER: New York State Electric & Gas Corporation Corporate Drive Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Title: Senior Vice President Attn.: Jeffrey K. Smith Phone: (607) 762-4440 Facsimile:
Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 DCLAN128366.1 If to CUSTOMER:
(607) 762-4345 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery.
New York State Electric & Gas Corporation Corporate Drive Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Title: Senior Vice President Attn.: Jeffrey K. Smith Phone: (607) 762-4440 Facsimile: (607) 762-4345 If given by electronic transmission (including telex, facsimile or telecopy),
PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent. 11. BUSINESS RELATIONSHIP.
notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.
Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage.
: 11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
: 12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
: 12. CONFIDENTIALITY.
: 13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
: 13. GOVERNMENT REGULATION.
DCLAN128366.1
This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.DCLAN128366.1
: 15. DISPUTE RESOLUTION.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION.
This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York. 15. DISPUTE RESOLUTION.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.
The arbitration process shall be concluded not later than six (6) months after the date that it is initiated.
The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.
Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
: 16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes.
DCLAN128366.1
Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party. 16. WAIVER AND AMENDMENT.
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement.
: 18.     ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.DCLAN128366.1
: 19.     ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which DCLAN128366.1 have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity, and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS.
This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
: 18. ENTIRE AGREEMENT.
This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter. 19. ASSIGNMENT.
CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment);
and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which DCLAN128366.1 have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity, and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
: 20. SIGNATORS' AUTHORITY/COUNTERPARTS.
: 20. SIGNATORS' AUTHORITY/COUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.
The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party. This Agreement may be executed in two or more counterparts, each of which shall be an original.
This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
: 21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
: 21. NO DEDICATION OF FACILITIES.
: 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.
No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity. 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.DCLAN128366.1 12/11/00 09:29 FAX Hi DEO-11-2000 HN 0'o9 PH OHAIRfA OFFIOE
DCLAN128366.1 12/11/00         09:29 FAX                         HiUBER LAWRENCE & ABELL                          Q006 FAX NO, 0077024345                  P. 01 DEO-11-2000 HN 0'o9 PH OHAIRfA           OFFIOE
* 1 UBER LAWRENCE & ABELL FAX NO, 0077024345 Q006 P. 01 IN WITNESS WHEREOF, and intending to be legally bound, the Parties have eXer-ktAd this Agreement by the undersigned duly authorized reprmentatlvoo as of the date first stated above. PRODUCER CUSTOMER Name: %",firk'EY C- C ' 7P Name: Title:* I Tite; S" VJF2, DATE: December 11, 2000 T1u-NWIDER LAWRNICE & AN Pas 001!Rleceived 12-1l-OO 21805 Frou-90771l4045  
*1 IN WITNESS WHEREOF, and intending to be legally bound, the Parties have eXer-ktAd this Agreement by the undersigned duly authorized reprmentatlvoo as of the date first stated above.
.r 2-00 TUE 12:43 AM ECONO LODGE FAX NO. 3153431222 P. 02/03 (MNJ?.I6 9:,'5/sT.  
PRODUCER                                         CUSTOMER
~I4C e1g25?6 WN WITNESS VWHEROp. and intendina to b& "eAlty boUnd, the parti.u have Th execut.4 this Agreenwnt by the undersigned duly authorzrpr tvamuoth date first stated above. _idf~eettvaa ft, ThtIp OA~r: December 11 2000 C)-Sx-iod31 Bcid CUSTOMER By: PRODUCER By. Namrne: -A-pgswr-Wof TI'L 800f ZPr*ON A7 :7=
  !
SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLAN128366.1 SCHEDULE B "Monthly Price Factors" DCLAN128366.1 Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 Execution Copy PRODUCER -CUSTOMER NMP -2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Rochester Gas and Electric Corporation
Name:                                            Name: %",firk'EY           C- C   ' 7P Title:                                             Tite;     S"VJF2,
("CUSTOMER"), a New York company with offices located at 89 East Avenue, Rochester, New York 14649 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
* I DATE: December 11, 2000 Rleceived   12-1l-OO 21805   Frou-90771l4045               T1u-NWIDER LAWRNICE &AN  Pas 001
 
2-00 TUE 12:43 AM
          .r ECONO LODGE                   FAX NO. 3153431222 P. 02/03 (MNJ?.I6   9:,'5/sT. ~I4C     e1g25?6 Th execut.4WN WITNESS       VWHEROp. and intendina to b&"eAlty this Agreenwnt  by the undersigned                boUnd, the parti.u have duly authorzrpr           tvamuoth date first stated above.                                 _idf~eettvaa             ft, PRODUCER CUSTOMER By.
Namrne: -A-pgswr-                              By:
ThtIp OA~r: December 11 2000 C)
Wof  TI'L
                                                              - Sx-iod31 Bcid       A7 :7=
800f ZPr*ON
 
SCHEDULE A "Contract Year Base Prices" Contract         Price Year       ($ per MWh) 1           $35.70 2             $35.32 3             $33.95 4             $33.60 5             $33.56 6             $33.23 7             $33.91 8             $34.61 9             $35.32 10             $36.05 DCLAN128366.1
 
SCHEDULE B "Monthly Price Factors" Month     On-Peak             Off-Peak January     1.1865             0.6746 February     1.1865             0.6746 March     0.9492             0.6133 April     0.9492             0.6133 May       1.4238             0.7052 June       1.6611             0.7359 July     2.1357             0.7666 August       2.1357             0.7666 September     1.6611             0.7359 October     0.9492             0.6133 November     0.9492             0.6133 December     1.1865             0.6746 DCLAN128366.1
 
Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Rochester Gas and Electric Corporation ("CUSTOMER"), a New York company with offices located at 89 East Avenue, Rochester, New York 14649 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
WITNESSETH:
WITNESSETH:
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA"); WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");
("Niagara Mohawk") and New York State Electric & Gas Company ("NYSEG")
WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &
have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA"). NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows: 1. DEFINITIONS.
Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").
In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:
1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves), DCLAN128368.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.4. "Closing" shall have the meaning set forth in the NMP-2 APA. 1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months. 1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A. 1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time. 1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN128368 1
: 1.       DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output. 1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA. 1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time. 1.12. "Effective Date" shall mean the date of the Closing.
1.1.   "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh). 1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour. 1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations.
DCLAN128368.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry.
1.2.   "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council ("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC")
1.3.   "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities.
1.4.   "Closing" shall have the meaning set forth in the NMP-2 APA.
When DCLAN128368.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.5.   "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules. 1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates". 1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.6.   "Contract Year Base Price" shall mean the prices so identified in Schedule A.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
1.7.   "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.8.   "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN128368 1 shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time. 1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17199, as amended and superseded from time to time.DCLAN128368.1 4-1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero. 1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m., prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO. 1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m. inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO. 2. CONDITION PRECEDENT.
1.9.     "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.
It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
1.11.   "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.
: 4. INSTALLED CAPACITY.
1.12. "Effective Date" shall mean the date of the Closing.
4.1. Sale of Installed Capacity.
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).
PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period. 4.2. Performance.
1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.
PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the DCLAN 128368.1 Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests. 5. ENERGY. 5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh. 5.2. Performance.
1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council
Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When DCLAN128368.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy. 5.3. Scheduling.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.
CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below. 5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement.
1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".
PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.DCLAN128368.1 5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
5.3.3. Mitigation.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party. 5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point. 5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point. 5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income), shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output. 5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.
1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17199, as amended and superseded from time to time.
DCLAN128368.1                                   4-
 
1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.
1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,
prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.
1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.
inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.
: 2.       CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
: 3.       TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
: 4.     INSTALLED CAPACITY.
4.1. Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.
4.2. Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the DCLAN 128368.1 Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.
: 5.     ENERGY.
5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.
5.2. Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.
5.3. Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.
5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.
DCLAN128368.1 5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.
5.4.     Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.
5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.
5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income),
shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.
5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN128368.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN128368.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii)the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 8. BILLINGS AND PAYMENTS.
: 8.     BILLINGS AND PAYMENTS.
8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5 th) day of the calendar month in which the invoice is rendered.
8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5 th) day of the calendar month in which the invoice is rendered. In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.
In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day. 8.2. Overdue Payments.
8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s) (such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement.
8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)
CUSTOMER hereby acknowledges DCLAN128368.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement. CUSTOMER hereby acknowledges DCLAN128368.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
: 9. DEFAULT, TERMINATION AND LIABILITY.
: 9.     DEFAULT, TERMINATION AND LIABILITY.
9.1. Breach, Cure and Default.
9.1. Breach, Cure and Default.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law. 9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii) where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN128368.1 breach cannot be cured within any commercially reasonable period of time. 9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof. 9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.
No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights. 9.2. Termination.
9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii)where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN128368.1 breach cannot be cured within any commercially reasonable period of time.
If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii)terminate this Agreement in accordance with Section 9.2 hereof.
9.3. Additional Remedies.
9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.
A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
9.2. Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.3.     Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN128368.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
9.4.     Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.5.     Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN128368.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
10.1. Party Representatives.
10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.
The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access. 10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows: If to PRODUCER:
10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:
Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile:
If to PRODUCER:
(410) 234-5323 DCLAN128368.1 If to CUSTOMER: Rochester Gas and Electric Corporation 89 East Avenue Rochester, NY 14649 Title: Senior Vice President Attn.: Paul C. Wilkens Phone: (716) 724-8076 Facsimile:
Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 DCLAN128368.1 If to CUSTOMER:
(716) 724-8285 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery.
Rochester Gas and Electric Corporation 89 East Avenue Rochester, NY 14649 Title: Senior Vice President Attn.: Paul C. Wilkens Phone: (716) 724-8076 Facsimile: (716) 724-8285 If given by electronic transmission (including telex, facsimile or telecopy),
PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent. 11. BUSINESS RELATIONSHIP.
notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.
Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage.
: 11.     BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
: 12.     CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
: 12. CONFIDENTIALITY.
: 13.     GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
: 13. GOVERNMENT REGULATION.
This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of DCLAN 128368.1 negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of DCLAN 128368.1 negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York. 15. DISPUTE RESOLUTION.
: 15.     DISPUTE RESOLUTION.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.
The arbitration process shall be concluded not later than six (6) months after the date that it is initiated.
The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.
Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
: 16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes.
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and DCLAN 128368.1 therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party. 16. WAIVER AND AMENDMENT.
: 18.     ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement.
: 19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may S DCLAN128368.1 assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity , and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS.
This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and DCLAN 128368.1 therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
: 18. ENTIRE AGREEMENT.
This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter. 19. ASSIGNMENT.
CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment);
and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may S DCLAN128368.1 assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity , and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
: 20. SIGNATORS' AUTHORITY/COUNTERPARTS.
: 20. SIGNATORS' AUTHORITY/COUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.
The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party. This Agreement may be executed in two or more counterparts, each of which shall be an original.
This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
: 21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
: 21. NO DEDICATION OF FACILITIES.
: 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.
No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity. 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.DCLAN128368.1 DL.EC.-122-00 TUE 12:4C AM ECONO LODGE FAX NO. 3153431222
DCLAN128368.1 DL.EC.-122-00 TUE   12:4C AM   ECONO LODGE FAX NO. 3153431222                       P.05/13 C                                                ~3~'~;~~   i~~/S.       :4,/N"" 48417SE208 P INWITNrI                  4e           '5eg1ally bound.     the Pamiag havo C)        executed this Agreement by the undersigned duly authorized represenlativeg date first staled above.
~3~'~;~~ i~~/S. :4,/N"" 48417SE208 P IN WITNrI 4e '5eg1ally bound. the Pamiag havo executed this Agreement by the undersigned duly authorized represenlativeg aS Of the date first staled above. PRODUCER CUSTOMER By:y Na~me: 1 Name: Title- P4gE.SA0S-Title DATE: December 11, 2000 SOOC 62r': OT06 I= *ON 516r,3 1: 3 1066 Sld'flOd i33f0dc C)P. 05/13 61T :00 000Z/ZT I
aS Of the PRODUCER                                     CUSTOMER By:y Na~me: 1                                     Name:
~:~: ~>i2?M K TXO! FACP Lý~IN WITNESS WHEREOF, and intending to be legally bound, the Parties have executed this Agreement by the undersigned duly authorized representatives as of the date first stated above.PRODUCER By: CUSTOMER Name: &,'1/6 Name: Title: Title: DATE: December 11, 2000.'e .i" ýý. .1 o .: 'i2PV SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLAN128368.1 SCHEDULE B "Monthly Price Factors" DCLAN128368.1 Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 Execution Copy PRODUCER -CUSTOMER NMP -2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Central Hudson Gas & Electric Corporation
Title-   P4gE.SA0S-Title DATE:   December 11, 2000 SOOC   62r':
("CUSTOMER"), a New York company with offices located at 284 South Avenue, Poughkeepsie, NY 12601 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
516r,3   1: 3 1066 OT06    I= *ON Sld'flOd i33f0dc         61T :00     000Z/ZTI
 
.'ei". ýý.o. . 1 :'i2PV    KTXO!
                          ~:~:   FACP
                              ~>i2?M     Lý~
INWITNESS WHEREOF, and intending to be legally bound, the Parties have executed this Agreement by the undersigned duly authorized representatives as of the date first stated above.
PRODUCER                                     CUSTOMER By:
Name:                                        Name:       Pb*d &,'1/6 Title:                                       Title:
DATE: December 11, 2000
 
SCHEDULE A "Contract Year Base Prices" Contract         Price Year       ($ per MWh) 1           $35.70 2           $35.32 3           $33.95 4           $33.60 5           $33.56 6           $33.23 7           $33.91 8           $34.61 9           $35.32 10           $36.05 DCLAN128368.1
 
SCHEDULE B "Monthly Price Factors" Month     On-Peak             Off-Peak January       1.1865             0.6746 February     1.1865             0.6746 March       0.9492             0.6133 April     0.9492             0.6133 May       1.4238             0.7052 June       1.6611             0.7359 July       2.1357             0.7666 August       2.1357             0.7666 September     1.6611             0.7359 October     0.9492             0.6133 November     0.9492             0.6133 December     1.1865             0.6746 DCLAN128368.1
 
Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Central Hudson Gas & Electric Corporation ("CUSTOMER"), a New York company with offices located at 284 South Avenue, Poughkeepsie, NY 12601 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
WITNESSETH:
WITNESSETH:
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA"); WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");
("Niagara Mohawk") and New York State Electric & Gas Company ("NYSEG")
WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &
have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA"). NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows: 1. DEFINITIONS.
Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").
In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:
1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 1 0-minute non-synchronized reserves and 30-minute reserves),'I-, DCLAN01:128367.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.4. "Closing" shall have the meaning set forth in the NMP-2 APA. 1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months. 1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A. 1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time. 1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN01:128367.1 shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output. 1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA. 1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time. 1.12. "Effective Date" shall mean the date of the Closing.
: 1.       DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh). 1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour. 1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations.
1.1.   "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),
Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry.
'I-, DCLAN01:128367.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council ("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC")
1.2.     "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities.
1.3.     "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
When DCLAN01:128367.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.4.     "Closing" shall have the meaning set forth in the NMP-2 APA.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules. 1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates". 1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.5.     "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.
1.6.     "Contract Year Base Price" shall mean the prices so identified in Schedule A.
1.7.     "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.
1.8.     "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN01:128367.1 shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.
1.9.     "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.
1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
1.11.     "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.
1.12. "Effective Date" shall mean the date of the Closing.
1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).
1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.
1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council
("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When DCLAN01:128367.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.
1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.
1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".
1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time. 1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time. 1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.DC LANO1:128367.1 4-1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero. 1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m., prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO. 1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m. inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO. 2. CONDITION PRECEDENT.
1.21.     "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.
1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.
DC LANO1:128367.1                                   4-
 
1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.
1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,
prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.
1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.
inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.
: 2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
: 4. INSTALLED CAPACITY.
: 4. INSTALLED CAPACITY.
4.1. Sale of Installed Capacity.
4.1.       Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) nine percent (9%) times (ii)ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.
PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period. 4.2. Performance.
4.2.       Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the Energy generated by the plant. In no event, however, will PRODUCER be DCLAN01:128367.1 required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.
PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the Energy generated by the plant. In no event, however, will PRODUCER be DCLAN01:128367.1 required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests. 5. ENERGY. 5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh. 5.2. Performance.
: 5. ENERGY.
Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
5.1.       Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.
If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy. 5.3. Scheduling.
5.2.       Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.
CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below. 5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement.
Iffor any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.
PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.DC_LAN01:128367.1 5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
5.3.     Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.
5.3.3. Mitigation.
5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.
The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party. 5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point. 5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point. 5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income), shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output. 5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings.
DC_LAN01:128367.1
Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
 
5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.
5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.
5.4.     Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.
5.5.     Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.
5.6.     Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income),
shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.
5.7.     Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN01:128367.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN01:128367.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii)the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
: 8. BILLINGS AND PAYMENTS.
: 8. BILLINGS AND PAYMENTS.
8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5 th) day of the calendar month in which the invoice is rendered.
8.1.     Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5th) day of the calendar month in which the invoice is rendered. In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.
In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day. 8.2. Overdue Payments.
8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.
8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s) (such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement.
8.4.     Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)
CUSTOMER hereby acknowledges DCLAN01:128367.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement. CUSTOMER hereby acknowledges DCLAN01:128367.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.
: 9. DEFAULT, TERMINATION AND LIABILITY.
: 9. DEFAULT, TERMINATION AND LIABILITY.
9.1. Breach, Cure and Default.
9.1. Breach, Cure and Default.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law. 9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii) where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN01:128367.1 breach cannot be cured within any commercially reasonable period of time. 9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof. 9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception.
9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.
No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights. 9.2. Termination.
9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii) where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN01:128367.1 breach cannot be cured within any commercially reasonable period of time.
If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof.
9.3. Additional Remedies.
9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.
A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
9.2. Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.
9.3. Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.
9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.
9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN01:128367.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
9.5.     Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN01:128367.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
: 10. CONTRACT ADMINISTRATION AND OPERATION.
10.1. Party Representatives.
10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement.
PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.
The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access. 10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows: If to PRODUCER:
10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:
Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile:
Ifto PRODUCER:
(410) 234-5323 DCLAN01:128367.1 If to CUSTOMER: Central Hudson Gas & Electric Corporation 284 South Avenue Poughkeepsie, NY 12601 Title: Senior Vice President Attn.: Arthur R. Upright Phone: (845) 486-5247 Facsimile:
Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 DCLAN01:128367.1 If to CUSTOMER:
(845) 486-5782 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery.
Central Hudson Gas & Electric Corporation 284 South Avenue Poughkeepsie, NY 12601 Title: Senior Vice President Attn.: Arthur R. Upright Phone: (845) 486-5247 Facsimile: (845) 486-5782 If given by electronic transmission (including telex, facsimile or telecopy),
PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent. 11. BUSINESS RELATIONSHIP.
notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.
Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage.
: 11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
: 12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
: 12. CONFIDENTIALITY.
: 13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
: 13. GOVERNMENT REGULATION.
This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION.
: 14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of DC_LAN01:128367.1 negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of DC_LAN01:128367.1 negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York. 15. DISPUTE RESOLUTION.
: 15. DISPUTE RESOLUTION.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement.
15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.
The arbitration process shall be concluded not later than six (6) months after the date that it is initiated.
The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.
Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.
: 16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes.
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and DC LAN01 :128367.1 therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party. 16. WAIVER AND AMENDMENT.
: 18. ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement.
: 19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may DCLAN01:128367.1 assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity , and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
: 17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS.
This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and DC LAN01 :128367.1 therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
: 18. ENTIRE AGREEMENT.
This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter. 19. ASSIGNMENT.
CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment);
and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may-14-DCLAN01:128367.1 assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity , and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.
: 20. SIGNATORS' AUTHORITY/COUNTERPARTS.
: 20. SIGNATORS' AUTHORITY/COUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.
The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party. This Agreement may be executed in two or more counterparts, each of which shall be an original.
This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.
: 21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
: 21. NO DEDICATION OF FACILITIES.
: 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.
No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity. 22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.DCLAN01:128367.1 P.03 S14 486 5782 TO 812022936330 DEC 11 2000 22:37 FR EXECUTIVE IN WITNESS WHEREOF, and Intending to be legally bound, the Parties have executed this Agreement by the undersigned duly authorized representatives as of the date first stated above. PRODUCER CUSTOMER By:By Name: Name: Title: Titse: ~ VDATE: December 11,2000 DEC-'1 2-00 TUE 12:43 AMl 3ROY & ~ C FAX NO, 3153431222 P 30 ECONO LODGE X1fON) 12. 11.'00 IS9:151ST 115-VIO 486'i79S214' P 2 IN W~TNE83 WHEREOF, and In~eiding to~ be )~aly bound. the Pertiee have executed this Agreemrent by the undersignod duty authorized repreaentaetives as of the date first stated above.PRODUCER Title- ~e~7 CUSTOMER By: Narn.: rthle I (Th 0 SIW):Q -:,310a 6006 ?77-*ON DATE- December ll..2000 P. 03/03 000Z/Zl/Z' SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10$36.05 DCLAN01:128367.1 SCHEDULE B "Monthly Price Factors" N-__, DCLAN01:128367.1 Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 Exhibit 9 REVENUE SHARING AGREEMENT FOR NMP 2 BETWEEN NMPC AND NMP LLC Execution Copy PRODUCER -CUSTOMER NMP-2 REVENUE SHARING AGREEMENT This Revenue Sharing Agreement
DCLAN01:128367.1 S14 486   5782 TO 812022936330             P.03 DEC 11 2000 22:37 FR EXECUTIVE IN WITNESS WHEREOF, and Intending to be legally bound, the Parties have executed this Agreement by the undersigned duly authorized representatives as of the date first stated above.
("Agreement"), dated as of the 11 th day of December, 2000, by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18tb Floor, Baltimore, MD 21201, and Niagara Mohawk Power Corporation
PRODUCER                                     CUSTOMER By:By Name:                                       Name:
("CUSTOMER"), a New York corporation with offices located at 300 Erie Boulevard West, Syracuse, NY 13202 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
Title:                                       Titse:     ~     VŽ DATE: December 11,2000
 
FAX NO, 3153431222                    P.
P 03/03 30 DEC-' 12-00 TUE 12:43 AMl     ECONO LODGE 3ROY &       ~ C                                 X1fON) 12. 11.'00 IS9:151ST 115-VIO 486'i79S214' P 2 I                  IN W~TNE83 WHEREOF, and In~eiding to~ be )~aly bound. the Pertiee have executed this Agreemrent by the undersignod duty authorized repreaentaetives as of the date first stated above.
PRODUCER                                         CUSTOMER By:
Narn.:
Title-   ~e~7                                   rthle DATE- December ll..2000 (Th 0
SIW):Q -:,310a                   000Z/Zl/Z' 6006     ?77-*ON
 
SCHEDULE A "Contract Year Base Prices" Contract           Price Year       ($ per MWh) 1             $35.70 2             $35.32 3             $33.95 4             $33.60 5             $33.56 6             $33.23 7             $33.91 8             $34.61 9           $35.32 10           $36.05 DCLAN01:128367.1
 
SCHEDULE B "Monthly Price Factors" Month     On-Peak             Off-Peak January     1.1865             0.6746 February     1.1865             0.6746 March     0.9492             0.6133 April     0.9492             0.6133 May       1.4238             0.7052 June       1.6611             0.7359 July     2.1357             0.7666 August     2.1357             0.7666 September     1.6611             0.7359 October     0.9492             0.6133 November     0.9492             0.6133 December     1.1865             0.6746 N-__, DCLAN01:128367.1
 
Exhibit 9 REVENUE SHARING AGREEMENT FOR NMP 2 BETWEEN NMPC AND NMP LLC
 
Execution Copy PRODUCER - CUSTOMER NMP-2 REVENUE SHARING AGREEMENT This Revenue Sharing Agreement ("Agreement"), dated as of the 11 th day of December, 2000, by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18tb Floor, Baltimore, MD 21201, and Niagara Mohawk Power Corporation ("CUSTOMER"),
a New York corporation with offices located at 300 Erie Boulevard West, Syracuse, NY 13202 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").
WITNESSETH:
WITNESSETH:
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA"); WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have entered into a Power Purchase Agreement of even date herewith pursuant to which PRODUCER has agreed to sell and CUSTOMER has agreed to purchase certain energy and installed capacity from NMP-2 (the "NMP-2 PPA"); and NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows: 1. DEFINITIONS.
WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");
1.1 "Contract Month" shall mean each consecutive calendar month starting with the calendar month in which the Effective Date occurs and ending with (but including) the calendar month during which the Agreement expires.
WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have entered into a Power Purchase Agreement of even date herewith pursuant to which PRODUCER has agreed to sell and CUSTOMER has agreed to purchase certain energy and installed capacity from NMP-2 (the "NMP-2 PPA"); and NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:
1.2 "Contract Quarter' shall mean each consecutive period comprised of three (3) consecutive Contract Months beginning with the Contract Month in which the Effective Date occurs. If the Agreement does not expire on the last day of a Contract Month, then the Contract Month during which the Agreement expires shall constitute a Contract Quarter.
: 1. DEFINITIONS.
1.3 "Effective Date" shall mean the first full day after the expiration or termination of the NMP-2 PPA pursuant to its terms.DCLAN01:128295 1
1.1   "Contract Month" shall mean each consecutive calendar month starting with the calendar month in which the Effective Date occurs and ending with (but including) the calendar month during which the Agreement expires.
1.4 "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh). 1.5 "Floor Price" shall mean the price as defined in Section 4.3 of this Agreement.
1.2   "Contract Quarter' shall mean each consecutive period comprised of three (3) consecutive Contract Months beginning with the Contract Month in which the Effective Date occurs.               If the Agreement does not expire on the last day of a Contract Month, then the Contract Month during which the Agreement expires shall constitute a Contract Quarter.
1.6 "Interest Rate" shall mean, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates". 1.7 "Market Capacity Price" shall mean the price as defined in Section 4.3 of this Agreement.
1.3   "Effective Date" shall mean the first full day after the expiration or termination of the NMP-2 PPA pursuant to its terms.
1.8 "Market Energy Price" shall mean the price as defined in Section 4.3 of this Agreement.
DCLAN01:128295                               1
1.9 "Market Price" shall mean the price as defined in Section 4.3 of this Agreement.
 
1.10 "Monthly Price Adjustment" shall mean the value as calculated under Section 4.3 of this Agreement.
1.4   "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).
1.11 "Monthly "New York Independent System Operator" or "NYISO" shall mean the organization formed in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.5   "Floor Price" shall mean the price as defined in Section 4.3 of this Agreement.
1.6   "Interest Rate" shall mean, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journalunder "Money Rates".
1.7   "Market Capacity Price" shall mean the price as defined in Section 4.3 of this Agreement.
1.8   "Market Energy Price" shall mean the price as defined in Section 4.3 of this Agreement.
1.9   "Market Price" shall mean the price as defined in Section 4.3 of this Agreement.
1.10 "Monthly Price Adjustment" shall mean the value as calculated under Section 4.3 of this Agreement.
1.11 "Monthly "New York Independent System Operator" or "NYISO" shall mean the organization formed in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.
1.12 "Negative Price Adjustment Amount" shall mean the value as calculated under Section 4.4 of this Agreement.
1.12 "Negative Price Adjustment Amount" shall mean the value as calculated under Section 4.4 of this Agreement.
1.13 "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero. 1.14 "Positive Price Adjustment Amount" shall mean the value as calculated under Section 4.5(i) of this Agreement.
1.13 "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.
1.15 "Price Adjustment" shall mean the value as calculated under Section 4.3 of this Agreement.
1.14 "Positive Price Adjustment Amount" shall mean the value as calculated under Section 4.5(i) of this Agreement.
DCLAN01:128295 2
1.15 "Price Adjustment" shall mean the value as calculated under Section 4.3 of this Agreement.
: 2. CONDITION PRECEDENT.
DCLAN01:128295                             2
It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
: 2.     CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00, midnight, prevailing Eastern Time as applicable on the day that is exactly ten (10) years after the Effective Date. 4. PURCHASE PRICE ADJUSTMENT.
: 3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00, midnight, prevailing Eastern Time as applicable on the day that is exactly ten (10) years after the Effective Date.
4.1 As adjustments to the purchase price for NMP-2, PRODUCER shall pay to CUSTOMER the Price Adjustments as calculated in this Section 4. An example of the calculation and application of the Price Adjustment described in this Section 4 is set forth in Appendix A hereto. 4.2 A Price Adjustment shall be calculated for each Contract Quarter starting with the Effective Date through the Term of this Agreement.
: 4. PURCHASE PRICE ADJUSTMENT.
4.3 The Price Adjustment for each Contract Quarter shall be equal to the sum of the Monthly Price Adjustments for each Contract Month in the Contract Quarter. The Monthly Price- Adjustment for each Contract Month shall be calculated as follows: Monthly Price Adjustment  
4.1     As adjustments to the purchase price for NMP-2, PRODUCER shall pay to CUSTOMER the Price Adjustments as calculated in this Section 4. An example of the calculation and application of the Price Adjustment described in this Section 4 is set forth in Appendix A hereto.
=[Market Price -(Floor Price x Monthly Base Price Factor)] x forty-one percent (41%) x (the sum of the Net Electric Output during each hour of the Contract Month up to a maximum total amount of Energy in each such hour of 1,148 MWh).where: Market Price = Market Energy Price =S-DCLAN01:128295 Market Energy Price + Market Capacity Price for the respective Contract Month. The average over all hours of the respective Contract Month of the day-ahead locational based market price ("LBMP") paid to producers for energy at the NMP-2 Delivery Point (defined in the NMP-2 Interconnection Agreement) specified and published by the NYISO or, if the NYISO does not specify or publish an LBMP for the NMP-2 Delivery Point, 3 the LBMP specified and published by the NYISO for the region in which the NMP-2 Delivery Point is located. In the event the NYISO ceases to provide such prices, the Parties shall in good faith undertake commercially reasonable efforts to agree on a substitute indices to reflect the value of Energy located at the NMP-2 Delivery Point. Failure of the parties to agree to such alternative indices shall constitute a dispute to be resolved in accordance with the provisions of Section 5.4.Market Capacity Price = The market value of the installed capacity of NMP-2, expressed in $/MWh. The measure will reflect the weighted average of the market prices paid to producers for installed capacity at the NMP-2 Delivery Point as published by the NYISO in its installed capacity auctions.
4.2     A Price Adjustment shall be calculated for each Contract Quarter starting with the Effective Date through the Term of this Agreement.
Where Market Capacity Prices are posted in units of $/kW-month, such conversion to units of $/MWh shall be the result of the posted price in $/kW-month, multiplied by 41.66666, divided-by-the -number of days in the month. (For example, if the posted price was $1.50 /kW-month for a month which is 30 days long, the $/MWh would be $2.0833/MWh
4.3     The Price Adjustment for each Contract Quarter shall be equal to the sum of the Monthly Price Adjustments for each Contract Month in the Contract Quarter. The Monthly Price- Adjustment for each Contract Month shall be calculated as follows:
[($1.50 x 41.6666)+30].
Monthly Price Adjustment =         [Market Price - (Floor Price x Monthly Base Price Factor)] x forty-one percent (41%) x (the sum of the Net Electric Output during each hour of the Contract Month up to a maximum total amount of Energy in each such hour of 1,148 MWh).
Note 41.6666 = 10OOkW/MWh  
where:
-24 hours per day). In the event NYISO ceases to provide such prices, the Parties shall in good faith undertake commercially reasonable efforts to agree on a substitute indices to reflect the value of installed capacity located at the NMP-2 Delivery Point. Failure of the parties to agree to such alternative indices shall constitute a dispute to be resolved in accordance with the provisions of Section 5.4. Floor Price = Set forth in Schedule 1. Monthly Base Price Factor = Set forth in Schedule 2. 4.4 If the Price Adjustment for a Contract Quarter is negative, PRODUCER shall accrue eighty percent (80%) of that negative DCLAN01:128295 4
Market Price =       Market Energy Price + Market Capacity Price for the respective Contract Month.
Market Energy Price =      The average over all hours of the respective Contract Month of the day-ahead locational based market price ("LBMP") paid to producers for energy at the NMP-2 Delivery Point (defined in the NMP-2 Interconnection Agreement) specified and published by the NYISO or, if the NYISO does not specify or publish an LBMP for the NMP-2 Delivery Point, S-DCLAN01:128295                                    3
 
the LBMP specified and published by the NYISO for the region in which the NMP-2 Delivery Point is located. In the event the NYISO ceases to provide such prices, the Parties shall in good faith undertake commercially reasonable efforts to agree on a substitute indices to reflect the value of Energy located at the NMP-2 Delivery Point. Failure of the parties to agree to such alternative indices shall constitute a dispute to be resolved in accordance with the provisions of Section 5.4.
Market Capacity Price = The market value of the installed capacity of NMP-2, expressed in $/MWh. The measure will reflect the weighted average of the market prices paid to producers for installed capacity at the NMP-2 Delivery Point as published by the NYISO in its installed capacity auctions.
Where Market Capacity Prices are posted in units of $/kW-month, such conversion to units of $/MWh shall be the result of the posted price in $/kW-month, multiplied by 41.66666, divided-by-the -number of days in the month.
(For example, if the posted price was $1.50
                                /kW-month for a month which is 30 days long, the $/MWh would be $2.0833/MWh [($1.50 x 41.6666)+30]. Note 41.6666 = 10OOkW/MWh
                                  -24 hours per day). In the event NYISO ceases to provide such prices, the Parties shall in good       faith   undertake     commercially reasonable efforts to agree on a substitute indices to reflect the value of installed capacity located at the NMP-2 Delivery Point. Failure of the parties to agree to such alternative indices shall constitute a dispute to be resolved in accordance with the provisions of Section 5.4.
Floor Price =     Set forth in Schedule 1.
Monthly Base Price Factor =     Set forth in Schedule 2.
4.4 If the Price Adjustment for a Contract Quarter is negative, PRODUCER shall accrue eighty percent (80%) of that negative DCLAN01:128295                       4
 
Price Adjustment (that 80% defined herein as the "Negative Price Adjustment Amount") to be credited against Positive Price Adjustment Amounts, if any, for subsequent Contract Quarters, thereby reducing such Positive Price Adjustment Amounts until the full amount of such Negative Price Adjustment Amounts has been so credited.
Price Adjustment (that 80% defined herein as the "Negative Price Adjustment Amount") to be credited against Positive Price Adjustment Amounts, if any, for subsequent Contract Quarters, thereby reducing such Positive Price Adjustment Amounts until the full amount of such Negative Price Adjustment Amounts has been so credited.
4.5 If the Price Adjustment for a Contract Quarter is positive, PRODUCER shall: (i) take 80% of that positive Price Adjustment (the 80% defined hlerein as the "Positive Price Adjustment Amount");
4.5 If the Price Adjustment for a Contract Quarter is positive, PRODUCER shall:
then (ii) credit against and reduce the Positive Price Adjustment Amount by the sum of any Negative Price Adjustment Amounts for prior Contract Quarters, to the extent that any such Negative Price Adjustment Amounts have not been credited against Positive Price Adjustment Amounts; then (iii) make payment of the Purchase Price Adjustment in an amount equal to any Positive Price Adjustment Amount remaining after crediting any Negative Price Adjustment Amounts as described in (ii) above. 4.6 Negative Price Adjustment Amounts calculated with respect to a Contract Quarter shall only be credited against Positive Price Adjustment Amounts, if any, for subsequent Contract Quarters.
(i)   take 80% of that positive Price Adjustment (the 80% defined hlerein as the "Positive Price Adjustment Amount"); then (ii)   credit against and reduce the Positive Price Adjustment Amount by the sum of any Negative Price Adjustment Amounts for prior Contract Quarters, to the extent that any such Negative Price Adjustment Amounts have not been credited against Positive Price Adjustment Amounts; then (iii) make payment of the Purchase Price Adjustment in an amount equal to any Positive Price Adjustment Amount remaining after crediting any Negative Price Adjustment Amounts as described in (ii) above.
4.6 Negative Price Adjustment Amounts calculated with respect to a Contract Quarter shall only be credited against Positive Price Adjustment Amounts, if any, for subsequent Contract Quarters.
CUSTOMER shall have no obligation to make any payment to PRODUCER in respect of any Negative Price Adjustment Amount, whether by way of refund of payments made by PRODUCER in respect of Positive Price Adjustment Amounts for prior Contract Quarters, payment for Negative Price Adjustment Amounts which are not followed by Positive Price Adjustment Amounts against which such Negative Price Adjustment Amounts may be credited, or otherwise.
CUSTOMER shall have no obligation to make any payment to PRODUCER in respect of any Negative Price Adjustment Amount, whether by way of refund of payments made by PRODUCER in respect of Positive Price Adjustment Amounts for prior Contract Quarters, payment for Negative Price Adjustment Amounts which are not followed by Positive Price Adjustment Amounts against which such Negative Price Adjustment Amounts may be credited, or otherwise.
4.7 Extraordinary Inflation:
4.7 Extraordinary Inflation: On each anniversary of the date hereof, if the United States Gross Domestic Product Implicit Price Deflator (as reported quarterly by the United States Department of Commerce; the "GDP Deflator") for the most recently reported quarterly period has increased by more than 5% from the same quarterly period in the prior year, the Floor Price for each subsequent Contract Year set forth in Schedule 1 hereof, shall be increased by the percentage amount such increase is greater than 5%. For example, if on the first anniversary date hereof the GDP DCLAN01:128295                         5
On each anniversary of the date hereof, if the United States Gross Domestic Product Implicit Price Deflator (as reported quarterly by the United States Department of Commerce; the "GDP Deflator")
 
for the most recently reported quarterly period has increased by more than 5% from the same quarterly period in the prior year, the Floor Price for each subsequent Contract Year set forth in Schedule 1 hereof, shall be increased by the percentage amount such increase is greater than 5%. For example, if on the first anniversary date hereof the GDP DCLAN01:128295 5
Deflator for the most recent quarter equals 112, and the GDP Deflator for the same quarter reported in the previous year was 105, each Contract Year in Schedule 1 hereof shall be increased by 1.66%.
Deflator for the most recent quarter equals 112, and the GDP Deflator for the same quarter reported in the previous year was 105, each Contract Year in Schedule 1 hereof shall be increased by 1.66%. 5. PAYMENT AND DISPUTES.
: 5. PAYMENT AND DISPUTES.
5.1 Statements and Payments.
5.1 Statements and Payments.             PRODUCER shall prepare a statement ("Statement") for each Contract Quarter showing the Price Adjustment Payment due to CUSTOMER, if any, for such Contract Quarter and the calculation of the Price Adjustment Amount for such Contract Quarter (whether positive or negative).
PRODUCER shall prepare a statement
("Statement")
for each Contract Quarter showing the Price Adjustment Payment due to CUSTOMER, if any, for such Contract Quarter and the calculation of the Price Adjustment Amount for such Contract Quarter (whether positive or negative).
PRODUCER will provide to CUSTOMER such Statement on or before the tenth (10th) Business Day after the final Contract Month of each Contract Quarter. PRODUCER shall pay the amount due, if any, by wire transfer of immediately available funds to an account specified by CUSTOMER not later than the fifth (5 th) Business Day after the date on which PRODUCER provides the Statement.
PRODUCER will provide to CUSTOMER such Statement on or before the tenth (10th) Business Day after the final Contract Month of each Contract Quarter. PRODUCER shall pay the amount due, if any, by wire transfer of immediately available funds to an account specified by CUSTOMER not later than the fifth (5 th) Business Day after the date on which PRODUCER provides the Statement.
5.2 Overdue Payments.
5.2 Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including the due date to, but excluding, the date of payment.
Overdue payments shall accrue interest at the Interest Rate from, and including the due date to, but excluding, the date of payment.
5.3 Billing Disputes. If CUSTOMER, in good faith, disputes any Statement or part thereof, CUSTOMER shall notify PRODUCER in writing of the basis for the dispute within ten (10) business days of receipt of the Statement. If it is subsequently determined by arbitration or agreed that an adjustment to the Statement is appropriate, PRODUCER will prepare and issue a revised Statement not later than ten (10) Business Days after it is determined that an adjustment is appropriate.               Any Price Adjustment   Payment   due to CUSTOMER     pursuant to the revised Statement shall be paid by wire transfer of immediately available funds to the account specified by CUSTOMER not later than three (3) Business Days from the date the revised Statement is issued and shall include interest accrued at the Interest Rate until the date paid.
5.3 Billing Disputes.
5.4   Dispute Resolution.
If CUSTOMER, in good faith, disputes any Statement or part thereof, CUSTOMER shall notify PRODUCER in writing of the basis for the dispute within ten (10) business days of receipt of the Statement.
If it is subsequently determined by arbitration or agreed that an adjustment to the Statement is appropriate, PRODUCER will prepare and issue a revised Statement not later than ten (10) Business Days after it is determined that an adjustment is appropriate.
Any Price Adjustment Payment due to CUSTOMER pursuant to the revised Statement shall be paid by wire transfer of immediately available funds to the account specified by CUSTOMER not later than three (3) Business Days from the date the revised Statement is issued and shall include interest accrued at the Interest Rate until the date paid. 5.4 Dispute Resolution.
5.4.1 All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
5.4.1 All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.
DCLAN01:128295 6
DCLAN01:128295                         6
5.4.2 Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement.
 
The arbitration process shall be concluded not later than six (6) months after the date that it is initiated.
5.4.2 Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid.
The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise.
                      -Judgment may-be entered upon the arbitration opinion and award in any court having jurisdiction.
Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. -Judgment may-be entered upon the arbitration opinion and award in any court having jurisdiction.
5.4.3 The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.
5.4.3 The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes.
: 6. CONTRACT ADMINISTRATION AND OPERATION.
Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party. 6. CONTRACT ADMINISTRATION AND OPERATION.
6.1 Company Representative. PRODUCER and CUSTOMER shall each appoint a representative (collectively, the "Company Representatives"), who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
6.1 Company Representative.
6.2   Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER. PRODUCER and CUSTOMER, on a DCLAN01:128295                           7
PRODUCER and CUSTOMER shall each appoint a representative (collectively, the "Company Representatives"), who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.
 
6.2 Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities.
confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.
All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.
6.3 Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:
PRODUCER and CUSTOMER, on a DCLAN01:128295 7
If-to- PRODUCER:
confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement.
Constellation Nuclear, LLC 39 West Lexington Street 18 th Floor Baltimore, MD 21201 Attn: Robert E. Denton Title: President Phone: (410) 234-6149 Facsimile: (410) 234-5323 If to CUSTOMER:
The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access. 6.3 Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows: If-to- PRODUCER:
Niagara Mohawk Power Corporation 300 Erie Boulevard West Attn: Clement E. Nadeau Title: Vice President Phone: (315) 428-6492 Facsimile: (315) 428-5722 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s) including its Company representative and the address to which notices are to be sent.
Constellation Nuclear, LLC 39 West Lexington Street 1 8 th Floor Baltimore, MD 21201 Attn: Robert E. Denton Title: President Phone: (410) 234-6149 Facsimile:
DCLAN01:128295                         8
(410) 234-5323 If to CUSTOMER:
: 7.     CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken pursuant hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret or similar protection from such authority and promptly notify the other Party.
Niagara Mohawk Power Corporation 300 Erie Boulevard West Attn: Clement E. Nadeau Title: Vice President Phone: (315) 428-6492 Facsimile:
: 8.     GOVERNMENT REGULATION. This Agreement and all rights and obligations the Parties hereunder are subject to all applicable federal, state and local of laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
(315) 428-5722 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery.
Further, if at any time following receipt of any regulatory approvals required for the initial effectiveness of the NMP-2-Sale, the New York Public Service Commission, any legislature, any agency, or any court takes any action relating to or affecting this Agreement, the payments required to be made hereunder, or CUSTOMER's reflection in rates thereof, neither CUSTOMER or PRODUCER shall have any right to seek damages from the other, to discontinue performance under this Agreement, or to modify or seek to modify any of the terms and conditions in any way as a consequence of such action.
PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s) including its Company representative and the address to which notices are to be sent.DCLAN01:128295 8
: 9.     GOVERNING LAW/CONTRACT CONSTRUCTION.                       This Agreement
: 7. CONFIDENTIALITY.
.shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof.
Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken pursuant hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret or similar protection from such authority and promptly notify the other Party. 8. GOVERNMENT REGULATION.
: 10. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.
: 11. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
Further, if at any time following receipt of any regulatory approvals required for the initial effectiveness of the NMP-2-Sale, the New York Public Service Commission, any legislature, any agency, or any court takes any action relating to or affecting this Agreement, the payments required to be made hereunder, or CUSTOMER's reflection in rates thereof, neither CUSTOMER or PRODUCER shall have any right to seek damages from the other, to discontinue performance under this Agreement, or to modify or seek to modify any of the terms and conditions in any way as a consequence of such action. 9. GOVERNING LAW/CONTRACT CONSTRUCTION.
: 12. ENTIRE AGREEMENT. This Agreement contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
This Agreement .shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. 10. WAIVER AND AMENDMENT.
: 13. ASSIGNMENT. CUSTOMER shall have right to assign the Agreement in whole or in part without consent of PRODUCER. Partial assignments are subject to a 50-MW minimum. PRODUCER shall not have the right to assign this Agreement DCLAN01:128295                                 9
Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement.
 
The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
DEC-12-00 TUE 22:41 AM                   ECONO LODGE                                 FAX NO. 3153431222                              P. 09/13 C,:-i -Oa     06:390m       Fr-D-ILLVAN 6 CIW.LL                                                         7-484   P.005/007   F-408 withoUt CUSTOMER'S pn" w,. .....                     .....       vide mt PRODUCER or ,is permitted assignee. without           CUSTOMER's     coPsent.       may     essign. trarwfer. piedge or otherwiSe dispose of (aDso~utety or as security) its rights             and   Interests hereunder to an Afliate (an "Assignee Entity") of       PRODUCER       at least     68%     of the equity socurites of which are owned by PRODUCER* r vo...de4,                             , (I) any     rTinority owner of the Assignee Entity shall be that entity contemplaetd           to   become       an   equ/ty owner of PRODUCERs affiliated     merchant   energy group   as set   formt   in   that   certain   press release issued by Constellation Energy Group on October 23. 2000.                   (ii) no minority   owner of the Assignee or oper-bonal     rights   or role with respect to Entity may have any oontrol or management shall relieve or dIscdarge the Assignee Entity , and (ili no such assignmntt or shall be made if It would PRODUCER from any of its obligations hereunder impde.      interfere with er delay the reasonably be expected to prevent or materially                                   Increas the costs of the transactions contemplated by this         Agreement         or   materially transactions contemplated by this Agreement.
: 11. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS.
certify
This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
: 14. SIGNATORS' AUTHORTTYICOUNTERPARTS- The undersigned of their respecive    Parttes.
: 12. ENTIRE AGREEMENT.
that they are authorized to execLte tis Agreement on behalf                           elch of which shall be This Agreement may be executed in two or more counterparts.
This Agreement contains the complete and exclusive agreement and understanding between the Parties as to its subject matter. 13. ASSIGNMENT.
ini making      proof    of the  cornents  of this Agreement an origiraL, It snal'itiL vv ,,.,
CUSTOMER shall have right to assign the Agreement in whole or in part without consent of PRODUCER.
to produce or account for       more than   one     such   counterpart.
Partial assignments are subject to a 50-MW minimum. PRODUCER shall not have the right to assign this Agreement DCLAN01:128295 9
or
DEC-12-00 TUE 22:41 AM ECONO LODGE C,:-i -Oa 06:390m Fr-D-ILLVAN 6 CIW.LL FAX NO. 3153431222 7-484 P.005/007 F-408 CUSTOMER Name: Title-Name: Ti*tle:-DCLANOI:128295 10 O£2926ZZOZTB
: 15. NO DEDICATION OF FACLITIlES. No underaking by PRODUCER
*- SI1!70d ID3108 I1:00 003'ZcI/Z.
                                                    -- - 6-reement shell be deemed
61:00 ooBe-/Z-.:-
                                                  - -..'
P. 09/13 Th withoUt CUSTOMER'S pn" w,. ..... ..... vide mt PRODUCER or ,is permitted assignee.
to constitute ije
without CUSTOMER's coPsent. may essign. trarwfer.
              ,CUSTOMER '::^ -
piedge or otherwiSe dispose of (aDso~utety or as security) its rights and Interests hereunder to an Afliate (an "Assignee Entity") of PRODUCER at least 68% of the equity socurites of which are owned by PRODUCER*
dedication of     any portion of NMP-2   to trie public, to CUSTOMER. or to any other eralty.
r vo...de4, , (I) any rTinority owner of the Assignee Entity shall be that entity contemplaetd to become an equ/ty owner of PRODUCERs affiliated merchant energy group as set formt in that certain press release issued by Constellation Energy Group on October 23. 2000. (ii) no minority owner of the Assignee Entity may have any oontrol or management or oper-bonal rights or role with respect to the Assignee Entity , and (ili no such assignmntt shall relieve or dIscdarge PRODUCER from any of its obligations hereunder or shall be made if It would reasonably be expected to prevent or materially impde. interfere with er delay the transactions contemplated by this Agreement or materially Increas the costs of the transactions contemplated by this Agreement.
the Parties have IN wrr4NES WHEREOF, and intending to be legally bound, authoriZed    representatives-    as of the executed this Agreement by the und;ersigned duly date flrsV stated above.
: 14. SIGNATORS' AUTHORTTYICOUNTERPARTS-The undersigned certify that they are authorized to execLte tis Agreement on behalf of their respecive Parttes.
CUSTOMER Name:
This Agreement may be executed in two or more counterparts.
Name:
elch of which shall be an origiraL, It snal'itiL vv ,,., ini making proof of the cornents of this Agreement to produce or account for more than one such counterpart.
Title-Ti*tle:-
: 15. NO DEDICATION OF FACLITIlES.
DCLANOI:128295                                      10 Th 6r,,f
No underaking by PRODUCER or ,CUSTOMER
    .,    2.,r.,"*5',
'::^ ---..' ---1 -- 6-reement shell be deemed to constitute ije dedication of any portion of NMP-2 to trie public, to CUSTOMER.
                  '.
or to any other eralty. IN wrr4NES WHEREOF, and intending to be legally bound, the Parties have executed this Agreement by the und;ersigned duly authoriZed representatives-as of the date flrsV stated above.6r,,f ., 2., r.," '. *5',
I1:00      003'ZcI/Z.
DEC-11-00 MON 21:40 P. 05/38 P.2 MCC 1 , 'PO % 9 .t& r HINGTO. without CUSTOMERSt prior wrfttn conmrnt, DMW that PRODUCER Or Its prmitte assignee, without CUSTOMER's.
O£2926ZZOZTB *-SI1!70d ID3108                          61:00        ooBe-/Z-.:-
conser.t may assign, tran.er, pledge of otherwise dispose of (absolutely or as security)
 
Its rights and tinterests hereunder to an Affiliate (an "Assignee of PRODUCER at least 68% of the equity securities of which are "owned by PRODUCER;
P.2P.05/38 DEC-11-00 MON 21:40 MCC  1 , 'PO    % i'j.W:* 9 .r t& HINGTO.
.!Md, however (I) any minority owner of the Assignee Entity shall be that entity conteplate to become an equIty owner or PRODUCER'S afflhlated merchant energy group as set forth In thut oertaln press release issued by Constellation Energy Group on October 23, 2000, 01) no minority owner of the Assignee Entity may have any control or management or operational .ghts or role with reapecd to the Assignee Entity , and (111) no such assignment shall relierve or discGhrge PRODUCER from any of its obligations hereunder or shall be made If it would reasonably be expected to prevent or materially impede. interfere with or delay the transactions contemplated by this Agreement or materially Increase the Gost of the transactions contemplated by this Agreement
DMW that PRODUCER Or Its otherwise    prmitte without CUSTOMERSt prior wrfttn conmrnt, may            assign,   tran.er,  pledge  of assignee, without CUSTOMER's.           conser.t rights and tinterests hereunder to an Affiliate (an dispose of (absolutely or as security) Itsleast "Assignee Entit'*) of PRODUCER at                  68% of the equity securities of which are "owned by PRODUCER; .                !Md, however (I) any minority owner of the Assignee Entity shall be that entity conteplate to become anoertaln        equIty owner or PRODUCER'S press release issued by afflhlated merchant energy group as set forth In thut                      owner of the Assignee Constellation Energy Group on October 23, 2000, 01) no minority.ghts        or role with reapecd to Entity may have any control or management or operational shall relierve or discGhrge the Assignee Entity , and (111)no such assignment shall be made If it would PRODUCER from any of its obligations hereunder or                                with or delay the reasonably be expected to prevent or materially impede. interfere                the Gost    of the transactions contemplated by this Agreement or materially Increase transactions contemplated by this Agreement certify
: 14. SIGNATORS' AUTHORITYICOUNTERPART,.
: 14.      SIGNATORS' AUTHORITYICOUNTERPART,. The undersigned on behalf    of their respective  Parties.
The undersigned certify thaT they are authorized to cxewWut this Agreement on behalf of their respective Parties.
thaT they are authorized to cxewWut this Agreement                         each of which shall be This Agreement may be executed in two or more counterparts,                    of this Aome0 *nt an original. It ahall not be ncoooory in      maling proof    of the contents to produce or account for more than one such cnunterparL NO DEDICATION OF FACILITIES. No undertaking by to               PRODUCER or
This Agreement may be executed in two or more counterparts, each of which shall be an original.
: 15.                                                                        constitute the be deemed CUSTOMER under any provision of this Agreement shall                      or to any  other entity.
It ahall not be ncoooory in maling proof of the contents of this Aome0 *nt to produce or account for more than one such cnunterparL
dedication of any portion of NMP-2 to the public, to CUSTOMER, IN Wf*NE*S        HEREOF, a-nd-inteding-to be legally bound, the Parties ofhave as the oxoouted this Agreement by the underionArl drily withoriz*d representativeS date first stated above.
: 15. NO DEDICATION OF FACILITIES.
PRODUCER                                                             CUSTOMER Name_                                               Name:         L4&LIAM F. ED1WA1PS Title:                                 .Title:         9._.         pAoMi      CFO DCLAN01:128295                                 10
No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity. IN HEREOF, a-nd-inteding-to be legally bound, the Parties have oxoouted this Agreement by the underionArl drily representativeS as of the date first stated above. PRODUCER CUSTOMER Name_ Name: L4&LIAM F. ED1WA1PS Title: .Title: 9._. pA oMi C FO 10 DCLAN01:128295 SCHEDULE 1 Floor Price Contract Year 1 Floor Price 4 ($/MWh)2 3 0.75 41.57 42.40 4 5 6 7 43.25 44.11 44.99 4 8 9 10 5.89 46.81 47.75 48.70 SCHEDULE 2 Monthly Base Price Factor For every year of the Term: BASE PRICE MONTH FACTOR January 0.9176 February 0.9192 March 0.7729 April 0.7707 May 1.0461 June 1.1687 July 1.3861 August 1.4450 September 1.1275 October 0.7801 November 0.7707 December 0.8954 DCLAN01:128295 11 Exhibit 10A [PROPRIETARY]
 
FORM OF MASTER DEMAND NOTE Dated: Effective:
SCHEDULE 1 Floor Price Contract Year   1       2      3        4      5      6    7      8    9    10 Floor Price     4 0.75   41.57   42.40     43.25   44.11   44.99 4 5.89 46.81 47.75 48.70
Each of the undersigned (each a "Party", collectively the "Parties")
($/MWh)
anticipate entering into one or more loans with each other from time to time as either a borrower or a lender. Any such loans between any of the Parties will be governed by this Master Demand Note, and the grid attached hereto and made a part hereof (the "Grid"). At any time that a Party desires to lend money to, or borrow money from, another Party the Chief Financial Officer of Constellation Energy Group, Inc. and his staff is authorized to endorse on the Grid the date of each loan, the principal amount thereof, the interest rate and the identity of the Party that is the borrower and the Party that is the lender. All notations on the Grid shall be binding on the Parties, absent manifest error. For value received, each Party that is a borrower promises to pay to the order of each Party that is a lender the principal borrowed as evidenced on the Grid in accordance with the terms hereof, together with accrued interest on any and all principal amounts remaining unpaid hereunder from the date of such loan until payment in full, at a rate per annum noted on the Grid until such principal amount shall have become due and payable; and at the rate of 2% over the grid rate on any overdue principal and (to the extent permitted by applicable law) on any overdue interest, from the date on which payment is due until the obligation of the borrower with respect to the payment thereof shall be discharged.
SCHEDULE 2 Monthly Base Price Factor For every year of the Term:
Interest hereunder shall be calculated on the basis of a three hundred sixty (360) day year counting the actual number of days elapsed.
BASE PRICE MONTH           FACTOR January             0.9176 February           0.9192 March               0.7729 April               0.7707 May                 1.0461 June               1.1687 July               1.3861 August             1.4450 September           1.1275 October             0.7801 November           0.7707 December           0.8954 DCLAN01:128295                           11
The borrower promises to pay the lender the outstanding principal amount of this Note together with all accrued but unpaid interest in one installment within 24 hours of lender's demand. All of the principal may be prepaid by borrower at any time, together with all accrued interest thereon to the date of payment, without penalty with five (5) days prior written notice. All principal and interest hereunder are payable in lawful money of the United States of America at the address of the lender shown beneath its signature.
 
Exhibit 10A [PROPRIETARY]
FORM OF MASTER DEMAND NOTE Dated:
Effective:
Each of the undersigned (each a "Party", collectively the "Parties") anticipate entering into one or more loans with each other from time to time as either a borrower or a lender. Any such loans between any of the Parties will be governed by this Master Demand Note, and the grid attached hereto and made a part hereof (the "Grid"). At any time that a Party desires to lend money to, or borrow money from, another Party the Chief Financial Officer of Constellation Energy Group, Inc. and his staff is authorized to endorse on the Grid the date of each loan, the principal amount thereof, the interest rate and the identity of the Party that is the borrower and the Party that is the lender. All notations on the Grid shall be binding on the Parties, absent manifest error.
For value received, each Party that is a borrower promises to pay to the order of each Party that is a lender the principal borrowed as evidenced on the Grid in accordance with the terms hereof, together with accrued interest on any and all principal amounts remaining unpaid hereunder from the date of such loan until payment in full, at a rate per annum noted on the Grid until such principal amount shall have become due and payable; and at the rate of 2% over the grid rate on any overdue principal and (to the extent permitted by applicable law) on any overdue interest, from the date on which payment is due until the obligation of the borrower with respect to the payment thereof shall be discharged. Interest hereunder shall be calculated on the basis of a three hundred sixty (360) day year counting the actual number of days elapsed.
The borrower promises to pay the lender the outstanding principal amount of this Note together with all accrued but unpaid interest in one installment within 24 hours of lender's demand. All of the principal may be prepaid by borrower at any time, together with all accrued interest thereon to the date of payment, without penalty with five (5) days prior written notice.
All principal and interest hereunder are payable in lawful money of the United States of America at the address of the lender shown beneath its signature.
No delay or omission on the part of the Lender in exercising any rights hereunder shall operate as a waiver of such right or any other right of such lender, nor shall any delay, omission or waiver on any one occasion be deemed a bar to or waiver of the same or any other right on any future occasion.
No delay or omission on the part of the Lender in exercising any rights hereunder shall operate as a waiver of such right or any other right of such lender, nor shall any delay, omission or waiver on any one occasion be deemed a bar to or waiver of the same or any other right on any future occasion.
The borrower for itself and its respective legal representatives, successors and assigns, hereby expressly waives presentment, demand, protest, notice of protest, presentment for the purpose of accelerating maturity and diligence in collection.
The borrower for itself and its respective legal representatives, successors and assigns, hereby expressly waives presentment, demand, protest, notice of protest, presentment for the purpose of accelerating maturity and diligence in collection.
This Note and all transactions hereunder and/or evidenced herein shall be governed by, construed, and enforced in accordance with the laws of the State of Maryland (without giving effect to its choice of law rules) and shall have the effect of a sealed instrument.
This Note and all transactions hereunder and/or evidenced herein shall be governed by, construed, and enforced in accordance with the laws of the State of Maryland (without giving effect to its choice of law rules) and shall have the effect of a sealed instrument.
IN WITNESS WHEREOF, each Party has caused this Note to be executed by its duly authorized officer, under seal, as of the date first above written.
IN WITNESS WHEREOF, each Party has caused this Note to be executed by its duly authorized officer, under seal, as of the date first above written.
CONSTELLATION ENERGY GROUP, INC. By: Name: Thomas E. Ruszin, Jr. Title: Treasurer Address: 250 West Pratt Street Baltimore, MD 21201 State of Incorporation:
CONSTELLATION ENERGY GROUP, INC.
Maryland (CONSTELLATION ENERGY GROUP, INC. SUBSIDIARY NAME) By: Name: Title: Address: State of Incorporation:
By:
Name:     Thomas E. Ruszin, Jr.
Title:   Treasurer Address: 250 West Pratt Street Baltimore, MD 21201 State of Incorporation: Maryland (CONSTELLATION ENERGY GROUP, INC.
SUBSIDIARY NAME)
By:
Name:
Title:
Address:
State of Incorporation:
 
Exhibit 11A [PROPRIETARY]
Exhibit 11A [PROPRIETARY]
FORM OF INTER-COMPANY CREDIT AGREEMENT This Inter-Company Credit Agreement (the "Agreement"), dated [ 1, effective as of[ 1, by and between Constellation Energy Group, Inc. (Parent) and its affiliate, Nine Mile Point Nuclear Station, LLC (NMP LLC). RECITALS A. Nuclear Regulatory Commission
FORM OF INTER-COMPANY CREDIT AGREEMENT This Inter-Company Credit Agreement (the "Agreement"), dated [             1, effective as of[     1, by and between Constellation Energy Group, Inc. (Parent) and its affiliate, Nine Mile Point Nuclear Station, LLC (NMP LLC).
("NRC") regulations require the licensee of Nine Mile Point nuclear power reactors (collectively, the "Facilities")
RECITALS A.     Nuclear Regulatory Commission ("NRC") regulations require the licensee of Nine Mile Point nuclear power reactors (collectively, the "Facilities")
to provide financial assurance of its ability to protect public health and safety. B. NMP LLC participates in a cash pool Parent operates for the benefit of all of its subsidiaries.
to provide financial assurance of its ability to protect public health and safety.
The cash pool is intended to provide NMP LLC with the cash necessary to meet its day-to-day cash needs, including its obligation to protect public health and safety. However, if the cash pool, at any time, cannot meet those needs, then Parent has agreed to provide credit to NMP LLC to allow it to meet its obligation to protect public health and safety. The parties, for adequate consideration and intending to be legally bound, hereby agree as follows: ARTICLE I THE ADVANCES Section 1.01. Advances.
B.     NMP LLC participates in a cash pool Parent operates for the benefit of all of its subsidiaries. The cash pool is intended to provide NMP LLC with the cash necessary to meet its day-to-day cash needs, including its obligation to protect public health and safety. However, if the cash pool, at any time, cannot meet those needs, then Parent has agreed to provide credit to NMP LLC to allow it to meet its obligation to protect public health and safety.
During the period from the date of this Agreement to and including the Maturity Date (as defined in Section 1.03), Parent agrees, on the terms and conditions set forth herein, from time-to-time, to extend credit to NMP LLC; provided, however, that the aggregate principal amount of all advances outstanding at any time shall [not exceed $100 million].
The parties, for adequate consideration and intending to be legally bound, hereby agree as follows:
During the term of this Agreement, NMP LLC, at its option and without penalty or premium, may from time to time repay all or any part of the principal amount outstanding as provided in Section 1.06, and may reborrow any amount that has been repaid. Each advance of funds under this Agreement shall be in a minimum amount of [$5 million] and, if greater, shall be in an [integral multiple of $1 million].
ARTICLE I THE ADVANCES Section 1.01. Advances. During the period from the date of this Agreement to and including the Maturity Date (as defined in Section 1.03), Parent agrees, on the terms and conditions set forth herein, from time-to-time, to extend credit to NMP LLC; provided, however, that the aggregate principal amount of all advances outstanding at any time shall [not exceed $100 million]. During the term of this Agreement, NMP LLC, at its option and without penalty or premium, may from time to time repay all or any part of the principal amount outstanding as provided in Section 1.06, and may reborrow any amount that has been repaid. Each advance of funds under this Agreement shall be in a minimum amount of [$5 million] and, if greater, shall be in an [integral multiple of $1 million].
Section 1.02. Request for an Advance. Each request for an advance of funds under this Agreement shall be made not later than noon on the second business day prior to the proposed drawdown by notice from NMP LLC to Parent (pursuant to procedures that may be changed from time to time by mutual agreement) specifying the amount of the advance and a certification that such advance is for the purpose specified in Section 1.07.
Section 1.02. Request for an Advance. Each request for an advance of funds under this Agreement shall be made not later than noon on the second business day prior to the proposed drawdown by notice from NMP LLC to Parent (pursuant to procedures that may be changed from time to time by mutual agreement) specifying the amount of the advance and a certification that such advance is for the purpose specified in Section 1.07.
Section 1.03. The Note. At the time of the first advance, NMP LLC will execute a note in substantially the form attached hereto as Exhibit B-2.1 (the "Note") and deliver it to Parent. Any advance provided by Parent to NMP LLC, and any payments of principal and interest by NMP LLC, shall be noted by Parent on the grid attached to the Note. Such notations shall be conclusive absent manifest error. The Note is payable to the order of Parent at its principal office in Baltimore, Maryland, and matures on the Maturity Date (subject to the terms of Article II hereof). The "Maturity Date" shall mean: (i) the 5th year anniversary date of the date of this Agreement; (ii) such earlier termination date as may occur pursuant to Sections 2.01, or 2.02, or 2.03; (iii) such later date as may be mutually agreed by the parties hereto pursuant to Section 1.09; or (iv) at the date of closing on any transaction in which: (a) the assets (except asset sales in the ordinary course of business) or stock of NMP LLC are sold to an unrelated third party of Parent, or (b) NMP LLC is merged or consolidated into an unrelated third party of Parent whether by operation of law or otherwise.
 
If the Maturity Date is not a business day in Baltimore, Maryland, the next succeeding business day shall be deemed to be the Maturity Date. Section 1.04. Interest.
Section 1.03. The Note. At the time of the first advance, NMP LLC will execute a note in substantially the form attached hereto as Exhibit B-2.1 (the "Note") and deliver it to Parent. Any advance provided by Parent to NMP LLC, and any payments of principal and interest by NMP LLC, shall be noted by Parent on the grid attached to the Note.
Interest on any principal amount outstanding shall accrue daily at such rate, and shall be payable at such times, as established by Parent at the time of an advance. The interest rate applicable to any advance and the time of payment shall be noted on the grid attached to the Note by Parent. Such notations shall be conclusive absent manifest error. Section 1.05. Funding and Repayment.
Such notations shall be conclusive absent manifest error. The Note is payable to the order of Parent at its principal office in Baltimore, Maryland, and matures on the Maturity Date (subject to the terms of Article II hereof). The "Maturity Date" shall mean: (i) the 5th year anniversary date of the date of this Agreement; (ii) such earlier termination date as may occur pursuant to Sections 2.01, or 2.02, or 2.03; (iii) such later date as may be mutually agreed by the parties hereto pursuant to Section 1.09; or (iv) at the date of closing on any transaction in which: (a) the assets (except asset sales in the ordinary course of business) or stock of NMP LLC are sold to an unrelated third party of Parent, or (b) NMP LLC is merged or consolidated into an unrelated third party of Parent whether by operation of law or otherwise. If the Maturity Date is not a business day in Baltimore, Maryland, the next succeeding business day shall be deemed to be the Maturity Date.
Each advance of funds under this Agreement shall be made in U.S. Dollars in immediately available funds on each drawdown date, at such place as Parent and NMP LLC may agree. All repayments and prepayments by NMP LLC of principal and interest, and of all other sums due under the Note or this Agreement shall be made without deduction, setoff, abatement, suspension, deferment, defense or counterclaim, on or before the due date of repayment or payment, and shall be made in U.S. dollars in immediately available funds at the principal office of Parent. Section 1.06. Optional Prepayments.
Section 1.04. Interest. Interest on any principal amount outstanding shall accrue daily at such rate, and shall be payable at such times, as established by Parent at the time of an advance. The interest rate applicable to any advance and the time of payment shall be noted on the grid attached to the Note by Parent. Such notations shall be conclusive absent manifest error.
NMP LLC, at its option, may prepay all or any part of the principal amount outstanding from time to time without penalty or premium, upon at least 2 business days' prior notice (which, if oral, shall be confirmed promptly in writing) to Parent; provided, however, that if the interest rate is LIBOR based, a prepayment penalty may be assessed against NMP LLC. Any prepayment penalty would be established at the time of an advance. Parent, at its option, may waive such notice requirements as to any prepayment.
Section 1.05. Funding and Repayment. Each advance of funds under this Agreement shall be made in U.S. Dollars in immediately available funds on each drawdown date, at such place as Parent and NMP LLC may agree. All repayments and prepayments by NMP LLC of principal and interest, and of all other sums due under the Note or this Agreement shall be made without deduction, setoff, abatement, suspension, deferment, defense or counterclaim, on or before the due date of repayment or payment, and shall be made in U.S. dollars in immediately available funds at the principal office of Parent.
Section 1.07. Use of Proceeds.
Section 1.06. Optional Prepayments. NMP LLC, at its option, may prepay all or any part of the principal amount outstanding from time to time without penalty or premium, upon at least 2 business days' prior notice (which, if oral, shall be confirmed promptly in writing) to Parent; provided, however, that if the interest rate is LIBOR based, a prepayment penalty may be assessed against NMP LLC. Any prepayment penalty would be established at the time of an advance. Parent, at its option, may waive such notice requirements as to any prepayment.
In order to provide financial assurance, any advance may be used by NMP LLC only to meet its expenses and obligations to safely operate and maintain the Facilities, including payments for nuclear property damage insurance and a retrospective premium pursuant to Title 10, Part 140, Section 21 of the Code of Federal Regulations (10 CFR 140.21).
Section 1.07. Use of Proceeds. In order to provide financial assurance, any advance may be used by NMP LLC only to meet its expenses and obligations to safely operate and maintain the Facilities, including payments for nuclear property damage insurance and a retrospective premium pursuant to Title 10, Part 140, Section 21 of the Code of Federal Regulations (10 CFR 140.21).
 
Section 1.08. Commitment Fee. At the time of any advance, Parent will notify NMP LLC of any commitment fee and the method and time of payment. Such commitment fee will only be in an amount necessary to offset Parent's operating expenses regarding the advance.
Section 1.08. Commitment Fee. At the time of any advance, Parent will notify NMP LLC of any commitment fee and the method and time of payment. Such commitment fee will only be in an amount necessary to offset Parent's operating expenses regarding the advance.
Section 1.09. Extension of Maturity Date. This Agreement and the Maturity Date hereunder may be extended for successive periods of two years each upon the mutual agreement of the parties.
Section 1.09. Extension of Maturity Date. This Agreement and the Maturity Date hereunder may be extended for successive periods of two years each upon the mutual agreement of the parties.
ARTICLE II TERMINATION Section 2.01. Termination upon Unenforceability.
ARTICLE II TERMINATION Section 2.01. Termination upon Unenforceability. Parent, at its option, shall have the right to cease making advances under this Agreement, to terminate this Agreement and/or to make the outstanding principal amount and interest thereon and any other sums due under the Note and this Agreement immediately due and payable upon written or oral notice to NMP LLC, but without the requirement of any further or other notice, demand or presentment of the Note for payment, if this Agreement or the Note shall at any time for any reason cease to be in full force and effect or shall be null and void while the Note is outstanding, or the validity or enforceability of this Agreement or the Note shall be contested by any person, or NMP LLC shall deny that it has any further liability or obligation under this Agreement or the Note.
Parent, at its option, shall have the right to cease making advances under this Agreement, to terminate this Agreement and/or to make the outstanding principal amount and interest thereon and any other sums due under the Note and this Agreement immediately due and payable upon written or oral notice to NMP LLC, but without the requirement of any further or other notice, demand or presentment of the Note for payment, if this Agreement or the Note shall at any time for any reason cease to be in full force and effect or shall be null and void while the Note is outstanding, or the validity or enforceability of this Agreement or the Note shall be contested by any person, or NMP LLC shall deny that it has any further liability or obligation under this Agreement or the Note. Section 2.02. Termination Upon Permanent Cessation of Operations or NRC Approval.
Section 2.02. Termination Upon Permanent Cessation of Operations or NRC Approval. Notwithstanding any other provisions in this Agreement or the Note to the contrary, except as provided in Sections 2.01 and 2.03 herein, Parent agrees that it will provide the credit to NMP LLC for the purposes defined in Section 1.07, and in no event shall this Agreement be terminated, nor shall Parent cease to make advances under this Agreement, until the earlier of: (i) such time that NMP LLC has permanently ceased operations at the Facilities; or (ii) the NRC has given written approval for the discontinuance or termination of this Agreement; or (iii) upon the date of closing on any transaction in which (a) the assets (except asset sales in the ordinary course of business) or stock of NMP LLC are sold to an unrelated third party of Parent, or (b) NMP LLC is merged or consolidated into an unrelated third party of Parent whether by operation of law or otherwise.
Notwithstanding any other provisions in this Agreement or the Note to the contrary, except as provided in Sections 2.01 and 2.03 herein, Parent agrees that it will provide the credit to NMP LLC for the purposes defined in Section 1.07, and in no event shall this Agreement be terminated, nor shall Parent cease to make advances under this Agreement, until the earlier of: (i) such time that NMP LLC has permanently ceased operations at the Facilities; or (ii) the NRC has given written approval for the discontinuance or termination of this Agreement; or (iii) upon the date of closing on any transaction in which (a) the assets (except asset sales in the ordinary course of business) or stock of NMP LLC are sold to an unrelated third party of Parent, or (b) NMP LLC is merged or consolidated into an unrelated third party of Parent whether by operation of law or otherwise.
Section 2.03. Substitution of Financial Assurance. Parent can terminate this Agreement upon 45 days written notice to NMP LLC if Parent has procured a substitute loan facility and/or letter of credit for NMP LLC that meets the financial assurance requirements of the NRC to protect the public health and safety. Such substitute loan facility and/or letter of credit shall remain in effect until the earlier of (i) such time that NMP LLC has permanently ceased operations at the Facilities; (ii) the NRC has given written approval of the discontinuance or termination of the substitute loan facility and/or letter of credit; or (iii) if Parent has procured another substitute loan facility and/or letter of credit for NMP LLC that meets the financial assurance requirements of the NRC to protect the public health and safety.
Section 2.03. Substitution of Financial Assurance.
 
Parent can terminate this Agreement upon 45 days written notice to NMP LLC if Parent has procured a substitute loan facility and/or letter of credit for NMP LLC that meets the financial assurance requirements of the NRC to protect the public health and safety. Such substitute loan facility and/or letter of credit shall remain in effect until the earlier of (i) such time that NMP LLC has permanently ceased operations at the Facilities; (ii) the NRC has given written approval of the discontinuance or termination of the substitute loan facility and/or letter of credit; or (iii) if Parent has procured another substitute loan facility and/or letter of credit for NMP LLC that meets the financial assurance requirements of the NRC to protect the public health and safety.
ARTICLE III MISCELLANEOUS Section 3.01. Notices. Any communications between the parties hereto, and notice provided herein to be given, may be given by mailing or otherwise by delivering the same to the Treasurer of Parent and the Treasurer of NMP LLC, at the principal offices of Parent and NMP LLC, respectively, or to such other officers or addresses as either party may in writing hereafter specify.
ARTICLE III MISCELLANEOUS Section 3.01. Notices. Any communications between the parties hereto, and notice provided herein to be given, may be given by mailing or otherwise by delivering the same to the Treasurer of Parent and the Treasurer of NMP LLC, at the principal offices of Parent and NMP LLC, respectively, or to such other officers or addresses as either party may in writing hereafter specify.
Section 3.02. Remedies.
Section 3.02. Remedies. No delay or omission to exercise any right, power or remedy accruing to Parent under this Agreement shall impair any such right, power or remedy, nor shall it be construed to be a waiver of any such right, power or remedy. Any waiver, permit, consent or approval of any kind or character on the part of Parent of any breach or default under this Agreement, must be in writing and shall be effective only to the extent specifically set forth in such writing. All remedies, either under this Agreement or by law or otherwise afforded to Parent, shall be cumulative and not alternative.
No delay or omission to exercise any right, power or remedy accruing to Parent under this Agreement shall impair any such right, power or remedy, nor shall it be construed to be a waiver of any such right, power or remedy. Any waiver, permit, consent or approval of any kind or character on the part of Parent of any breach or default under this Agreement, must be in writing and shall be effective only to the extent specifically set forth in such writing. All remedies, either under this Agreement or by law or otherwise afforded to Parent, shall be cumulative and not alternative.
Section 3.03. Miscellaneous. This Agreement may not be amended unless in writing signed by both parties. This Agreement is governed by Maryland law. This Agreement may not be assigned by either party without the prior written consent of the other party.
Section 3.03. Miscellaneous.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement by their duly authorized officers, as of the date first above written.
This Agreement may not be amended unless in writing signed by both parties. This Agreement is governed by Maryland law. This Agreement may not be assigned by either party without the prior written consent of the other party. IN WITNESS WHEREOF, the parties hereto have executed this Agreement by their duly authorized officers, as of the date first above written.
CONSTELLATION ENERGY GROUP, INC.
CONSTELLATION ENERGY GROUP, INC. By: Name: Title: NINE MILE POINT NUCLEAR STATION, LLC By: Name: Title:
By:
ATTACHMENT FORM OF INTER-COMPANY CREDIT NOTE 1$100 million] (Available Credit) ,2001 Baltimore, Maryland NINE MILE POINT NUCLEAR STATION, LLC, a Delaware limited liability company ("NMP LLC"), for value received and in consideration of the execution and delivery by Constellation Energy Group, Inc., a Maryland corporation
Name:
("Parent")
Title:
of that certain Inter-Company Credit Agreement, effective as of [ ] (the "Agreement"), hereby promises to pay to the order of Parent on the Maturity Date, the principal sum of [$100 million], or so much thereof as may be outstanding hereunder, together with any accrued but unpaid interest.
NINE MILE POINT NUCLEAR STATION, LLC By:
Prior to maturity, interest shall be due and payable by NMP LLC periodically as noted by Parent at the time of any advance and as set forth on the grid attached hereto and made a part hereof. This Note is issued by NMP LLC pursuant to the Agreement, to which reference is made for certain terms and conditions applicable hereto. Capitalized terms used in this Note shall, unless the context otherwise requires, have the same meanings assigned to them in the Agreement.
Name:
Both the principal of this Note and interest hereon are payable in lawful money of the Untied States of America, which will be immediately available on the day when payment shall become due, at the principal office of Parent. Interest shall be paid on overdue principal hereof and to the extent legally enforceable, on overdue interest, at a rate of 11% over] the then current prime lending rate per annum. The outstanding principal amount of this Note shall be increased or decreased upon any increase or decrease in the outstanding aggregate principal amount as provided under the terms of Sections 1.02 and 1.06 of the Agreement; provided, however, that at no time shall the outstanding principal amount of this Note exceed the Available Credit. Upon any such increase or decrease in the principal amount of this Note, Parent shall cause to be shown upon the grid portion of this Note the date and amount of such increase or decrease, as the case may be. All notations by Parent on the grid shall be conclusive absent manifest error. Upon payment in full of the principal of and interest on this Note and all other sums due from NMP LLC to Parent under the terms of this Note and the Agreement at the Maturity Date, this Note shall be canceled and returned to NMP LLC and shall be of no further operation or effect. The obligation of NMP LLC to make the payments required to be made on this Note and under the Agreement and to perform and observe the other agreements on its part contained herein and therein shall be absolute and unconditional and shall not be subject to diminution by setoff, counterclaim, abatement or otherwise.
Title:
 
ATTACHMENT FORM OF INTER-COMPANY CREDIT NOTE 1$100 million] (Available Credit)                                                           ,2001 Baltimore, Maryland NINE MILE POINT NUCLEAR STATION, LLC, a Delaware limited liability company ("NMP LLC"), for value received and in consideration of the execution and delivery by Constellation Energy Group, Inc., a Maryland corporation ("Parent") of that certain Inter-Company Credit Agreement, effective as of [         ] (the "Agreement"),
hereby promises to pay to the order of Parent on the Maturity Date, the principal sum of
[$100 million], or so much thereof as may be outstanding hereunder, together with any accrued but unpaid interest. Prior to maturity, interest shall be due and payable by NMP LLC periodically as noted by Parent at the time of any advance and as set forth on the grid attached hereto and made a part hereof.
This Note is issued by NMP LLC pursuant to the Agreement, to which reference is made for certain terms and conditions applicable hereto. Capitalized terms used in this Note shall, unless the context otherwise requires, have the same meanings assigned to them in the Agreement.
Both the principal of this Note and interest hereon are payable in lawful money of the Untied States of America, which will be immediately available on the day when payment shall become due, at the principal office of Parent. Interest shall be paid on overdue principal hereof and to the extent legally enforceable, on overdue interest, at a rate of 11% over] the then current prime lending rate per annum.
The outstanding principal amount of this Note shall be increased or decreased upon any increase or decrease in the outstanding aggregate principal amount as provided under the terms of Sections 1.02 and 1.06 of the Agreement; provided, however, that at no time shall the outstanding principal amount of this Note exceed the Available Credit. Upon any such increase or decrease in the principal amount of this Note, Parent shall cause to be shown upon the grid portion of this Note the date and amount of such increase or decrease, as the case may be. All notations by Parent on the grid shall be conclusive absent manifest error.
Upon payment in full of the principal of and interest on this Note and all other sums due from NMP LLC to Parent under the terms of this Note and the Agreement at the Maturity Date, this Note shall be canceled and returned to NMP LLC and shall be of no further operation or effect. The obligation of NMP LLC to make the payments required to be made on this Note and under the Agreement and to perform and observe the other agreements on its part contained herein and therein shall be absolute and
 
unconditional and shall not be subject to diminution by setoff, counterclaim, abatement or otherwise.
Upon the occurrence of an event giving rise to a right on the part of Parent to terminate the Agreement as set forth in sections 2.01, 2.02, and 2.03 of the Agreement, the maturity of this Note may be accelerated and the principal of and interest on and any other sums due from NMP LLC to Parent under the terms of this Note may be declared immediately due and payable as provided for in the Agreement.
Upon the occurrence of an event giving rise to a right on the part of Parent to terminate the Agreement as set forth in sections 2.01, 2.02, and 2.03 of the Agreement, the maturity of this Note may be accelerated and the principal of and interest on and any other sums due from NMP LLC to Parent under the terms of this Note may be declared immediately due and payable as provided for in the Agreement.
This Note is issued with the intent that it shall be governed by, and construed in accordance with, the laws of the State of Maryland.
This Note is issued with the intent that it shall be governed by, and construed in accordance with, the laws of the State of Maryland.
IN WITNESS WHEREOF, Nine Mile Point NMP LLC Station, LLC has caused this Note to be duly executed in its name, and its corporate seal to be hereunto affixed and attested, by its duly authorized officer as of , 2001. NINE MILE POINT NUCLEAR STATION, LLC By: Title:
IN WITNESS WHEREOF, Nine Mile Point NMP LLC Station, LLC has caused this Note to be duly executed in its name, and its corporate seal to be hereunto affixed and attested, by its duly authorized officer as of                     , 2001.
INCREASES AND DECREASES IN OUTSTANDING PRINCIPAL AMOUNT OF THIS NOTE INTEREST UNPAID DATE AMOUNT OF RATE AND AMOUNT OF PRINCIPAL ADVANCE TIME OF REPAYMENT BALANCE PAYMENT BALANCE I i I i i +4 4 1 +4 4 i +
NINE MILE POINT NUCLEAR STATION, LLC By:
Exhibit 12 Constellation Energy Group, Inc.'s 1999 Annual Report and 100 Filine for 3 rd Ouarter 2000 0
Title:
Constellation Energy Group at a Glance Constellation Energy Group (NYSE:CEG) is a holding company whose subsidiaries include a group of energy businesses focused mostly on power marketing and merchant generation in North America and the Baltimore Gas and Electric Company (BGE). In 1999, combined revenues totaled $3.8 billion.
 
Here are the Constellation Stars: Constellation Power Source Our integrated domestic merchant energy company provides wholesale customers with solutions to their energy needs. Combining expertise in marketing and risk management with the development, ownership and operation of power plants, Constellation Power Source actively markets power and risk management services throughout North America.
INCREASES AND DECREASES IN OUTSTANDING PRINCIPAL AMOUNT OF THIS NOTE INTEREST                   UNPAID DATE     AMOUNT OF       RATE AND     AMOUNT OF   PRINCIPAL ADVANCE         TIME OF     REPAYMENT   BALANCE PAYMENT                   BALANCE Ii                        I i           i                         +
Constellation Nuclear Group Our nuclear generation and consulting business brings together our experience and expertise in the nuclear industry.
4               4           1           +
Under the Constellation Nuclear umbrella is our newly formed Constellation Nuclear Services, Inc., which provides nuclear consulting services specializing in nuclear power plant license renewal and life-cycle management.
4               4             i           +
In July 2000, upon receipt of all regulatory approvals, the Calvert Cliffs Nuclear Power Plant will be moved under that umbrella as well. Baltimore Gas and Electric Company Our regulated, electric and gas utility serves more than 1.1 million electric customers and more than 584,000 gas customers in Central Maryland.
 
Up until deregulation of the generation part of the business on July 1, 2000, BGE will provide services to these customers as a fully integrated utility with operations as listed below: Generation:
Exhibit 12 Constellation Energy Group, Inc.'s 1999 Annual Report and 100 Filine for 3 rd Ouarter 2000
Owns and operates 10 Maryland-based power stations, including the Calvert Cliffs Nuclear Power Plant; shares ownership of three power plants in Pennsylvania; total generating capacity exceeds 6,200 megawatts.
 
Electricity Delivery:
0 Constellation Energy Group at a                                                                     Glance Constellation Energy Group (NYSE:CEG) is a holding company whose subsidiaries include a group of energy businesses focused mostly on power marketing and merchant generation in North America and the Baltimore Gas and Electric Company (BGE). In 1999, combined revenues totaled $3.8 billion.
Provides electricity throughout a 2,300-square-mile service territory through its transmission and distribution system and is a member of the PJM (Pennsylvania-New Jersey-Maryland)
Here are the Constellation Stars:
Constellation Power Source Our integrated domestic merchant energy company provides wholesale customers with solutions to their energy needs. Combining expertise in marketing and risk management with the development, ownership and operation of power plants, Constellation Power Source actively markets power and risk management services throughout North America.
Constellation Nuclear Group Our nuclear generation and consulting business brings together our experience and expertise in the nuclear industry. Under the Constellation Nuclear umbrella is our newly formed Constellation Nuclear Services, Inc., which provides nuclear consulting services specializing in nuclear power plant license renewal and life-cycle management. In July 2000, upon receipt of all regulatory approvals, the Calvert Cliffs Nuclear Power Plant will be moved under that umbrella as well.
Baltimore Gas and Electric Company Our regulated, electric and gas utility serves more than 1.1 million electric customers and more than 584,000 gas customers in Central Maryland. Up until deregulation of the generation part of the business on July 1, 2000, BGE will provide services to these customers as a fully integrated utility with operations as listed below:
Generation: Owns and operates 10 Maryland-based power stations, including the Calvert Cliffs Nuclear Power Plant; shares ownership of three power plants in Pennsylvania; total generating capacity exceeds 6,200 megawatts.
Electricity Delivery: Provides electricity throughout a 2,300-square-mile service territory through its transmission and distribution system and is a member of the PJM (Pennsylvania-New Jersey-Maryland)
Interconnection, a regional power pool of wholesale market participants and other utility companies.
Interconnection, a regional power pool of wholesale market participants and other utility companies.
Natural Gas Delivery:
Natural Gas Delivery: Delivers natural gas through nearly 5,600 miles of gas main in a 600-square mile service territory.
Delivers natural gas through nearly 5,600 miles of gas main in a 600-square mile service territory.
On July 1, 2000, BGE's generating assets will be transferred to our nonregulated subsidiaries, pending full regulatory approval. BGE will then continue to operate as our electric and natural gas delivery business, serving its Central Maryland customers.
On July 1, 2000, BGE's generating assets will be transferred to our nonregulated subsidiaries, pending full regulatory approval.
BGE Home Products & Services Our local home products, commercial buildings, and gas retail marketing business offers a wide range of home energy products and services and commercial building systems in Maryland, Virginia, and Washington, D.C. After July 2000, BGE HOME will begin marketing electricity, as well as gas, to residential and small                       M commercial customers in Maryland.
BGE will then continue to operate as our electric and natural gas delivery business, serving its Central Maryland customers.
Constellation Energy Source Our energy products and services business provides customized energy solutions exclusively to commercial and industrial customers, primarily in the mid-Atlantic region.
BGE Home Products & Services Our local home products, commercial buildings, and gas retail marketing business offers a wide range of home energy products and services and commercial building systems in Maryland, Virginia, and Washington, D.C. After July 2000, BGE HOME will begin marketing electricity, as well as gas, to residential and small M commercial customers in Maryland.
Committed to Equal Opportunity. As an Equal Opportunity Employer, Constellation Energy Group does not discriminate on the basis of age, color, disability, marital status, national origin, race, religion, sex, sexual orientation, or veteran status. I
Constellation Energy Source Our energy products and services business provides customized energy solutions exclusively to commercial and industrial customers, primarily in the mid-Atlantic region. Committed to Equal Opportunity.
 
As an Equal Opportunity Employer, Constellation Energy Group does not discriminate on the basis of age, color, disability, marital status, national origin, race, religion, sex, sexual orientation, or veteran status. I 4., CM) C 1999 1998 (In millions, except per share $ 2.03 $ 1.93 .45 .27 Total earnings per share before nonrecurring charges included in operations 2.48 2.20 Nonrecurring charges included in operations  
4.,
*Hurricane Floyd (.03) *Write-downs of power projects (.12) *Write-down of financial investment
CM) 1999             1998   %Change (In millions, except per share amo*unts)        {
(.11) *Write-downs of real estate and senior-living investments
Common Stock Data Earnings per share Earnings per share before nonrecurring C          charges included in operations Utility business                                                $     2.03         $   1.93       5.2%
(.04) (.10) *Write-off of energy services investment  
Diversified businesses                                                  .45             .27     66.7 Total earnings per share before nonrecurring charges included in operations                                       2.48             2.20     12.7 Nonrecurring charges included in operations
-(.04) Total earnings per share before extraordinary item 2.18 2.06 Extraordinary loss (.44) Total earnings per share $ 1.74 $ 2.06 Dividends declared per share $ 1.68 $ 1.67 Average shares outstanding 149.6 148.5 Return on average common equity Reported 8.6% 10.5% Excluding nonrecurring charges to earnings 12.3% 11.2% Book value per share-year-end  
          *Hurricane Floyd                                                       (.03)
$ 20.01 $ 19.98 Market price per share-year-end  
          *Write-downs of power projects                                         (.12)
$29.000 $30.875 Financial Data Revenues Electric $ 2,259 $ 2,219 Gas 476 449 Diversified businesses 1,051 690 Total revenues $ 3,786 $ 3,358 Income before extraordinary item $ 326 $ 306 Extraordinary loss, net of income taxes (66) Net income $ 260 $ 306 Total assets Utility construction expenditures (excluding AFC)Investment in utility business Investment in diversified businesses Utility System Data Electric system sales-megawatt-hours Gas system sales-dekatherms
          *Write-down of financial investment                                     (.11)
*Nonrecurring charges to earnings discussed in Note 2 to the Conso$ 9,684 $ 9,275 $ 376 $ 329 $ 2,349 $ 2,467 $ 643 $ 515 29.3 28.8 105.2 100.1 'lidated Financial Statements on pa Common Stock Data Earnings per share Earnings per share before nonrecurring charges included in operations Utility business Diversified businesses Certain prior-year amounts have been reclassified to conforn LtYVV Ij C )C'u r .J -1 C .% Change unts) { 5.2% 66.7 12.7 5.8 (15.5) 0.6 0.7 (18.1) 9.8 0.2 (6.1) 1.8 6.0 52.3 12.7 6.5 (15.0) 4.4 14.3 (4.8) 24.9 1.7 5.1 ge 55.
          *Write-downs of real estate and senior-living investments               (.04)           (.10)
Table of Contents 2 Letter to Our Shareholders 7 Strategy:
          *Write-off of energy services investment                                 -             (.04)
Merchant Energy 12 Strategy:
Total earnings per share before extraordinary item                       2.18             2.06       5.8 Extraordinary loss                                                         (.44)
UtiLity Services 16 Powerful Partnerships 17 Financial Review 39 Forward Looking Statements 74 Directors and Officers 76 Five-Year Statistical Summary 77 Shareholder Information I
Total earnings per share                                           $     1.74         $   2.06     (15.5)
In creating the Constellation Energy Group holding company/&, Now we are putting in place the major pieces of the competitive
Dividends declared per share                                           $     1.68         $   1.67       0.6 Average shares outstanding                                                 149.6             148.5       0.7 Return on average common equity Reported                                                                 8.6%             10.5%     (18.1)
Excluding nonrecurring charges to earnings                             12.3%               11.2%         9.8 Book value per share-year-end                                           $ 20.01           $ 19.98         0.2 Market price per share-year-end                                         $29.000           $30.875         (6.1)
Financial Data Revenues Electric                                                           $ 2,259           $ 2,219         1.8 Gas                                                                       476             449         6.0 Diversified businesses                                                 1,051               690       52.3 Total revenues                                                     $ 3,786           $ 3,358       12.7 Income before extraordinary item                                     $     326         $     306       6.5 Extraordinary loss, net of income taxes                                       (66)
Net income                                                           $     260         $   306     (15.0)
Total assets                                                         $ 9,684            $ 9,275          4.4 Utility construction expenditures (excluding AFC)                     $ 376              $ 329          14.3 Investment in utility business                                       $ 2,349            $ 2,467        (4.8)
Investment in diversified businesses                                 $ 643              $ 515          24.9 Utility System Data Electric system sales-megawatt-hours                                       29.3              28.8        1.7 Gas system sales-dekatherms                                               105.2              100.1        5.1
    *Nonrecurringchargesto earningsdiscussed in Note 2 to the Conso'lidatedFinancialStatements on pa ge 55.
Certainprior-yearamounts have been reclassifiedto conforn   Ij LtYVV     C   )C'u
                                                                                . r   J C- 1 .
 
Table of Contents 2   Letter to Our Shareholders 7   Strategy: Merchant Energy 12 Strategy: UtiLity Services 16 Powerful Partnerships 17 Financial Review 39 Forward Looking Statements 74 Directors and Officers 76 Five-Year Statistical Summary 77 Shareholder Information
 
I 0                        In creatingthe ConstellationEnergy Group holding company/&,
Now we areputting in place the majorpieces of the competitive 0J
.4
-J                                                                    A New Company Is Born The action began in February 1999, when the Maryland General Assembly passed legislation allowing BGE to form


==Dear Investor,==
==Dear Investor,==
Nineteen ninety-nine was arguably the most pivotal year in our company's history. The events of last year have forever changed the energy landscape in Maryland and have set in motion a fundamental transformation of our corporation.
 
In our 1998 annual report, I said we were determined to win in the new energy market and outlined the primary strategies we would pursue to ensure success. They included:
a holding company. Following your approval at the annual Nineteen ninety-nine was arguably the most pivotal year in our shareholders' meeting, the Constellation Energy Group started company's history. The events of last year have forever changed trading on the New York Stock Exchange on May 3.
Be a leader in wholesale power marketing and generation in North America.
the energy landscape in Maryland and have set in motion a fundamental transformation of our corporation.                  Throughout the legislative session, we worked closely with key stakeholders and state lawmakers to develop the legal In our 1998 annual report, I said we were determined to win framework that would shape Maryland's electric market. In in the new energy market and outlined the primary strategies April, Governor Parris Glendening signed comprehensive we would pursue to ensure success. They included:
Provide premier utility services to Maryland while managing the transition to competitive energy markets.
In this report, you
Our employees have always rolled up their sleeves to help where help is needed. In fact, over the past two years they donated more than 8,000 pints of blood to the Red Cross, provided more than 21,000 hours of community service, and raised more than $300,000 for various nonprofit groups in Maryland.
Our employees have always rolled up their sleeves to help where help is needed. In fact, over the past two years they donated more than 8,000 pints of blood to the Red Cross, provided more than 21,000 hours of community service, and raised more than $300,000 for various nonprofit groups in Maryland.
M In 1994, to help children start school ready to learn, we established the Early Childhood Development grant program. As our program continues, we've donated more than $3 million to assist early childhood education programs in Maryland.
M    In 1994, to help children start school ready to learn, we established the Early Childhood Development grant program. As our program continues, we've donated more than $3 million to assist early childhood education programs in Maryland.
I=n To recognize our 1998 recycling efforts, the Environmental Protection Agency in 1999 named BGE a WasteWise Prograrr Champion.
I=n To recognize our 1998 recycling efforts, the Environmental      At our PowerFest '99 celebration,employees opened the Protection Agency in 1999 named BGE a WasteWise Prograrr        gates and hosted a full day of fun and educationalevents Champion. During that period we recycled 562 tons of            for more than 1,500 residents who live near our Brandon paper, 599 tons of aluminum, and 750 tons of utility poles.      Shores/Wagnerpowerplant.
During
 
Financial  Review 18 Selected Financial Data 19 Utility Operating Statistics 20 Management's Discussion and Analysis 39 Forward Looking Statements 40 Report of Management 40 Report of Independent Accountants 41 Consolidated Statements of Income 41 Consolidated Statements of Comprehensive Income 42 Consolidated Balance Sheets 44 ConsoLidated Statements of Cash Flows 45 Consolidated Statements of Common Shareholders' Equity 46 Consolidated Statements of Capitalization 48 Consolidated Statements of Income Taxes 49 Notes to Consolidated Financial Statements
 
I (    Selected              Financial                  Data )
Compounded 1999          1998        1997          1996          1995        Growth (Dollaramounts in millions, except per share amounts)    5-Year    10-Year Summary of Operations Total Revenues                              $3,786.2      $3,358.1    $3,307.6      $3,153.2      $2,934.8    6.35%    6.42%
Operating Expenses                            3,026.3      2,617.0    2,584.0        2,483.7      2,239.1    7.10      6.88 Income From Operations                          759.9        741.1      723.6        669.5        695.7    3.65      4.78 Other Income (Expense)                            7.9          5.7      (52.8)          6.1          8.8 (24.55) (12.75)
Income Before Fixed Charges and Income Taxes                            767.8        746.8      670.8        675.6        704.5    2.84      4
Constellation Energy Group Inc. and Subsidiaries
Constellation Energy Group Inc. and Subsidiaries
"* BGE will be allowed to recover $528 million after-tax of . its potentially stranded investments and utility restructuring, r costs through a competitive transition charge on customers' bills. Residential customers will pay this charge for six years. Commercial and industrial customers will pay in a lump sum or over the four to six-year period, depending on the service option selected by each customer.
 
"* Generation-related regulatory assets and nuclear decommissioning costs will be included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their existing amortization schedules. 
Consolidated                Statements of                    Capitalization 4t December 31,                                                                                        1999                  1998 (In millions)
"* Starting July 1, 2000, BGE will unbundle rates to show separate components for delivery service, transition charges, standard offer service (generation), transmission, universal service, and taxes.  "* On July 1, 2000, BGE will transfer, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy. "* BGE will reduce its generation assets, as discussed in Note 4 on page 59, by $150 million pre-tax during the period July 1, 1999 -June 30, 2000 to mitigate a portion of its potentially stranded investments.
BGE Preference Stock Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.85%, 1991 Series                                                                            $     -             $    7.0 Current portion of redeemable preference stock                                                      -                  (7.0)
"* Universal service will be provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually.
Total redeemable preference stock                                                                  -
We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation for that portion of its business.
Preference stock not subject to mandatory redemption 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003              40.0                40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003            50.0                50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004            40.0                40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005            60.0                60.0 Total preference stock not subject to mandatory redemption                                      190.0                190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 149,556,416 and 149,245,641 shares issued and outstanding at December 31, 1999 and 1998, respectively. (At December 31, 1999 166,893 shares were reserved for the Employee Savings Plan and 12,061,756 shares were reserved for the Shareholder Investment Plan.)                                                                  1,494.0              1,485.1 Retained earnings                                                                                1,499.1              1,490.3 Accumulated other comprehensive (loss) income                                                        (0.1)                6.1 Total common shareholders' equity                                                                2,993.0            2,981.5 Total Capitalization                                                                                $5.758.4           $6.299.6
Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises-Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statements No. 71 and 101 for BGE's electric gener ation business.
                                                                                                                        $6299.6 See Notes to ConsolidatedFinancialStatements.
BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated.
ConstellationEnergy Group Inc. andSubsidiaries
We describe the effect of applying these accounting requirements in Note 4 on page 59. In early December, the Mid-Atlantic Power Supply Association (MAPSA), Trigen-Baltimore Energy Corporation, and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order. MAPSA also filed a motion seeking to delay the implementation of the Restructuring Order pending I a decision on the merits by the court. While we believe that ,,_,the appeals are without merit, no assurances can be given as to the timing or outcome of these cases, and whether the outcome will have a material adverse effect on our and BGE's financial results.
 
Regulation by the Maryland PSC Under traditional rate regulation that will continue for all BGE's businesses except electric generation beginning July 1, 2000, the Maryland PSC determines the rate we can charge our customers.
FQ    Consolidated                    Statements              of     Income Taxes                    )
Our rates consist of a "base rate," a "conservation surcharge," and a "fuel rate." Base Rate The base rate is the rate the Maryland PSC allows us to charge our customers for the cost of providing them service, plus a profit. We have both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is higher. Gas base rates are not affected by seasonal changes.
Year Ended December31,                                                                    1999              1998              1997 (Dollaramounts in millions)
Except as provided under the terms of the electric Restructuring Order discussed on page 24, BGE may ask the Maryland PSC to increase base rates from time to time. The Maryland PSC historically has allowed BGE to increase base rates to recover increased utility plant asset costs, plus a profit, beginning at '--/the time of replacement.
Income Taxes Current                                                                              $182.0              $169.5            $158.1 Deferred Change in tax effect of temporary differences                                        9.6              14.2              (1.0)
Generally, rate increases improve our utility earnings because they allow us to collect more revenue.
Change in income taxes recoverable through future rates                              -                 3.9                8.0 Deferred taxes credited (charged) to shareholders' equity                            3.4              (0.6)              0.4 Deferred taxes charged to expense                                                  13.0                17.5                7.4 Investment tax credit adjustments                                                        (8.6)              (8.8)              (7.5)
However, rate increases are normally granted based on histor ical data and those increases may not always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates. On November 17, 1999, BGE filed an application with the Maryland PSC to increase its gas base rates. We discuss this filing in the gas "Base Rates" section on page 29. Conservation Surcharge The Maryland PSC allows us to include in electric and gas rates a component to recover money spent on conservation programs.
Income taxes per Consolidated Statements of Income                                  $186.4            $178.2            $158.0 Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends)                $526.3            $505.9            $440.8 Statutory federal income tax rate                                                 35%                35%              35%
This component is called a "conservation surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If at the end of the year we have exceeded our allowed profit, we defer (include as a liability on our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest.
Income taxes computed at statutory federal rate                                   184.2              177.1            154.3 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities                15.3                13.6              13.9 Allowance for equity funds used during construction                            (2.2)              (2.2)              (1.9)
As a result of the Restructuring Order, the electric conservation surcharge was frozen at its current level and the associated profit limitation is no longer applicable.
Amortization of deferred investment tax credits                                (8.6)              (8.8)              (7.5)
Fuel Rate Currently, we charge our electric customers separately for the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity.
Tax credits flowed through to income                                            (3.2)              (0.3)              (0.5)
We charge the actual cost of these items to the customer with no profit to us. If these costs go up, the Maryland PSC permits us to increase the fuel rate. If these costs go down, our customers benefit from a reduction in the fuel rate. The fuel rate is mostly impacted by the amount of electricity generated at Calvert Cliffs because the cost of nuclear fuel is cheaper than coal, gas, or oil. Under the Restructuring Order, BGE's electric fuel rate is frozen at its current level until July 1, 2000, at which time the fuel rate clause will be discontinued.
Amortization of deferred tax rate differential on regulated activities          (3.0)              (2.3)              (2.3)
We will continue to defer the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate through June 30, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. We discuss our exposure to market risk further in the "Current Issues" section on page 21. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. At December 31, 1999, the amount to be collected from customers was $60.0 million.
State income taxes                                                              8.9                9.8                6.2 Other                                                                          (5.0)             (8.7)              (4.2)
We charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market based rates incentive mechanism approved by the Maryland PSC. We discuss market based rates in more detail in the "Gas Cost Adjustments" section on page 29 and in Note 1 on page 51. Weather Weather affects the demand for electricity and gas. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather impacts residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. We measure the weather's effect using "degree days." A degree day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees.
Total income taxes                                                              $186.4            $178.2            $158.0 Effective federal income tax rate                                                35.4%              35.2%              35.8%
Cooling degree days result when the average daily actual temperature exceeds the 65 degree baseline.
At December31,                                                                                 1999              1998 (Dollaramounts in millions)
Heating degree days result when the average daily actual temperature is less than the baseline.Constellation Energy Group Inc. and Subsidiaries I I r During the cooling season, hotter weather is measured by more cooling degree days and results in greater demand for electricity to operate cooling systems. During the heating season, colder weather is measured by more heating degree days and results in greater demand for electricity and gas to operate heating systems.
Deferred Income Taxes Deferred tax liabilities Accelerated depreciation                                                            $ 962.7            $1,009.9 Allowance for funds used during construction                                            202.3            204.5 Income taxes recoverable through future rates                                            35.7              88.4 Deferred termination and postemployment costs                                             14.7              32.3 Deferred fuel costs                                                                      25.8                4.5 Leveraged leases                                                                          19.9              22.6 Percentage repair allowance                                                              35.0              36.8 Conservation expenditures                                                                  4.7              18.9 Energy trading activities                                                                71.4              33.4 Deferred electric generation-related regulatory assets                                  100.3 Other                                                                                    187.9            182.6 Total deferred tax liabilities                                                        1,660.4          1,633.9 Deferred tax assets Accrued pension and postemployment benefit costs                                          63.6              54.3 Deferred investment tax credits                                                          38.3              41.3 Capitalized interest and overhead                                                        48.3              46.6 Contributions in aid of construction                                                      49.1              45.6 Nuclear decommissioning liability                                                        25.4              22.8 Energy trading activities                                                                15.1              20.3 Other                                                                                    131.8              93.9 Total deferred tax assets                                                                371.6            324.8 Deferred tax liability, net                                                              $1,288.8          $1,309.1 See Notes to ConsolidatedFinancialStatements.
Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas business revenues to eliminate the effect of abnormal weather patterns.
Certainprior-yearamounts have been reclassifiedto conform with the current year's presentation.
We discuss this further in the "Weather Normalization" section on page 29. We show the number of cooling and heating degree days in 1999 and 1998, the percentage change in the number of degree days from the prior year, and the number of degree days in a "normal" year as represented by the 30-year average in the following table. 30-year 1999 1998 average Cooling degree days 845 915 843 Percentage change from prior year (7.7)% 22.7% Heating degree days 4,585 4,119 4,755 Percentage change from prior year 11.3% (14.6)% Other Factors Other factors, aside from weather, impact the demand for electricity and gas. These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of electric and gas operations.
ConstellationEnergy Group Inc. and Subsidiaries
In those sections, we discuss how these and other factors affected electric and gas sales during 1999 and 1998. The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory.
 
When customer choice for electric generation begins on July 1, 2000, a portion of BGE's electric customers will become delivery service customers only and will purchase their electricity from other sources.
Notes        to Consolidated                  Financial              Statements                    I
Other electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Order. To the extent our electricity generation exceeds or is less than the electricity demanded by customers utilizing our standard offer service, the incremental electricity will be sold or purchased in the wholesale market at prevailing market prices. We discuss our exposure to market risk further in the "Current Issues" section on page 21.Usage per customer refers to all other items impacting customer sales that cannot be measured separately.
    ~Note      1.                                                   The only time we do not use this method is if we can exercise
These factors include the strength of the economy in our service territory.
,--                                                                  control over the operations and policies of the company. If we 4ignificant          Accounting        Policies have control, accounting rules require us to use consolidation.
When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas.Utility Business Earnings Per Share of Common Stock 1999 1998 1997 Electric business $1.81 $1.75 $1.77 Gas business .22 .18 .17 Total utility earnings per share before nonrecurring charge included in operations 2.03 1.93 1.94 Nonrecurring charge included in operations:
Nature of Our Business                                          BGE reports its investment in Safe Harbor Water Power On April 30, 1999, Constellation Energy Group, Inc.              Corporation (Safe Harbor) under the equity method. Safe (Constellation Energy) became the holding company for          Harbor is a producer of hydroelectric power. BGE owns Baltimore Gas and Electric Company (BGE) and BGE's              two-thirds of Safe Harbor's total capital stock, including former subsidiary Constellation Enterprises, Inc. BGE's        one-half of the voting stock, and a two-thirds interest in its outstanding common stock automatically became shares of        retained earnings. This investment is included in "Investments common stock of Constellation Energy. BGE's debt securities,   and Other Assets - Other" in our Consolidated Balance Sheets obligated mandatorily redeemable trust preferred securities,    on page 42.
Hurricane Floyd (see Note 2 on page 55) (.03) -Write-off of merger costs (see Note 2 on page 55) --(.25)lotal utility earnings per share before extraordinary item 2.00 1.93 1.69 Extraordinary loss (see Note 4 on page 59) (.44) -Total utility earnings per share $1.56 $1.93 $1.69 Our 1999 total utility earnings decreased
and preference stock remain securities of BGE.
$53.9 million, or $.37 per share, compared to 1998. Our 1998 total utility earnings increased
Constellation Energy's subsidiaries primarily include BGE      The Cost Method We usually use the cost method if we hold less than a 20%
$36.1 million, or $.24 per share, compared to 1997. We discuss the factors affecting utility earnings below. Electric Operations The discussion below reflects the operations of the electric generation portion of our utility business under current rate regulation by the Maryland PSC. Our electric business will change significantly beginning July 1, 2000 as we enter into retail customer choice for electric generation.
and a group of energy services businesses mostly focused on voting interest in an investment. Under the cost method, we power marketing and merchant generation in North America.
Also, no earlier than July 1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation assets will be transferred, at book value, to nonregulated subsidiaries of Constellation Energy. These assets represent about 6,240 megawatts of generation capacity with a total projected net book value at June 30, 2000 of approximately
report our investment at cost in our Consolidated Balance BGE is an electric and gas public utility company with a        Sheets. The only time we do not use this method is when we service territory that covers the City of Baltimore and all    can exercise significant influence over the operations and or part of ten counties in Central Maryland. We describe        policies of the company. If we have significant influence, our operating segments in Note 2 on page 54.                    accounting rules require us to use the equity method.
$2.4 billion.Constellation Energy Group Inc. and Subsidiaries
References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively.        Regulation of Utility Business Reference in this report to the "utility business" is to BGE. The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the "onsolidation Policy
/
,-,,_Ve use three different accounting methods to report our          same accounting policies and practices used by nonregulated investments in our subsidiaries or other companies:              companies for financial reporting under generally accepted consolidation, the equity method, and the cost method.          accounting principles. However, sometimes the Maryland PSC orders an accounting treatment different from that used by Consolidation                                                    nonregulated companies to determine the rates we charge our We use consolidation when we own a majority of the voting        customers. When this happens, we must defer certain utility stock of the subsidiary. This means the accounts of our          expenses and income in our Consolidated Balance Sheets as subsidiaries are combined with our accounts. We eliminate        regulatory assets and liabilities. We have recorded these regula intercompany balances and transactions when we consolidate      tory assets and liabilities in our Consolidated Balance Sheets in these accounts. Our consolidated financial statements include    accordance with Statement of Financial Accounting Standards the accounts of:                                                (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We summarize and discuss our regulatory assets
Ve estimate that the electric generation portion of our currently represents about one-half of BGE's operating income. We expect BGE to transfer approximately
      "*Constellation Energy,                                        and liabilities further in Note 5 on page 60.
$278 million of tax exempt debt to our nonregulated subsidiaries related to the transferred assets and that BGE will receive approximately
      "*BGE and its subsidiaries,
$1.1 billion in unsecured promissory notes. Repayments of the notes by our nonregulated subsidiaries will be used exclusively to service certain long-term debt of BGE. BGE will also transfer equity associated with the generating assets to nonregulated subsidiaries of Constellation Energy. Given the uncertainties surrounding electric deregulation as discussed in the "Strategy" and "Current Issues" sections on page 21, the results discussed in this section may not be indicative of the future performance of our generation business.
      "*Constellation Enterprises, Inc. and its subsidiaries, and    In 1997, the Financial Accounting Standards Board (FASB)
Also, these results will not be indicative of the future performance of BGE once BGE transfers all of its generation assets to nonregulated subsidiaries of Constellation Energy. The impact of this transfer on BGE's financial results will be material.
      "*Constellation Nuclear Group, LLC and its subsidiaries.       through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulationof the Pricing of Electricity-Issues The Equity Method                                                Related to the Application of FASB Statements No. 71 and We usually use the equity method to report investments,         101. The EITF concluded that a company should cease to corporate joint ventures, partnerships, and affiliated companies apply SFAS No. 71 when either legislation is passed or a (including power projects) where we hold a 20% to 50%            regulatory body issues an order that contains sufficient detail voting interest. Under the equity method, we report:            to determine how the transition plan will affect the deregu lated portion of the business. Additionally, a company would our interest in the entity as an investment in our continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets beginning on page 42, and Consolidated Balance Sheets to the extent that the transition our percenitage share of the earnings from the entity in      plan provides for their recovery.
The total assets, liabilities, and common share holders' equity of Constellation Energy will not change as a result of the transfer.
our Consolidated Statements of Income on page 41.
Electric Revenues "The changes in electric revenues in 1999 and 1998 compared the respective prior year were caused by: 1999 1998 (In millions)
ConstellationEnergy Group Inc. and Subsidiaries I
Electric system sales volumes $41.2 $50.8 Base rates 0.8 (6.6) Fuel rates 3.7 (8.1) Total change in electric revenues from electric system sales 45.7 36.1 Interchange and other sales (8.2) (13.2) Other 2.1 4.6 Total change in electric revenues $39.6 $27.5 Electric System Sales Volumes "Electric system sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. These sales do not include interchange sales and sales to others. The percentage changes in our electric system sales volumes, by type of customer, in 1999 and 1998 compared to the respective prior year were: Residential Commercial Industrial 1999 3.5% 2.6 (5.1)1998 1.5% 3.9 0.2 In 1999, we sold more electricity to residential customers due to higher usage per customer, colder winter weather, and an increased number of customers.
 
This increase was partially offset by milder spring and early summer weather. We sold more electricity to commercial customers mostly due to higher usage per customer, an increased number of customers, and colder winter weather. We sold less electricity to industrial customers mostly because usage by Bethlehem Steel and other industrial customers decreased.
r On November 10, 1999, the Maryland PSC issued a                    We calculate the electric fuel rate using three factors:
Usage decreased at Bethlehem Steel as a result of a shut-down from June to August for an upgrade to their facilities that temporarily reduced their electricity consumption.
Restructuring Order that we believe provided sufficient details      "*the mix of generating plants we used over the last of the transition plan to competition for BGE's electric generation     24 months, business to require BGE to discontinue the application of            "*the latest three-month average fuel cost for each SFAS No. 71 for that portion of its business. Accordingly, generating unit, and in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises- Accounting for the              "*the net cost of purchases and sales of electricity over the Discontinuationof FASB Statement No. 71 and EITF No. 97-4               last 24 months.
This decrease was partially offset by an increase in the number of industrial customers.
for BGE's electric generation business. BGE's transmission          Historically, we were able to change the fuel rate only if the and distribution business continues to meet the requirements        calculated rate was more than 5% above or below the rate in of SFAS No. 71 as that business remains regulated. We              effect. The fuel rate was affected most by the amount of discuss this further in Note 4 on page 58.                          electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than Utility Revenues                                                    coal, gas, or oil. As a result of the Restructuring Order, the fuel We record utility revenues in our Consolidated Statements of       rate is frozen at its current level until July 1, 2000, at which Income when we provide service to customers.                       time it will be discontinued. We will continue to defer the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate through Fuel and Purchased Energy Costs                                    June 30, 2000. After that date, earnings will be affected by We incur costs for:                                                the changes in the cost of fuel and energy. In addition, any
In 1998, we sold more electricity to residential customers mostly because of an increased number of customers, hotter summer weather, and higher usage per customer.
  "*the fuel we use to generate electricity,                          accumulated difference between our actual costs of fuel and
The increase in sales to residential customers was partially offset by milder winter weather. We sold more electricity to commercial customers mostly because of higher usage per customer.
  "*purchases of electricity from others, and                        energy and the amounts collected from customers under the
We sold about the same amount of electricity to industrial customers as we did in 1997. Base Rates In 1999, base rate revenues were about the same compared to 1998. In 1998, base rate revenues decreased compared to 1997. Although we sold more electricity in 1998, our base rate revenues decreased because of lower conservation surcharge revenues.
  "*natural gas that we resell.                                       electric fuel rate clause will be collected from our customers These costs are shown in our Consolidated Statements of Income      over a period to be determined by the Maryland PSC.
Fuel Rates In 1999, fuel rate revenues increased compared to 1998 mostly because we sold more electricity.
as "Electric fuel and purchased energy" and "Gas purchased for      Extended outages at Calvert Cliffs increase fuel costs.
In 1998, fuel rate revenues decreased compared to 1997. Although we sold more electricity, the fuel rate was lower mostly because we were able to use a less-costly mix of generating plants and electricity purchases.
resale." We discuss each of these separately below.                 Any increase in fuel costs, including extended outages at Fuel Used to Generate Electricity and Purchases                    Calvert Cliffs through June 30, 2000, may result in fuel rat,,,
Interchange and Other Sales "Interchange and other sales" are sales in the PJM (Pennsylvania-New Jersey-Maryland)
of ElectricityFrom Others                                          proceedings before the Maryland PSC. In these proceedings, Until July 1, 2000, we will continue to recover our costs of        the Maryland PSC would consider whether any portion of electric fuel under the electric fuel rate clause set              the extra fuel costs should be paid by BGE instead of by the Maryland PSC. Under the electric fuel rate clause, we       passed on to customers.
Interconnection energy market and to others. The PJM is a regional power pool with members that include many wholesale market participants, as well as BGE and other utility companies.
charge our electric customers for:                                  We also report two other items as "Electric fuel and purchased
We sell energy to PJM members and to others after we have satisfied the demand for electricity in our own system.Constellation Energy Group Inc. and Subsidiaries I
  "*the fuel we use to generate electricity (nuclear fuel, coal,      energy" in our Consolidated Statements of Income:
In 1999 and 1998, interchange and other sales revenues decreased compared to the respective prior year mostly because higher demand for system sales reduced the amount of energy we had available for off-system sales. Electric Fuel and Purchased Energy Expenses 1999 1998 1997 (In millions)
gas, or oil), and                                                  "*amortization of nuclear fuel (described under "Utility Plant"
Actual costs $538.0 $514.7 $504.5 Net (deferral) recovery of costs under electric fuel rate clause (see Note 1 on page 50) (70.3) (9.0) 15.2 Total electric fuel and purchased energy expenses $467.7 $505.7 $519.7 Actual Costs In 1999, our actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others were higher compared to 1998 mostly because the price of electricity we bought from others was higher. The price of electricity changes based on market conditions and contract terms. This increase was partially offset by our settlement of a capacity contract with PECO in 1998. In 1998, our actual costs increased compared to 1997 mostly because we settled a capacity contract with PECO. Electric Fuel Rate Clause Under the electric fuel rate clause, we defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss the calculation of the fuel rate and its future discontinuance in Note I on page 50. In 1999 and 1998, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers.
  "*the net cost of purchases and sales of electricity.                   later in this note). We amortize nuclear fuel based on the energy produced over the life of the fuel. We pay quarterly We charge the actual costs of these items to customers with no fees to the Department of Energy for the future disposal of profit to us. To do this, we must keep track of what we spend spent nuclear fuel, and accrue these fees based on the and what we collect from customers under the fuel rate in a            kilowatt-hours of electricity sold. We bill our customers given period. Usually these two amounts are not the same for nuclear fuel as described earlier in this note, and because there is a difference between the time we spend the money and the time we collect it from our customers.                 "*amortization of deferred costs of decommissioning and decontaminating the Department of Energy's uranium Under the electric fuel rate clause, we currently defer (include         enrichment facilities. We discuss these costs further in as an asset or liability in our Consolidated Balance Sheets and          Note 5 on page 61.
The increase in the 1999 deferral reflects higher purchased power costs, especially during record-setting summer peak loads.Electric Operations and Maintenance Expenses In 1999, electric operations and maintenance expenses were about the same compared to 1998. In 1999, operations and maintenance expenses include the costs for system restoration activities related to Hurricane Floyd of $7.5 million and a major winter ice storm. This was offset by lower employee benefit costs in 1999 and a 1998 $6.0 million write-off of contributions to a third party for a low-level radiation waste facility that was never completed.
exclude from our Consolidated Statements of Income) the differ ence between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future.
In 1998, electric operations and maintenance expenses increased
We discuss this and the impact of the Restructuring Order on BGE's electric fuel rate clause further in Note 5 on page 61.
$28.7 million compared to 1997 mostly because of: "* higher nuclear costs, "* higher employee benefit costs, and "* the $6.0 million write-off for the low-level radiation waste facility discussed above. Electric Depreciation and Amortization Expense In 1999, electric depreciation and amortization expense increased
ConstellationEnergy Group Inc. and Subsidiaries
$63.4 million compared to 1998 mostly because of the $75.0 million amortization of the regulatory asset for the reduction in generation plant provided for in the Restructuring Order. This increase was partially offset by lower amortization of deferred electric conservation expenditures due to the write-off of a portion of these expenditures that will not be recovered under the Restructuring Order. We discuss the accounting implications of the Restructuring Order further in Note 4 on page 59. In 1998, electric depreciation and amortization expense increased
 
$26.5 million compared to 1997 mostly because: "* in October 1998, the Maryland PSC authorized us to implement new electric depreciation rates retroactive to January 1, 1998, which increased depreciation expense by approximately
I NaturalGas                                                      DiversifiedBusinesses
$13.9 million, "* we had more electric plant in service (as our level of plant in service changes, the amount of our depreciation and amortization expense changes), and "* we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years.Constellation Energy Group Inc. and Subsidiaries F
      ,Ve charge our gas customers for the natural gas they purchase  Our subsidiary, Constellation Power Source, engages in
4as Operations ,ll BGE industrial and commercial gas customers, and N'-effective November 1, 1999, all BGE residential customers have the option to purchase gas from other suppliers.
"--from us using "gas cost adjustment clauses" set by the             power marketing activities, which include trading electricity, Maryland PSC. These clauses operate similarly to the electric    other energy commodities, and related derivatives (such as fuel rate clause described earlier in this Note. However, the    futures, forwards, options, and swaps). Constellation Power Maryland PSC approved a modification of the gas cost            Source uses the mark-to-market method of accounting for adjustment clauses to provide a market based rates incentive    its trading activities.
We do not expect the impact of customer choice to have a material effect on our, and BGE's, financial results.
mechanism. Under market based rates our actual cost of gas is compared to a market index (a measure of the market          Under the mark-to-market method of accounting, we report:
Gas Revenues The changes in gas revenues in 1999 and 1998 compared to the respective prior year were caused by: 1999 1998 (In millions)
price of gas in a given period). The difference between our        "*commodity positions and derivatives at fair value as actual cost and the market index is shared equally between          "Assets from energy trading activities" or "Liabilities shareholders and customers.                                         from energy trading activities" in our Consolidated Balance Sheets, and Risk Management                                                    "*changes in fair value as components of "Diversified We engage in risk management activities in our gas business          business revenues" in our Consolidated Statements and in our diversified businesses. We separately describe these      of Income.
Gas system sales volumes $ 8.0 $(10.8) Base rates 2.2 14.2 Weather normalization 4.5 10.1 Gas cost adjustments 19.8 (87.6) Total change in gas revenues from gas system sales 34.5 (74.1) Off-system sales (7.9) 1.8 Other 0.5 0.1 Total change in gas revenues $27.1 $(72.2) Gas System Sales Volumes The percentage changes in our gas system sales volumes, v type of customer, in 1999 and 1998 compared to the ,'_.espective prior year were: Residential Commercial Industrial 1999 1998 9.2% (11.6)% 12.7 (9.5) (4.8) (11.3)In 1999, we sold more gas to residential customers mostly for two reasons: colder winter weather and an increased number of customers.
activities for each business below.
This was partially offset by lower usage per customer.
Taxes Gas Business                                                    We summarize our income taxes in our Consolidated We use basis swaps in the winter months (November through        Statements of Income Taxes on page 48. As you read this March) to hedge our price risk associated with natural gas      section, it may be helpful to refer to those statements.
We sold more gas to commercial customers mostly because of higher usage per customer, colder winter weather, and an increased number of customers.
purchases under our market based rates incentive mechanism.
We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers.
We also use fixed-to-floating and floating-to-fixed swaps to    Income Tax Expense hedge our price risk associated with our off-system gas sales. We have two categories of income taxes in our Consolidated The fixed portion represents a specific dollar amount that      Statements of Income-current and deferred. We describe we will pay or receive and the floating portion represents a   each of these below.
Usage by Bethlehem Steel decreased due to a shut-down from June to August for an upgrade to their facilities.
luctuating amount based on a published index that we will
In 1998, we sold less gas to residential and commercial customers mostly for two reasons: milder weather and lower usage per customer.
"ýrýeceive or pay. Our gas business internal guidelines do not       Our current income tax expense consists solely of regular permit the use of swap agreements for any purpose other than    tax less applicable tax credits.
This was partially offset by the increase in the number of customers.
to hedge price risk.                                           Our deferred income tax expense is equal to the changes BGE's off-system gas activities represent trading activities    in the net deferred income tax liability, excluding amounts under EITF 98-10, Accounting for ContractsInvolved in            charged or credited to common shareholders' equity. Our Energy Trading and Risk ManagementActivities. Accordingly,       deferred income tax expense is increased or reduced for we use mark-to-market accounting to record these transactions. changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this Note)
We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers.
We defer, as unrealized gains or losses, the changes in fair    during the year.
Base Rates In 1999, base rate revenues increased compared to 1998 mostly due to the increase in our base rates effective March 1, 1998 as discussed below. In 1998, base rate revenues increased compared to 1997. Although we sold less gas during 1998, our base rate revenues increased mostly because the Maryland PSC authorized an increase in our base rates effective March 1, 1998. The change in rates increased our base rate revenues over the twelve-month period from March 1998 through February 1999 by approximately
value of the swap agreements under the market based rates incentive mechanism and the customers' portion of off-system    Investment Tax Credits gas sales in our Consolidated Balance Sheets. When amounts      We have deferred the investment tax credit associated with are paid under the agreements, we report the payments as gas    our regulated utility business in our Consolidated Balance costs in our Consolidated Statements of Income. We report        Sheets. The investment tax credit is amortized evenly to the changes in fair value for the shareholders' portion of off  income over the life of each property. We reduce income system gas sales in earnings as a component of gas costs.       tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated diversified businesses, other than leveraged leases.
$16 million.
On November 17, 1999, we applied for a $36.3 million annual increase in our gas base rates. The Maryland PSC is currently reviewing our application and is expected to issue an order by June 2000. Weather Normalization Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas revenues to elimi nate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues will be based on weather that is considered "normal" for the month and, therefore, will not be affected by actual weather conditions.
Gas Cost Adjustments We charge our gas customers for the natural gas they purchase from us using gas cost adjustment clauses set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described in the "Electric Fuel Rate Clause" section on page 28. However, under market based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers, and does not significantly impact earnings.
We also discuss this in Note 1 on page 51. Delivery service customers, including Bethlehem Steel, are not subject to the gas cost adjustment clauses because we are not selling gas to them. We charge these customers fees to recover the fixed costs for the transportation service we provide. These fees are the same as the base rate charged for gas sales and are included in gas system sales volumes.
In 1999, gas cost adjustment revenues increased compared to the same period of 1998 mostly because we sold more gas at a higher price. In 1998, gas cost adjustment revenues decreased compared to 1997 mostly because we sold less gas.Constellation Energy Group Inc. and Subsidiaries I
Off-System Sales Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory.
Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments.
The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders).
Changes in off-system sales do not significantly impact earnings.
In 1999, revenues from off-system gas sales decreased compared to 1998 mostly because we sold less gas off-system.
In 1998, revenues from off-system gas sales increased compared to 1997 mostly because we sold more gas off-system.
Gas Purchased For Resale Expenses 1999 1998 1997 (In millions)
Actual costs $221.8 $212.2 $291.6 Net recovery (deferral) of costs under gas adjustment clauses (see Note 1 on page 51) 8.8 (3.6) 0.5 Total gas purchased for resale expenses $230.6 $208.6 $292.1 Actual Costs Actual costs include the cost of gas purchased for resale to our customers and for off-system sales. Actual costs do not include the cost of gas purchased by delivery service customers.
In 1999, actual gas costs increased compared to 1998 mostly because we sold more gas. In 1998, actual gas costs decreased compared to 1997 mostly because we sold less gas. Constellation Energy Group Inc. and Subsidiaries Gas Adjustment Clauses We charge customers for the cost of gas sold through gas adjustment clauses (determined by the Maryland PSC), as discussed under "Gas Cost Adjustments" earlier in this section.
In 1999, actual gas costs were lower than the fuel rate revenues we collected from our customers.
In 1998, actual gas costs were higher than the fuel rate revenues we collected from our customers.
Gas Operations and Maintenance Expenses In 1999, gas operations and maintenance expenses were about the same compared to 1998. In 1998, gas operations and maintenance expenses increased
$3.9 million compared to 1997 mostly because of higher employee benefit costs. Gas Depreciation and Amortization Expense In 1999, gas depreciation and amortization expense was about the same compared to 1998. In 1998, gas depreciation and amortization expense increased
$6.1 million compared to 1997 mostly because: "* we had more gas plant in service, and "* we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years.I Diversified Businesses )ur diversified businesses engage primarily in energy services. list each of our diversified businesses in the "Introduction" section on page 20. We describe our diversified businesses in more detail in our most recent Annual Report on Form 10-K under "Item 1. Business -Diversified Businesses." Diversified Business Earnings Per Share of Common Stock 1999 1998 1997 Energy services Power marketing
$ .23 $ .05 $ Power projects .26 .30 .25 Other (.05) (.01) (.05)Total energy services earnings per share before nonrecurrng charges included in operations Other diversified businesses earnings (losses) per share before nonrecurring charges included in operations Total diversified business earnings per share before nonrecurring charges included in operations Nonrecurring charges included in operations:
s 'Write-downs of power projects (see Note 3 on page 56) Write-off of energy services investment (see Note 2 on page 55) Write-down of financial investment (see Note 3 on page 57) Write-downs of real estate and senior-living investments (see Note 2 on page 55 and Note 3 on page 56) Total earnings per share Our 1999 diversified business earnings or $.05 per share, compared to 1998. 0 business earnings increased
$15.7 milli compared to 1997..44 .34 .20 .01 (.07) .14 Energy Services Power Marketing In 1999, earnings from our power marketing business increased compared to 1998 because of increased transaction margins and volume. In 1998, earnings from our power marketing business increased compared to 1997 because of increased power marketing activi ties in 1998, which was Constellation Power Source's first full year of operations.
Constellation Power Source uses the mark-to-market method of accounting.
We discuss the mark-to-market method of accounting and Constellation Power Source's activities in Note 1 on page 51. As a result of the nature of its business activities, Constellation Power Source's revenue and earnings will fluctuate.
We cannot predict these fluctuations, but the effect on our revenues and earnings could be material.
The primary factors that cause these fluctuations are: "* the number and size of new transactions, "* the magnitude and volatility of changes in commodity prices and interest rates, and Sthe number and size of open commodity and derivative
.45 .27 .34 positions Constellation Power Source holds or sells. Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative positions it holds and sells. These estimates consider various factors including closing exchange and over the-counter price quotations, time value, volatility factors, and 0 credit exposure.
However, it is possible that future market -((~ prices could vary from those used in recording assets and liabilities from power marketing and trading activities, and such variations could be material.
In 1999, assets and (lI) -liabilities from energy trading activities (as shown in our Consolidated Balance Sheets beginning on page 42) increased because of greater business activity during the period.  (.04) (.10) (.31) In March 1998, we formed Orion Power Holdings, Inc. (Orion) .18 $.13 $.03 with Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., to acquire electric generating plants in the United States and Canada. Our energy services businesses own a minority interest in Orion. To date, our energy services increased
$8.1 million, businesses have funded $104 million in equity and have a ur 1998 diversified commitment to contribute an additional
$121 million to Orion. on, or $.10 per share, We discuss factors affecting the earnings of our diversified businesses below.Constellation Energy Group Inc. and Subsidiaries II I Power Projects In 1999, earnings from our power projects business decreased compared to 1998 mostly because of three factors: " In 1999, our power projects business recorded a $14.2 million after-tax, or $.09 per share, write-off of two geothermal power projects.
These write-offs occurred because the expected future cash flows from the projects are less than the investment in the projects.
For the first project, this resulted from the inability to restructure certain project agreements.
For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production. 
"* In 1999, our power projects business recorded a $4.5 million after-tax, or $.03 per share, write-down to reflect the fair value of our investment in a power project as a result of our international exit strategy discussed on page 33.  "* In 1998, our power projects business recorded a $10.4 million after-tax, or $.07 per share, gain for its share of earnings in a partnership.
The partnership recognized a gain on the sale of its ownership interest in a power purchase agreement.
In 1998, earnings from our power projects business increased compared to 1997 mostly because Constellation Power recorded a $10.4 million after-tax gain for its share of earnings in a partnership as discussed above. California Power Purchase Agreements Constellation Power and subsidiaries and Constellation Investments have $301.8 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements.
In 1999, earnings from these projects, excluding any write-offs, were $34.4 million, or $.23 per share, compared to $41.3 million, or $.28 per share in 1998. Under these agreements, the electricity rates change from fixed rates to variable rates beginning in 1996 and continuing through 2000. The projects which already have had rate changes have lower revenues under variable rates than they did under fixed rates. When the remaining projects transition to variable rates, we expect their revenues also to be lower than they are under fixed rates.As of December 31, 1999, ten projects had already transitioned, to variable rates. The remaining four projects will transition between February and December 2000. The projects which transitioned in 1999 contributed
$6.2 million, or $.04 per share to 1999 earnings.
Those changing over in 2000 contributed
$28.0 million, or $.19 per share to 1999 earnings.
We expect earnings from the projects changing over in 2000 to contribute
$17.4 million, or $.12 per share to 2000 earnings.
Our power projects business continues to pursue alternatives for some of these projects including:
"* repowering the projects to reduce operating costs, "* changing fuels to reduce operating costs, "* renegotiating the power purchase agreements to improve the terms, "* restructuring financing to improve existing terms, and "* selling its ownership interests in the projects.
We evaluate the carrying amount of our investment in these projects for impairment using the methodology discussed in Note 1 on page 52. Constellation Power's management uses its best estimates to determine if there has been an impairment of these investments and considers various factors including forward price curves for energy, fuel costs, and operating costs. However, it is possible that future estimates of market prices and project costs could vary from those used in evaluating these assets, and the impact of such variations could be material.
We also describe these projects and the transition process in Note 10 on page 71. International Projects At December 31, 1999, Constellation Power had invested about $254.1 million in 10 power projects in Latin America compared to $269.7 million invested in Latin America in 1998. These investments include: "° the purchase of a 51% interest in a Panamanian electric distribution company for approximately
$90 million in 1998 by an investment group in which subsidiaries of Constellation Power hold an 80% interest, and "* approximately
$98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala.
Constellation Energy Group Inc. and Subsidiaries I
Constellation Energy Group Inc. and Subsidiaries I
Tn December 1999, we decided to exit the international portion )f our power projects business as part of our strategy to improve our competitive position.
 
As a result, we recorded a $4.5 million after-tax write-down of our investment in a generating company in Bolivia to reflect the current fair value of this investment.
F DeferredIncome Tax Assets and Liabilities                        Financial Investments and Trading Securities We must report some of our revenues and expenses differently      In Note 3 on page 57, we summarize the financial investment for our financial statements than we do for income tax purposes. that are in our Consolidated Balance Sheets.
We expect to complete our exit strategy by the end of 2000. We discuss our strategy further in the "Strategy" section on page 21. Other Energy Services In 1999, earnings from our other energy services businesses decreased compared to 1998 mostly because of lower gross margins at our energy products and services business.
The tax effects of the differences in these items are reported SFAS No. 115, Accounting for Certain Investments in Debt as deferred income tax assets or liabilities in our Consolidated and Equity Securities, applies particular requirements to Balance Sheets. We measure the assets and liabilities using some of our investments in debt and equity securities. We income tax rates that are currently in effect.
In 1998, earnings from our other energy services businesses increased compared to 1997 due to improved results from our energy products and services business.
report those investments at fair value, and we use specific A portion of our total deferred income tax liability relates to  identification to determine their cost for computing realized our utility business, but has not been reflected in the rates we gains or losses. We classify these investments as either charge our customers. We refer to this portion of the liability  trading securities or available-for-sale securities, which as "Income taxes recoverable through future rates (net)." We      we describe separately below. We report investments that have recorded that portion of the net liability as a regulatory  are not covered by SFAS No. 115 at their cost.
Earnings would have been higher except we recorded a $5.5 million after-tax, or $.04 per share, write-off of our investment in, and certain of our product inventory from, an automated electric distribution equipment company. We recorded this write-off because of that company's inability to raise capital and sell its products.
asset in our Consolidated Balance Sheets. We discuss this further in Note 5 on page 60.                                    Trading Securities Our diversified businesses classify some of their investments in marketable equity securities and financial limited partner State and Local Taxes ships as trading securities. We include any unrealized gains Through December 31, 1999, we paid Maryland public service company franchise tax instead of state income tax        or losses on these securities in "Diversified business revenues" in our Consolidated Statements of Income.
Other Diversified Businesses In 1999, earnings from our other diversified businesses increased compared to 1998 mostly because of higher earnings from our real estate and senior-living facilities business.
on our utility revenue from sales in Maryland. We include the franchise tax in "Taxes other than income taxes" in our Available-for-Sale Securities Consolidated Statements of Income.
This increase was artially offset by lower earnings from our financial investments
We classify our investments in the nuclear decommissioning As discussed in Note 4 on page 58, the tax legislation made      trust fund as available-for-sale securities. We include any comprehensive changes to the state and local taxation of electric unrealized gains or losses on the trust assets as a change and gas utilities.                                               in the decommissioning reserve. We describe the nuclear decommissioning trust and the reserve under the heading Inventory                                                        "Decommissioning Costs" later in this note on page 53.
"--business.
We report the majority of our fuel stocks and materials and In addition, our diversified businesses classify some of their supplies at average cost.
In 1999, earnings from our real estate and senior-living facilities business increased compared to 1998 mostly because of: "* a $15.4 million after-tax write-down of its investment in Church Street Station, an entertainment, dining, and retail complex in Orlando, Florida in 1998, and "* an increase in earnings from its investment in Corporate Office Properties Trust (COPT) in 1999. We discuss the investment in COPT below. This increase was partially offset by a $5.8 million after-tax, or $.04 per share, write-down of certain senior-living facilities related to the proposed sale of these facilities in 1999 as discussed below.In 1999, our senior-living facilities business entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire 12 of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption.
investments in marketable equity securities as available-for sale securities. We include any unrealized gains or losses Real Estate Projects and Investments                              on these securities in "Accumulated other comprehensive In Note 3 on page 56, we summarize the real estate projects      (loss) income" in our Consolidated Statements of Common and investments that are in our Consolidated Balance Sheets.      Shareholders' Equity on page 45 and in the Consolidated The projects and investments consist of:                          Statements of Capitalization on page 47. We also include
We could not reach an agreement on financing issues that subsequently arose, and the agreement was terninated in November 1999. As a result, our senior-living facilities business engaged a third-party management company to manage its senior-living facilities portfolio including the three facilities now under construction, scheduled to be completed in the first half of 2000. In 1999, Constellation Real Estate Group, Inc. (CREG) sold Church Street Station, for $11.5 million, the approximate book value of the complex.
    "*land under development in the Baltimore-Washington          our diversified businesses' portion of unrealized gains or corridor,                                                   losses on securities of equity-method (described earlier in
In 1999, our financial investments business announced that it would exchange its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE), another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock of Capital Re. Through September 30, 1999, our financial investments business wrote down its $94.2 million investment in Capital Re stock by $20.9 million after-tax, or $.14 per share, to reflect the market value of this investment.
    "*a mixed-use planned-unit development, and                    this note) investees in our Consolidated Statements of Common Shareholders' Equity.
The agreement between ACE and Capital Re was subsequently revised on a more favorable basis for Capital Re to include both cash and ACE stock. In December 1999, the transaction was finalized and our financial investments business recorded a $4.9 million after-tax, or $.03 per share, gain on this investment to reflect the closing price of the business combination.
    "*an equity interest in Corporate Office Properties Trust, a real estate investment trust.
This net write down of Capital Re was partially offset by better market performance of other financial investments in 1999 compared to 1998. In 1998, earnings from our other diversified businesses decreased compared to 1997 mostly due to lower earnings from our real estate and senior-living facilities and financial investments businesses.
Evaluation of Assets for Impairment The costs incurred to acquire and develop properties are          SFAS No. 121, Accounting for the Impairment ofLong-Lived included as part of the cost of the properties.                 Assets andfor Long-Lived Assets to Be Disposed Of, applies particular requirements to some of our assets that have long lives (some examples are utility property and equipment and real estate). We determine if those assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We recog nize an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset.
Earnings from our real estate and senior-living facilities business decreased mostly due to: "* a $15.4 million after-tax write-down of its investment in Church Street Station, "* lower earnings from various real estate and senior-living facilities projects, and "* a $4.0 million after-tax gain on the sale of two senior living facilities projects reflected in 1997 results.
See Note 4 on page 59 for further discussion.
Constellation Energy Group Inc. and Subsidiaries I
ConstellationEnergy Group Inc. and Subsidiaries
In addition, in 1998, our real estate and senior-living facilities business exchanged certain assets and liabilities in return for a 41.9% equity interest in COPT, a real estate investment trust. In 1998, earnings from our financial investments business decreased compared to 1997 mostly because of: "* better market performance for its investments in 1997, and "* a $6.0 million after-tax gain on the sale of stock held by a financial limited parmership reflected in 1997 results.
 
We discuss our real estate projects, the write-downs of our real estate projects, the COPT transaction, and our financial investments further in Note 3 beginning on page 56. Most of CREG's remaining real estate projects are in the Baltimore-Washington corridor.
I
The area has had a surplus of available land in recent years and as a result these projects have been economically hurt. Constellation Real Estate's projects have continued to incur carrying costs and depreciation over the years. Additionally, this business has been charging interest payments to expense rather than capitalizing them for some undeveloped land where development activities have stopped. These carrying costs, depreciation, and interest expenses have decreased earnings and are expected to continue to do so. Cash flow from real estate operations has not been enough to make the monthly loan payments on some of these projects.
    'Itility Plant, Depreciation, Amortization,                      expense based on a facility-specific cost estimate so we
Cash shortfalls have been covered by cash obtained from the cash flows of other diversified subsidiaries.
      )id Decommissioning                                            can accumulate a decommissioning reserve of $521 million
We consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about our real estate projects.
"ý4JtilityPlant                                                      in 1993 dollars by the end of Calvert Cliffs' service life Utility plant is the term we use to describe our utility business  in 2016, adjusted to reflect expected inflation. We have property and equipment that is in use, being held for future      reported the decommissioning reserve in "Accumulated use, or under construction. We summarize utility plant in our      depreciation" in our Consolidated Balance Sheets. The Consolidated Balance Sheets. We report our utility plant at        total reserve was $287.5 million at December 31, 1999 its original cost, unless impaired under the provisions of         and $244.0 million at December 31, 1998.
If we were to decide to sell our real estate projects, we could have write downs. In addition, if we were to sell our real estate projects in the current market, we would have losses which could be material, although the amount of the losses is hard to predict.
SFAS No. 121. Our original cost includes:
Depending on market conditions, we could also have material losses on any future sales. Our current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. We evaluate strategies for all our businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial.
To fund the costs we expect to incur to decommission the
Under accounting rules, we are required to write down the / value of a real estate project to market value in either of two cases. The first is if we change our intent about a project from'an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected future cash flow from the project is less than the investment in the project.
      "*material and labor,                                           plant, we established an external decommissioning trust in
Consolidated Nonoperating Income and Expenses Other Income and Expenses In September.
      "*contractor costs,                                            accordance with Nuclear Regulatory Commission (NRC)
1995, we signed an agreement to merge with Potomac Electric Power Company after all necessary regulatory approvals were received.
      "*construction overhead costs (where applicable), and           regulations. We report the assets in the trust in "Nuclear
In December 1997, both companies mutually terminated the merger agreement.
      "*an allowance for funds used during construction (described    decommissioning trust fund" in our Consolidated Balance later in this note).                                          Sheets. The NRC requires utilities to provide financial assur ance that they will accumulate sufficient funds to pay for the We charge retired or otherwise-disposed-of utility plant to        cost of nuclear decommissioning based upon either a generic accumulated depreciation.                                          NRC formula or a facility-specific decommissioning cost We own an undivided interest in the Keystone and Conemaugh        estimate. We use the facility-specific cost estimate for funding electric generating plants in Western Pennsylvania, as well as    these costs and providing the required financial assurance.
Accordingly, in 1997, we wrote off $57.9 million of costs related to the merger. This write-off reduced after-tax earnings by $37.5 million, or $.25 per share. Fixed Charges In 1999, fixed charges decreased
in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests    Allowance for Funds Used During Construction and in these plants are 20.99% in Keystone and 10.56% in              Capitalized Interest Conemaugh. These ownership interests represented a net            Allowance for Funds Used During Construction(AFC) investment of $156 million at December 31, 1999 and               We finance utility construction projects with borrowed funds
$7.7 million compared to 1998 mostly because we had less BGE preference stock outstanding.
  $152 million at December 31, 1998. We report these                and equity funds. We are allowed by the Maryland PSC to roperties in the same accounts we use for our other            record the costs of these funds as part of the cost of construc
In 1998, fixed charges increased
_._,tility plant (described above).                                tion projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized DepreciationExpense                                                by the Maryland PSC. We bill our customers for the AFC Generally, we compute depreciation by applying composite,         plus a return after the utility plant is placed in service.
$4.0 million compared to 1997 mostly because we had more debt outstanding.
straight-line rates (approved by the Maryland PSC) to the average investment in classes of depreciable property. We          The AFC rates are 9.04% for gas plant, 9.35% for common depreciate vehicles based on their estimated useful lives.        plant, and 9.40% for electric plant. We compound AFC annually.
Our fixed charges would have been higher except we had less BGE preference stock outstanding and lower interest rates in 1998 compared to 1997. Income Taxes In 1999, income taxes increased
Amortization Expense Amortization is an accounting process of reducing an amount        CapitalizedInterest in our Consolidated Balance Sheets evenly over a period of        With the issuance of the Restructuring Order, we ceased time. When we reduce amounts in our Consolidated Balance          accruing AFC for electric generation-related construction Sheets, we increase amortization expense in our Consolidated      projects and began using SFAS No. 34, Capitalizing Statements of Income. An amount is considered fully                Interest Costs, to calculate the cost during construction of amortized when it has been reduced to zero.                       debt funds used to finance our electric generation-related construction projects.
$8.2 million compared to 1998 because we had higher taxable income from both our utility operations and our diversified businesses.
DecommissioningCosts                                              Our diversified businesses capitalize interest costs incurred We must accumulate a reserve for the costs that we expect to      to finance real estate developed for internal use and certain incur in the future to decommission the radioactive portion of    power projects.
In 1998, income taxes increased
Calvert Cliffs. We do this based on a sinking fund methodology.
$20.2 million compared to 1997 because we had higher taxable income from both our utility operations and our diversified businesses.
The Maryland PSC authorized us to record decommissioning ConstellationEnergy Group Inc. and Subsidiaries
Please refer to Note 4 on page 58 for a discussion of tax law changes. These changes are designed, in part, to tax Maryland electric generating facilities on a more comparable basis with electric generation in other states.Constellation Energy Group Inc. and Subsidiaries I
 
'Financial Condition
r Long-Term Debt                                                    "*our disclosure of contingent assets and liabilities at the We defer (include as an asset or liability in our Consolidated      dates of the financial statements, and Balance Sheets and exclude from our Consolidated Statements      "*our reported amounts of revenues and expenses in of Income) all costs related to the issuance of long-term debt. our Consolidated Statements of Income during the These costs include underwriters' commissions, discounts or        reporting periods.
,,ash Flows 1999 1998 (In millions)Cash provided by (used in): Operating Activities Investing Activities Financing Activities
premiums, and other costs such as legal, accounting, and        These estimates involve judgments with respect to, among regulatory fees, and printing costs. We amortize these costs    other things, future economic factors that are difficult to over the life of the debt.                                     predict and are beyond management's control. As a result, When we incur gains or losses on debt that we retire prior to  actual amounts could differ from these estimates.
$679.0 (615.1) (144.9)1997$799.8 $696.3 (711.3) (520.8) (77.4) (79.6)In 1999 and 1998, cash provided by operations changed compared to the respective prior year mostly because of changes in working capital requirements.
maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt. Reclassifications We have reclassified certain prior-year amounts for comparative Cash Flows                                                    purposes. These reclassifications did not affect consolidated For the purpose of reporting our cash flows, we define cash    net income for the years presented.
In 1999, we used less cash for investing activities compared to 1998 mostly due to lower investments in international power projects and in the real estate and senior-living facilities business.
equivalents as highly liquid investments that mature in three months or less.                                                Accounting Standards Issued In July 1999, the FASB issued SFAS No. 137 that delays the Use of Accounting Estimates                                    effective date for SFAS No. 133, Accounting for Derivative Management makes estimates and assumptions when                Instruments and Hedging Activities, by one year. Therefore, preparing financial statements under generally accepted        we must adopt the provisions of SFAS No. 133 in our accounting principles. These estimates and assumptions affect  financial statements for the quarter ended March 31, 2001.
This was partially offset by: "* our energy services businesses increased the investment in Orion Power Holdings, Inc. by $97.7 million, "* our power projects business increased its investment in domestic power projects, primarily related to the 800 megawatts of peaking capacity as discussed in the "Capital Requirements of our Diversified Businesses" section on page 37, and "* BGE increased its construction expenditures by $46.5 million.  " In 1998, net cash used in investing activities increased compared to 1997 mostly because of the additional investments in international power projects.
various matters, including:                                    We have not determined the effects of SFAS No. 133 on our reported amounts of assets and liabilities in our      our financial results.
This was partially offset by a $33.8 million decrease in utility construction expenditures.
Consolidated Balance Sheets at the dates of the financial statements, (Note        2.
Total utility construction expenditures, including the allowance for funds used during construction, were $385.9 million in 1999 as compared to $339.4 million in 1998 and $373.2 million in 1997.In 1999, we used more cash for financing activities compared to 1998 mostly because we repaid more long-term debt and issued less long-term debt and common stock. This was partially offset by a decrease in the redemption of BGE preference stock and higher net short-term borrowings in 1999 compared to 1998. In 1998, cash used in financing activities was about the same compared to 1997. In 1998, we issued more long-term debt and common stock, and had contributions from minority interests of approximately
Information          by Operating          Segment.
$86 million related to the acquisition of a distribution company in Panama. This was offset by the repayment of short-term borrowings that matured, sinking fund requirements, and early redemption of higher cost securities.
We have three reportable operating segments-Electric, Gas,      Our remaining diversified businesses:
Security Ratings Independent credit-rating agencies rate Constellation Energy and BGE's fixed-income securities.
and Energy Services:                                              "*engage in financial investments, and
The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities.
    "*Our Electric business generates, purchases, and sells        "*develop, own, and manage real estate and senior-living electricity,                                                   facilities.
These ratings affect how much it will cost each company to sell these securities.
    "*Our Gas business purchases, transports, and sells natural  These reportable segments are strategic businesses based gas, and                                                    principally upon regulations, products, and services that
The better the rating, the lower the cost of the securities to each company when they sell them. Constellation Energy and BGE's securities ratings at the date of this report are: Standard & Poors Rating Group Constellation Energy Unsecured Debt BGE Mortgage Bonds Unsecured Debt Trust Originated Preferred Securities and Preference Stock Moody's Duff & Phelps' Investors Credit Service Rating Co.A- A3 A AA A Al A2 AA A+A Constellation Energy Group Inc. and Subsidiaries I I Capital Resources Our business requires a great deal of capital. Our actual consolidated capital requirements for the years 1997 through 1999, along with estimated annual amounts for the years 2000 through 2002, are shown in the table below. For the year ended December 31, 1999, the ratio of earnings to fixed charges for Constellation Energy was 2.87. Investment requirements for 2000 through 2002 include estimates of funding for existing and anticipated projects.
    "*Our Energy Services businesses consist of certain          require different technology and marketing strategies.
We continuously review and modify those estimates.
diversified businesses that:                                The segments have the same accounting policies as those
Actual investment requirements may vary from the estimates included in the table below because of a number of factors including:
      - develop, own, and operate power projects,                 described in the summary of significant accounting policies
"* regulation, legislation, and competition, "* BGE load requirements, "* environmental protection standards, "* the type and number of projects selected for development, "* the effect of market conditions on those projects, "* the cost and availability of capital, and "* the availability of cash from operations.
      - provide power marketing and risk management services,    in Note 1. The Company evaluates the performance of these
Our estimates are also subject to additional factors. Please see the "Forward Looking Statements" section on page 39. No earlier than July 1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation assets will be transferred to nonregulated subsidiaries of Constellation Energy. The discus sion and table for capital requirements below include these generation assets as part of the utility business.1997 1998 1999 2000 2001 2002 (In millions)
      - provide nuclear consulting services,                     segments based on net income. We account for intersegment revenues using market prices. A summary of information by
Utility Business Capital Requirements:
      - sell natural gas through mass marketing efforts,         operating segment is shown on page 55.
Construction expenditures (excluding AFC) Electric $ 238 $ 239 $ 283 $ 329 $ 332 $ 312 Gas 89 55 59 63 61 61 Common 38 35 34 25 23 23 Total construction expenditures AFC Nuclear fuel (uranium purchases and processing charges) Deferred conservation expenditures Retirement of long-term debt and redemption of preference stock Total utility business capital requirements 365 329 8 10 44 50 27 16 243 222 687 627 376 10 49 1 342 778 417 4 50 401 872 416 4 48 281 749 396 4 48 151 599 Diversified Business Capital Requirements:
      - sell and service electric and gas appliances, heating We are realigning our organization combining all of our and air conditioning systems, and engage in home domestic merchant energy businesses. We have not determined improvements, and the impact of this reorganization on our operating segments, but
Investment requirements 156 325 278 764 1,001 755 Retirement of long-term debt 188 232 189 284 367 2 Total diversified business capital requirements 344 557 467 1,048 1,368 757 Total capital requirements
      - provide cooling services to commercial customers          such changes will impact our operating segments in the future in Baltimore.
$1,031 $1,184 $1,245 $1,920 $2,117 $1,356 Capital Requirements of Our Utility Business Our estimates of future electric construction expenditures do not include costs to build more generating units to meet load requirements for BGE customers.
I  Constellation Energy Group Inc. and Subsidiaries
Electric construction expen ditures include improvements to generating plants and to our transmission and distribution facilities, and costs for replacing the steam generators and renewing the operating licenses at Calvert Cliffs. The operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. If we do not replace the steam genera tors, we may not be able to operate the Calvert Cliffs units beyond 2014 and 2016. We expect the steam generator replace ments to occur during the 2002 refueling outage for Unit 1 and during the 2003 refueling outage for Unit 2. We discuss the license extension process further in the "Current Issues" section on page 22. We estimate these Calvert Cliffs costs to be: * $40 million in 2000, * $66 million in 2001, * $88 million in 2002, and * $60 million in 2003.Constellation Energy Group Inc. and Subsidiaries I
 
kdditionally, our estimates of future electric construction include the costs of complying with Environmental Protection Agency (EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction regulations as follows: * $63 million in 2000, * $52 million in 2001, and * $4 million in 2002. We discuss the NOx regulations and timing of expenses further in Note 10 on page 69. Our utility operations provided about 99% in 1999, 108% in 1998, and 105% in 1997 of the cash needed to meet its capital requirements, excluding cash needed to retire debt and redeem preference stock. During the three years from 2000 through 2002, we expect our existing utility business to provide about 115% of the cash needed to meet the capital requirements for these operations, excluding cash needed to retire debt. The table for capital requirements on page 36 includes the requirements for BGE fossil and nuclear generation under "Utility Business Capital Requirements-Electric" through 2002 even though these assets are to be transferred to nonregulated subsidiaries on or about July 1, 2000. We will continue to have cash requirements for: "* working capital needs including the payments of interest, distributions, and dividends, "* capital expenditures, and "* the retirement of debt and redemption of preference stock. When BGE cannot meet utility capital requirements internally, BGE sells debt and preference stock. BGE also sells securities when market conditions permit it to refinance existing debt or preference stock at a lower cost. The amount of cash BGE needs and market conditions determine when and how much BGE sells. Future funding for capital expenditures, the retirement of debt, and payments of interest and dividends is expected from internally generated funds, commercial paper issuances, available capacity under credit facilities, and/or the issuance of long-term debt, trust securities, or preference stock. At December 31, 1999, the Federal Energy Regulatory Commission has authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. In addition, BGE maintains
I Energy          Other          Unallocated Electric          Gas      Services      Diversified        Corporate "Business      Business  Businesses      Businesses        Items (a)    Eliminations Consolidated (In millions) 1999 Unaffiliated revenues                      $2,258.8        $476.5    $ 937.0          $113.9                                        $3,786.2 Intersegment revenues                            1.2          11.6      30.4              (0.4}                        (42.8')
$123 million in annual committed bank lines of credit and has $60 million in bank revolving credit agreements to support the commercial paper program as discussed in Note'7 on page 65. In addition, BGE has access to interim lines of credit as required from time to time to support its outstanding commercial paper.Capital Requirements of Our Diversified Businesses Our energy services businesses will require additional funding for: "* growing its power marketing business, "* developing and acquiring power projects, and "* constructing cooling system projects.
Total revenues                              2,260.0          488.1      967.4            113.5                -         (42.8)      3,786.2 Depreciation and amortization                  376.4            44.9      23.1              5.2              0.2            -         449.8 Equity in income of equity method investees (b)                          5.1            -          -              -                  -                          5.1 Net interest expense                          162.4          24.4        24.6            31.1                0.4        (1.4)        241.5 Income tax expense (benefit)                  149.2            18.1      34.8            (12.1)              (0.9)        (2.7)        186.4 Extraordinary loss                              66.3              -          -..                                                          66.3 Net income (loss) (c)                          198.8          33.0        50.6            (19.3)              (1.7)        (1.3)        260.1 Segment assets                              6,312.6          915.3    1,681.2          743.2              129.2        (97.7)      9,683.8 Utility construction expenditures              322.1           63.8          -              -                -                        385.9 1998 Unaffiliated revenues                      $2,219.2        $449.4    $ 524.1          $165.4            $-          $ -          $3,358.1 Intersegment revenues                            1.6            1.7      12.0              0.5              -        (15.8)             -
Our energy services businesses' investment requirements include the planned construction of 800 megawatts of peaking capacity in the Mid-Atlantic/Mid-West region by the summer of 2001 and an additional 4,300 megawatts of peaking and combined cycle production facilities scheduled for completion in 2002 and beyond. Our investment requirements also include our energy services businesses' commitment to contribute up to an additional
Total revenues                                2,220.8        451.1        536.1          165.9                -        (15.8)       3,358.1 Depreciation and amortization                  313.0          45.4          9.2              9.3              0.2                      377.1 Equity in income of equity method investees (b)                           5.0                                                                                        5.0 Net interest expense                            164.9          23.6        16.0            38.6              (1.9)        (0.3)        240.9 Income tax expense (benefit)                    146.6          13.4       34.1            (15.8)            (0.1)                      178.2 Net income (loss) (d)                          259.6          26.1       43.4            (24.2)            (0.1)          1.1         305.9 Segment assets                                6,342.8        934.6    1,315.0            811.6              (14.0)      (115.0)        9,275.0 Utility construction expenditures              279.0          60.4                                                                      339.4
$121 million in equity to Orion. To date, our energy services businesses have funded $104 million in equity to Orion. Our energy services businesses have met their capital requirements in the past through borrowing, cash from their operations, and from time to time equity contributions from BGE. Future funding for the expansion of our energy services businesses is expected from internally generated funds, commercial paper issuances and long-term debt financing by Constellation Energy, and from time to time equity contributions from Constellation Energy. BGE Home Products & Services may also meet capital requirements through sales of receivables.
.. 1997 Unaffiliated revenues                      $2,191.7        $521.6      $ 399.4          $194.9                                        $3,307.6 Intersegment revenues                            0.3                        0.6              9.7                          (10.6)
At December 31, 1999, Constellation Energy has a commercial paper program where it can issue up to $500 million in short term notes to fund its diversified businesses.
Total revenues                              2,192.0          521.6      400.0            204.6                          (10.6)        3,307.6 Depreciation and amortization                  286.5          39.3        6.9              9.9                0.3                      342.9 Equity in income of equity method investees (b)                        5.0                                                                                        5.0 Net interest expense                            160.7          20.3        10.1            32.5                6.4                      230.0 Income tax expense (benefit)                   135.7          13.9        23.8          (13.5)              (1.9)                       158.0 Net income (loss) (e)                          224.0          25.6        27.5          (21.1)              (3.6)          1.7          254.1 Segment assets                              6,404.4          907.7      700.9            885.4              10.7          (9.1)      8,900.0 Utility construction expenditures              278.7          94.5                                                                      373.2 (a) We do not allocate certain items presented in the table for          (d) Our Energy Services businesses recorded $10.4 million for Constellation Energy Group and a holding company for our                  its share of earnings in a partnership as discussed in Note 3 and a diversified businesses.                                                  $5.5 million write-off of an energy services investment as discussed (b) Our Energy Services and our Other Diversified businesses              in the "Other Energy Services" section of Management's Discussion record their equity in the income of equity method investees in          and Analysis on page 33. In addition, our Other Diversified businesses their unaffiliated revenues.                                             recorded a $15.4 million write-down of a real estate project as discussed in Note 3.
To support its commercial paper program, Constellation Energy maintains
(c) Our Electric business recorded costs of $4.9 million after-tax related to Hurricane Floyd as discussed in the "Electric Operations      (e) Our Electric business recorded a $37.5 million write-off and Maintenance Expenses" section of Management's Discussion              related to the terminated merger with Potomac Electric Power and Analysis on page 28. Our Other Diversified businesses recorded        Company as discussed in the "Other Income and Expenses" section a $16.0 million write-down of its investment in Capital Re stock to       of Management's Discussion and Analysis on page 34. In addition, reflect the market value of this investment as discussed in Note 3        our Other Diversified businesses recorded a $46.0 million write and a $5.8 million write-down of certain senior-living facilities as      down of two real estate projects as discussed in Note 3.
$35 million in annual committed bank lines of credit and has a $135 million revolving credit agreement, under which it can also issue letters of credit. In addition, Constellation Energy has access to interim lines of credit as required from time to time to support its outstanding commercial paper. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs. If we can get a reasonable value for our real estate projects, additional cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss the real estate business and market in the "Other Diversified Businesses" section on page 33. We discuss our short-term borrowings in Note 7 on page 65 and long-term debt in Note 8 on page 65.Constellation Energy Group Inc. and Subsidiaries I I Market Risk We are exposed to market risk, including changes in interest rates, certain commodity prices, equity prices, and foreign currency.
discussed in the "Other Diversified Businesses" section of "Management'sDiscussion and Analysis on page 33. In addition, 3ur Energy Services businesses recorded $18.7 million in write-downs of certain power projects as discussed in Note 3.
To manage our market risk, we may enter into various derivative instruments including swaps, forward contracts, futures contracts, and options. Effective July 1, 2000, we will be subject to additional market risk associated with the purchase and sale of energy as discussed in the "Current Issues" section on page 21. In this section, we discuss our current market risk and the related use of derivative instruments.
ConstellationEnergy Group Inc. and Subsidiaries I
Interest Rate Risk We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt. The following table provides information about our obligations that are sensitive to interest rate changes: Principal Payments and Interest Rate Detail by Contractual Maturity Date 2000 2001 2002 Fair value at 2003 2004 Thereafter Total Dec. 31, 1999 (In millions)Long-term debt Variable-rate debt Average interest rate Fixed-rate debt Average interest rate Commodity Price Risk We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas, electricity, and other trading commodities.
 
Currently, our gas business and energy services businesses use derivative instruments to manage changes in their respective commodity prices. Gas Business Our gas business may enter into gas futures, options, and swaps to hedge its price risk under our market based rate incentive mechanism and our off-system gas sales program. We discuss this further in Note 1 on page 51. At December 31, 1999 and 1998, our exposure to commodity price risk for our gas business was not material.
I (Note        3.
Energy Services Businesses With respect to our energy services businesses, Constellation Power Source manages its commodity price risk inherent in its power marketing activities on a portfolio basis, subject to established trading and risk management policies.
Investments Real Estate Projects and Investments                              In 1997, CREG recorded the following write-downs of real Real estate projects and investments held by Constellation        estate projects:
Commodity price risk arises from the potential for changes in the value of energy commodities and related derivatives due to: changes in commodity prices, volatility of commodity prices, and fluctua tions in interest rates. A number of factors associated with the structure and operation of the electricity market significantly influence the level and volatility of prices for electricity and related derivative products.
Real Estate Group (CREG), consist of the following:                 "*a $14.1 million after-tax write-down of the investment in At December 31,                          1999              1998        Church Street Station that occurred because CREG decided (In millions)          to sell rather than keep the project, and Properties under development            $197.8            $210.6    "*a $31.9 million after-tax write-down of the investment in Piney Orchard-a mixed-use, planned-unit development Rental and operating properties 9.2            38.9      that occurred because the expected future cash flow from (net of accumulated depreciation) the project was less than CREG's investment in the project.
Constellation Energy Group Inc. and Subsidiaries These factors include: "* seasonal changes in the demand for electricity, "* hourly fluctuations in demand due to weather conditions, "* available generation resources, "* transmission availability and reliability within and between > regions, and "* procedures used to maintain the integrity of the physical electricity system during extreme conditions.
Equity interest in real estate investment trust                      103.1            104.0 Other real estate ventures                  -                 0.4 Power Projects Total real estate projects                                        Power projects held by our diversified businesses consist of and investments                    $310.1            $353.9  the following:
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country and result from regional differences in: "* weather conditions, "* market liquidity, "* capability and reliability of the physical electricity system, and "* the nature and extent of electricity deregulation.
At December 31,                           1999             1998 In 1999, CREG sold Church Street Station -an entertainment,                                                   (In millions) dining, and retail complex in Orlando, Florida -for $11.5        Domestic million, the approximate book value of the complex.                  East                              $ 55.7            $ 46.0 West                                475.6            427.4 In 1998, CREG recorded a $15.4 million after-tax write-down International of the investment in Church Street Station that occurred South America                        12.3            21.6 because the fair value of the project declined based upon competitive bids.                                                    Central America                    241.8            248.1 Total power projects                  $785.4          $743.1 In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust Our Domestic-West power projects include investments of based in Philadelphia, under which COPT assumed approxi
Constellation Power Source uses various methods, including a value at risk model, to measure its exposure to market risk. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price and volatility data. Constellation Power Source calculates value at risk using a variance/covariance technique that models option positions using a linear approximation of their value. Additionally, Constellation Power Source estimates variances and correlation using historical market movements over the most recent rolling three-month period.$201.9 6.68% $484.4 7.16%$166.0 6.39% $482.8 7.08%$ 0.9 8.32% $154.6 7.31%$ 7.8 7.42% $289.4 6.52%$ 5.4 7.41% $154.6 5.78%$ 272.8 4.80% $1,173.7 6.83%$ 654.8 5.84% $2,739.5 6.87%$ 654.8 $2,637.3 The value at risk amount represents the potential loss in the ,jair value of assets and liabilities from trading activities over a one-day holding period with a 99.6% confidence level. Using this confidence level, Constellation Power Source would expect a one-day change in fair value greater than or equal to the daily value at risk at least once per year. Constellation Power Source's value at risk was $7.2 million as of December 31, 1999 compared to $6.0 million as of December 31, 1998. The average, high, and low value at risk for the year ended December 31, 1999 was $4.8 million, $7.2 million and $1.8 million, respectively.
                                                                      $301.8 million in 1999 and $310.6 in 1998 that sell electricity mately $62 million of CREG's outstanding debt, paid CREG in California under power purchase agreements called approximately $22.8 million in cash, and issued to CREG "Interim Standard Offer No. 4" agreements. We discuss approximately 7.0 million common shares representing a these projects further in Note 10 on page 71.
Constellation Power Source's calculation includes all assets and liabilities from its power marketing and trading activities, including energy commodities and derivatives that do not require cash settlements.
41.9% equity interest in COPT and 985,000 convertible preferred shares. Each convertible preferred share yields        In 1999, our power projects business recorded a $14.2 million 5.5% per year, and is convertible after two years from the       after-tax write-off of two geothermal power projects. These date of the agreement into 1.8748 common shares.                 write-offs occurred because the expected future cash flows In exchange, COPT received 14 operating properties and           from the projects are less than the investment in the projects.
We believe that this represents a more complete calculation of our value at risk. Due to the inherent limitations of statistical measures such as value at risk, the relative immaturity of the competitive market for electricity and related derivatives, and the season ality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price risk exposure.
two properties under development from CREG as well as             For the first project, this resulted from the inability to restruc certain other assets, options, and first refusal rights. These  ture certain project agreements. For the second project, we options and first refusal rights are related to approximately    experienced a declining water temperature of the geothermal 91 acres of identified properties which are adjacent to          resource used by one of the plants for production.
Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method. As a result, actual changes in the fair value of assets and liabilities from 9ower marketing and trading activities could differ from the ,%..--calculated value at risk and such changes could have a material impact on our financial results. Please refer to the "Forward Looking Statements" section below.We discuss Constellation Power Source's business in the "Power Marketing" section on page 31 and in Note 1 on page 51. The commodity price risk for our remaining energy services businesses was not material at December 31, 1999 and 1998. Equity Price Risk We are exposed to price fluctuations in equity markets primarily through our financial investments business and our nuclear decommissioning trust fund. We are required by the NRC to maintain a trust to fund the costs of decommissioning Calvert Cliffs. At December 31, 1999 and 1998, equity price risk was not material.
operating properties acquired by COPT. At December 31, 1999,     In 1999, we recorded a $4.5 million after-tax write-down to 48 acres remain under these options and first refusal rights    reflect the fair value of our investment in a generating company and have terms that range from 1 to 4 years.                     in Bolivia as a result of our international exit strategy.
We discuss our nuclear decommissioning trust fund in more detail in Note 1 on page 53. We also describe our financial investments in more detail in Note 3 on page 57. Foreign Currency Risk We are exposed to foreign currency risk primarily through our power projects business.
In 1998, our power projects business recorded $10.4 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power sales contract.
Our power projects business has $254.1 million invested in 10 international power generation and distribution projects as of December 31, 1999. To manage our exposure to foreign currency risk, the majority of our contracts are denominated in or indexed to the U.S. dollar. At December 31, 1999 and 1998, foreign currency risk was not material.
ConstellationEnergy Group Inc. and Subsidiaries
We discuss our international projects in the "Power Projects" section on page 32.( Forward Looking Statements We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "expects," "intends," "plans," and other similar words. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to: "* general economic, business, and regulatory conditions, "* energy supply and demand, "* competition, "* federal and state regulations, "* availability, terms, and use of capital, '
 
* nuclear and environmental issues, "* weather, "" implications of the Restructuring Order issued by the Maryland PSC,"* commodity price risk, "* operating our currently regulated generating assets in a deregulated market beginning July 1, 2000 without the benefit of a fuel rate adjustment clause, "* loss of revenues due to customers choosing alternative suppliers, "* higher volatility of earnings and cash flows, and "* increased financial requirements of our nonregulated subsidiaries.
I Financial Investments                                                                    Amortized Unrealized Unrealized Fair inancial investments held by Constellation Investments, Inc. At December 31, 1999    Cost Basis    Gains      Losses    Value consist of the following:                                                                                (In millions)
Given these uncertainties, you should not place undue reliance on these forward looking statements.
Marketable equity securities              $167.1      $42.8        $(2.1) $207.8 At December 31,                       1999              1998 Corporate debt and (In millions)
Please see the other sections of this report and our other periodic reports filed with the SEC for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report.Constellation Energy Group Inc. and Subsidiaries I I S Report of Management The management of the Company is responsible for the information and representations in the Company's financial statements.
U.S. Government Insurance company                    $    -            $102.5    agency                      14.4      -            -         14.4 Marketable equity securities          84.2                25.3  State municipal bonds        74.2      -          (0.8)      73.4 Financial limited partnerships        35.8               41.9  Totals                    $255.7     $42.8       $(2.9) $295.6 Leveraged leases                      25.4               28.3 Total financial investments          $145.4            $198.0                            Amortized Unrealized Unrealized Fair At December 31, 1998    Cost Basis    Gains        Losses    Value (In millions)
The Company prepares the financial statements in accordance with generally accepted accounting principles based upon available facts and circumstances and manage ment's best estimates and judgments of known conditions.
In 1999, our financial investments business announced that it Marketable equity would exchange its shares of common stock in Capital Re, an securities              $ 82.9      $24.2        $(0.4) $106.7 insurance company, for common stock of ACE Limited (ACE),
The Company maintains an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company's assets are protected.
Corporate debt and another insurance company, as part of a business combination U.S. Government whereby ACE would acquire all of the outstanding capital agency                      12.7       0.4          -          13.1 stock of Capital Re. Through September 30, 1999, our State municipal bonds        64.8        2.7         -        67.5 financial investments business wrote-down its $94.2 million Totals                    $160.4      $27.3        $(0.4) $187.3 investment in Capital Re stock by $20.9 million after-tax to reflect the market value of this investment. The agreement The above tables include $40.5 million in 1999 and $23.9 million between ACE and Capital Re was subsequently revised on a in 1998 of unrealized net gains associated with the nuclear more favorable basis for Capital Re to include both cash and decommissioning trust fund which are reflected as a change in kCE stock. In December 1999, the transaction was finalized the nuclear decommissioning trust fund on the Consolidated our financial investments business recorded a $4.9 million Balance Sheets.
The Company's staff of internal auditors, which reports directly to the Chairman of the Board, conducts periodic reviews to maintain the effectiveness of internal control procedures.
after-tax gain on this investment to reflect the closing price of the business combination. As a result of this business        Gross and net realized gains and losses on available-for-sale combination, this investment no longer qualifies as an          securities were as follows:
PricewaterhouseCoopers LLP, independent accountants, audit the financial statements and express their opinion on them. They perform their audit in accordance with generally accepted auditing standards.
equity-method investment. Accordingly, in 1999, we have         Year Ended December 31,                 1999       1998       1997 included this investment in the marketable equity securities                                                    (In millions) amount above.                                                   Gross realized gains                  $11.7      $4.2        $9.3 Gross realized losses                  (38.8)      (0.7)      (0.6)
The Audit Committee of the Board of Directors, which consists, of four outside Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities.
Investments Classifiedas Available-for-Sale Net realized (losses) gains          $(27.1)      $3.5        $8.7 We classify our investments in the nuclear decommissioning trust fund as available-for-sale. In addition, we classify some The Corporate debt securities, U.S. Government agency of our diversified businesses' marketable equity securities obligations, and state municipal bonds mature on the (shown above) as available-for-sale. This means we do not following schedule:
The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.
expect to hold them to maturity and we do not consider them trading securities.                                             At December 31, 1999                                    Amount (In millions)
Christian H. Poindexter Chairman of the Board and Chief Executive Officer David A. Brune Chief Financial Officer SReport of Independent Accountants To the Shareholders of Constellation Energy Group, Inc.In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, compre hensive income, cash flows, common shareholders' equity, capitalization and income taxes present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and Subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in confor mity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial state ments are free of material misstatement.
We show the fair values, gross unrealized gains and losses,     Less than 1 year                                          $ 1.0 and amortized cost bases for all of our available-for-sale      1-5 years                                                  46.4 securities, exclusive of $6.2 million in 1998 of unrealized net  5-10 years                                                  21.8 gains on securities held by Capital Re as an equity method      More than 10 years                                          18.6 investee, in the following tables.                              Total maturities of debt securities                      $87.8 ConstellationEnergy Group Inc. and Subsidiaries I
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.
 
We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Baltimore, Maryland January 19, 2000 Constellation Energy Group Inc. and Subsidiaries ConsoLidated Statements of Income Year Ended December 31, "ý'JRevenues Electric Gas Diversified businesses Total revenues Operating Expenses Electric fuel and purchased energy Gas purchased for resale Operations Maintenance Diversified businesses-selling, general, and administrative Depreciation and amortization Taxes other than income taxes Total oneratinL exnenses 1999 1998 1997 (In millions, except per share amounts)$2,258.8 476.5 1,050.9 3,786.2 467.7 230.6 546.0 186.2 918.7 449.8 227.3 3,026.3$2,219.2 449.4 689.5 3,358.1 505.7 208.6 554.1 177.5 574.6 377.1 219.4 2,617.0$2,191.7 521.6 594.3 3,307.6 519.7 292.1 518.3 178.5 515.7 342.9 216.8 2,584.0 Income from Operations 759.9 741.1 723.6 Other Income (Expense)
V (Note        4.
Write-off of merger costs (see Note 2) --(57.9) Other 7.9 5.7 5.1 Total other income (expense) 7.9 5.7 (52.8) Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8 Fixed Charges Interest expense (net) 241.5 240.9 230.0 BGE preference stock dividends 13.5 21.8 28.7 Total fixed charees 255.0 262.7 258.7 Income Before Income Taxes 512.8 484.1 412.1 Income Taxes 186.4 178.2 158.0 Income Before Extraordinary Item 326.4 305.9 254.1 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) (66.3) -Net Income $ 260.1 $ 305.9 $ 254.1 Earnings Applicable to Common Stock $ 260.1 $ 305.9 $ 254.1 Average Shares of Common Stock Outstanding 149.6 148.5 147.7 Earnings Per Common Share and Earnings Per Common Share -Assuming Dilution Before Extraordinary Item $ 2.18 $ 2.06 $ 1.72 Extraordinary Loss (.44) Earnings Per Common Share and Earnings Per Common Share --Assuming Dilution $ 1.74 $ 2.06 $ 1.72 (Consolidated Statements of Comprehensive Income) Year Ended December 31, 1999 1998 1997 (In millions)
Rate Matters and Accounting Impacts of Deregulation On April 8, 1999, Maryland enacted the Electric Customer          "*BGE will reduce residential base rates by approximately Choice and Competition Act of 1999 (the "Act") and                  6.5% on average, about $54 million a year, beginning accompanying tax legislation that will significantly restructure    July 1, 2000. These rates will not change before July 2006.
Net Income $ 260.1 $ 305.9 $ 254.1 Other comprehensive income/(loss), net of taxes (6.2) 1.2 (0.8) Comprehensive Income $ 253.9 $ 307.1 $ 253.3 "--'See Notes to Consolidated Financial Statements.
Maryland's electric utility industry and modify the industry's    "*Commercial and industrial customers will have up to tax structure. In the Restructuring Order discussed below, the      four service options that will fix electric energy rates and Maryland PSC addressed the major provisions of the Act.             transition charges for a period that generally ranges from The tax legislation made comprehensive changes to the state          four to six years.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
and local taxation of electric and gas utilities. Effective        "*Electric delivery service rates will be frozen for a four January 1, 2000, the Maryland public service franchise tax          year period for commercial and industrial customers. The will be altered to generally include a tax equal to .062 cents      generation and transmission components of rates will be on each kilowatt-hour of electricity and .402 cents on each          frozen for different time periods depending on the service therm of natural gas delivered for final consumption in             options selected by those customers.
Maryland. The Maryland 2% franchise tax on electric and           "*BGE will be allowed to recover $528 million after-tax of natural gas utilities will continue to apply to transmission and its potentially stranded investments and utility restructuring distribution revenue. Additionally, all electric and natural gas costs through a competitive transition charge on customers' utility results will become subject to the Maryland corporate bills. Residential customers will pay this charge for six income tax.
years. Commercial and industrial customers will pay in a Beginning July 1, 2000, the tax legislation also provides for a      lump sum or over the four to six-year period, depending two-year phase-in of a 50% reduction in the local personal          on the service option selected by each customer.
property taxes on machinery and equipment used to generate
                                                                    "*Generation-related regulatory assets and nuclear decom electricity for resale and a 60% corporate income tax credit missioning costs will be included in delivery service rates for real property taxes paid on those facilities.
effective July 1, 2000 and will be recovered on a basis On November 10, 1999, the Maryland PSC issued a                      approximating their existing amortization schedules.
Restructuring Order that resolves the major issues surrounding
                                                                    "*Starting July 1, 2000, BGE will unbundle rates to show electric restructuring, accelerates the timetable for customer      separate components for delivery service, transition choice, and addresses the major provisions of the Act. The          charges, standard offer services (generation), transmission, Restructuring Order also resolves the electric restructuring universal service, and taxes.
proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in    "*On July 1, 2000, BGE will transfer, at book value, its September 1998 by the Office of People's Counsel (OPC) to           ten Maryland-based fossil and nuclear power plants and lower our electric base rates. The major provisions of the          its partial ownership interest in two coal plants and a Restructuring Order are:                                            hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy.
    " All customers, except a few commercial and industrial companies that have signed contracts with BGE, will be        "*BGE will reduce its generation assets, as described later able to choose their electric energy supplier beginning          in this section, by $150 million pre-tax during the period July 1, 2000. BGE will provide a standard offer service          July 1, 1999 - June 30, 2000 to mitigate a portion of its for customers that do not select an altemative supplier.         potentially stranded investments.
In either case, BGE will continue to deliver electricity      "*Universal service will be provided for low-income customers to all customers in areas traditionally served by BGE.          without increasing their bills. BGE will provide its share
    " BGE's current electric base rates are frozen at their current    of a statewide fund totaling $34 million annually.
levels until July 1, 2000.
ConstellationEnergy Group Inc. and Subsidiaries
 
I As discussed in Note 1 on page 49, EITF 97-4 requires that          Under the Restructuring Order, BGE will recover $528 million
      / company should cease applying SFAS No. 71 when either            after-tax of its potentially stranded investments and utility
"-legislation is passed or a regulatory body issues an order that        restructuring costs through the competitive transition charge contains sufficient detail to determine how the transition plan    component of its customer rates beginning July 1, 2000. This will affect the deregulated portion of the business. Additionally, recovery mostly relates to the stranded costs associated with a company would continue to recognize regulatory assets and        Calvert Cliffs, whose book value is substantially higher than liabilities in the Consolidated Balance Sheets to the extent that  its estimated fair value. However, Calvert Cliffs is not consid the transition plan provides for their recovery.                   ered impaired under the provisions of SFAS No. 121 since its We believe that the Restructuring Order provided sufficient        estimated future undiscounted cash flows exceed its book details of the transition plan to competition for BGE's electric    value. Accordingly, BGE did not record any impairment generation business to require BGE to discontinue the                write-down related to Calvert Cliffs. However, we recognized application of SFAS No. 71 for that portion of its business.         after-tax impairment losses totaling $115.8 million associated Accordingly, in the fourth quarter of 1999, we adopted the          with certain of our fossil plants under the provisions of provisions of SFAS No. 101 and EITF 97-4 for BGE's                  SFAS No. 121.
electric generation business.                                       BGE has contracts to purchase electric capacity and energy SFAS No. 101 requires the elimination of the effects of rate        that are expected to be uneconomic upon the deregulation of regulation that have been recognized as regulatory assets and        electric generation. Therefore, we recorded a $34.2 million liabilities pursuant to SFAS No. 71. However, EITF 97-4              after-tax charge based on the net present value of the excess requires that regulatory assets and liabilities that will be        of estimated contract costs over the market-based revenues to recovered in the regulated portion of the business continue          recover these costs over the remaining terms of the contracts.
to be classified as regulatory assets and liabilities. The          In addition, BGE has deferred certain energy conservation Restructuring Order provides for the creation of a single, new      expenditures that will not be recovered through its transmis generation-related regulatory asset to be recovered through          sion and distribution business under the Restructuring Order.
BGE's regulated transmission and distribution business. We          Accordingly, we recorded a $10.3 million after-tax charge to discuss this further in Note 5 on page 60.                         eliminate the regulatory asset previously established for these
      `ursuant to SFAS No. 101, the book value of property, plant,      deferred expenditures.
,,*.tnd equipment may not be adjusted unless those assets are            At December 31, 1999, the total charge for BGE's electric impaired under the provisions of SFAS No. 121. The process          generating plants that are impaired, losses on uneconomic of evaluating and measuring impairment under the provisions          purchased capacity and energy contracts, and deferred of SFAS No. 121 involves two steps. First, we must compare          energy conservation expenditures was approximately the net book value of each generating plant to the estimated        $160.3 million after-tax.
undiscounted future net operating cash flows from that plant.       BGE recorded approximately $94.0 million of the $160.3 million An electric generating plant is considered impaired when its        on its balance sheet. This consisted of a $150.0 million undiscounted future net operating cash flows are less than its      regulatory asset of its regulated transmission and distribution net book value. Second, we compute the fair value of each            business, net of approximately $56.0 million of associated plant that is determined to be impaired based on the present        deferred income taxes. The regulatory asset will be amortized value of that plant's estimated future net operating cash flows      as it is recovered from ratepayers through June 30, 2000.
discounted using an interest rate that considers the risk of        This will accomplish the $150 million reduction of its operating that facility in a competitive environment. To the        generation plants required by the Restructuring Order.
extent that the net book value of each impaired electric genera tion plant exceeds its fair value, we must record a write-down.     We recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that will not be recovered under the Restructuring Order.
ConstellationEnergy Group Inc. and Subsidiaries
 
F SNote        5.
ReguLatory Assets                (net)
As discussed in Note 1 on page 49, the Maryland PSC                  Generation Plant Reduction provides the final determination of the rates we charge our          Recoverable in Current Rates customers for our regulated businesses. Generally, we use the        As a condition of the Maryland PSC's consolidation of the same accounting policies and practices used by nonregulated          September 3, 1998 Office of People's Counsel petition to companies for financial reporting under generally accepted          lower electric base rates with BGE's electric restructuring accounting principles. However, sometimes the Maryland              transition proposal, we agreed to make our rates subject to PSC orders an accounting treatment different from that used          refund effective July 1, 1999. Under the Restructuring Order, by nonregulated companies to determine the rates we charge          BGE's rates are frozen through June 30, 2000. However, our customers. When this happens, we must defer certain              BGE was required to record a reduction to its generation plant utility expenses and income in our Consolidated Balance              of $150 million which it will recover through its current rates Sheets as regulatory assets and liabilities. We then record          between July 1, 1999 and June 30, 2000. BGE recorded a them in our Consolidated Statements of Income (using                $150 million regulatory asset for the required generation plant amortization) when we include them in the rates we charge            reduction that will be amortized as it is recovered from our customers.                                                      ratepayers through June 30, 2000.
We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.                Electric Generation-Related Regulatory Asset With the issuance of the Restructuring Order, BGE no longer At At December December 31.31I                            19'99          1998 met the requirements for the application of SFAS No. 71 for (In millions) the electric generation portion of its business. In accordance Generation plant reduction                                            with SFAS No. 101 and EITF 97-4, all individual generation recoverable in current rates              $75.0          $        related regulatory assets and liabilities must be eliminated from Electric generation-related                                          our balance sheet unless these regulatory assets and liabilities regulatory asset                            286.6 will be recovered in the regulated portion of the business.
Income taxes recoverable through                                    Pursuant to the Restructuring Order, BGE wrote-off all of its \
future rates (net)                        110.4          252.6 individual, generation-related regulatory assets and liabilities.
Deferred postretirement and                                          A single, new generation-related regulatory asset was estab postemployment benefit costs                41.9            90.0 73.3  lished for amounts to be collected through BGE's regulated Deferred nuclear expenditures                                        transmission and distribution business. The new regulatory Deferred conservation expenditures            12.9            53.4 asset will be amortized on a basis that approximates the pre Deferred costs of decommissioning                                    existing individual regulatory asset amortization schedules.
federal uranium enrichment facilities                      38.5 Deferred environmental costs                  31.3            33.4 Deferred fuel costs (net)                      73.8            12.7  Income Taxes Recoverable Through Future Rates (net)
Other (net)                                      5.5          11.8  As described in Note 1 on page 51, income taxes recoverable
                                                $637.4        $565.7  through future rates is the portion of our net deferred income Total regulatory assets  (net) tax liability that is applicable to our utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.
In 1999, the electric generation-related portion of this regulatory asset is included in the electric generation-related regulatory asset discussed earlier in this note.
Constellation Energy Group Inc. and Subsidiaries
Constellation Energy Group Inc. and Subsidiaries
)-I I Consolidated Balance Sheets At December 31.1999 Assets Current Assets Cash and cash equivalents Accounts receivable (net of allowance for uncollectibles of $34.8 and $35.4 respectively)
 
Trading securities Assets from energy trading activities Fuel stocks Materials and supplies Prepaid taxes other than income taxes Other$ 92.7 578.5 136.5 312.1 94.9 149.1 72.4 54.0 1998 (In millions)$ 173.7 422.7 119.7 133.0 85.4 145.1 68.8 21.4 Total current assets 1,490.2 1,169.8 Investments and Other Assets Real estate projects and investments 310.1 353.9 Power projects 785.4 743.1 Financial investments 145.4 198.0 Nuclear decommissioning trust fund 217.9 181.4 Net pension asset 99.5 108.0 Other 422.9 243.3 Total investments and other assets 1,981.2 1,827.7 Utility Plant Plant in service Electric 7,088.6 6,890.3 Gas 962.0 921.3 Common 569.5 552.8 Total plant in service 8,620.1 8,364.4 Accumulated depreciation (3,466.1)
I Deferred Postretirement and Postemployment                            Deferred Costs of Decommissioning 3enefit Costs                                                        Federal Uranium Enrichment Facilities Deferred postretirement and postemployment benefit costs are          Deferred costs of decommissioning federal uranium enrichment the costs we recorded under SFAS No. 106 (for postretirement          facilities are the unamortized portion of our required contribu benefits) and No. 112 (for postemployment benefits) in excess          tions to a fund for decommissioning and decontaminating the of the costs we included in the rates we charge our customers.         Department of Energy's uranium enrichment facilities. We are We began amortizing these costs over a 15-year period in               required, along with other domestic utilities, by the Energy 1998. We discuss these costs further in Note 6 on page 62.             Policy Act of 1992 to make contributions to the fund. The In 1999, we reclassified the electric generation-related portion      contributions are generally payable over 15 years with escala of this regulatory asset to the electric generation-related            tion for inflation and are based upon the proportionate amount regulatory asset discussed earlier in this note.                       of uranium enriched by the Department of Energy for each utility. We are amortizing these costs over the contribution period as a cost of fuel. We also discuss this in Note 1 on page 50.
(3,087.5)
Deferred Nuclear Expenditures Deferred nuclear expenditures are the net unamortized balance        In 1999, these expenditures were reclassified to the electric of certain operations and maintenance costs at Calvert Cliffs.       generation-related regulatory asset discussed earlier in this note.
Net plant in service 5,154.0 5,276.9 Construction work in progress 222.3 223.0 Nuclear fuel (net of amortization) 133.8 132.5 Plant held for future use 13.0 24.3 Net utility plant 5,523.1 5,656.7 Deferred Charges Regulatory assets (net) 637.4 565.7 Other 51.9 55.1 Total deferred charges 689.3 620.8 Total Assets $9,683.8 $9,275.0 See Notes to Consolidated Financial Statements.
These expenditures consist of:
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
  "*costs incurred from 1979 through 1982 for inspecting and           Deferred Environmental Costs repairing seismic pipe supports,                                  Deferred environmental costs are the estimated costs of
Constellation Energy Group Inc. and Subsidiaries 1999
  "*expenditures incurred from 1989 through 1994 associated          investigating and cleaning up contaminated sites we own.
( Consolidated BaLance Sheets 4t December 31.Liabilities and Capitalization Current Liabilities Short-term borrowings Current portions of long-term debt and preference stock Accounts payable Customer deposits Liabilities from energy trading activities Dividends declared Accrued taxes Accrued interest Accrued vacation costs Other Total current liabilities Deferred Credits and Other Liabilities Deferred income taxes Postretirement and postemployment benefits Deferred investment tax credits Decommissioning of federal uranium enrichment facilities Other Total deferred credits and other liabilities Capitalization Long-term debt BGE preference stock not subject to mandatory redemption Common shareholders' eauitv Total capitalization 5,758.4 6,299.6 Commitments, Guarantees, and Contingencies (see Note 10) Total Liabilities and Capitalization
with nonrecurring phases of certain nuclear operations            We discuss this further in Note 10 on page 69. We are projects, and                                                     amortizing $21.6 million of these costs (the amount we had
$9,683.8 $9,275.0 See Notes to Consolidated Financial Statements.
  "*expenditures incurred during 1990 for investigating leaks        incurred through October 1995) over a 10-year period in in the pressurizer heater sleeves.                                accordance with the Maryland PSC's November 1995 order.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
In 1999, these expenditures were reclassified to the electric generation-related regulatory asset discussed earlier in this note. Deferred Fuel Costs As described in Note 1 on page 50, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases Deferred Conservation Expenditures and sales of electricity, and natural gas and our fuel rate Deferred conservation expenditures include two components:
Constellation Energy Group Inc. and Subsidiaries 1999 1998 (In millions)$$ 371.5 808.3 365.1 40.6 163.8 66.1 19.2 55.3 35.3 78.2 2,003.4 541.7 270.5. 35.5 99.0 66.1 6.5 58.6 34.7 45.3 1,157.9 1,309.1 217.0 118.0 30.8 142.6 1,817.5 3,128.1 190.0 2,981.5 1,288.8 269.8 109.6 27.2 226.6 1,922.0 2,575.4 190.0 2,993.0 I F ( Consolidated Statements of Cash FLows Year Ended December 31, 1999 1998 1997 (In millions)
revenues collected from customers. We reduce deferred fuel
Cash Flows From Operating Activities Net income $ 260.1 $ 305.9 $ 254.1 Adjustments to reconcile to net cash provided by operating activities Extraordinary loss 66.3 -Depreciation and amortization 505.9 429.4 396.8 Deferred income taxes 13.0 17.5 7.4 Investment tax credit adjustments (8.6) (8.8) (7.5) Deferred fuel costs (61.1) (8.3) 18.3 Accrued pension and postemployment benefits 36.1 41.6 (18.0) Write-off of merger costs --57.9 Write-downs of real estate investments 8.3 23.7 70.8 Write-down of financial investment 26.2 -Write-downs of power projects 28.5 -Equity in earnings of affiliates and joint ventures (net) (7.6) (54.5) (42.5) Changes in assets from energy trading activities (179.1) (123.6) (9.4) Changes in liabilities from energy trading activities 64.8 90.4 8.6 Changes in other current assets (216.4) 18.3 (54.7) Changes in other current liabilities 121.0 77.0 42.6 Other 21.6 (8.8) (28.1)Net cash provided by operating activities 679.0 799.8 696.3 Cash Flows From Investing Activities Utility construction and other capital expenditures (436.2) (406.1) (443.9) Contributions to nuclear decommissioning trust fund (17.6) (17.6) (17.6) Merger costs -(20.9) Purchases of marketable equity securities (27.3) (33.3) (23.0) Sales of marketable equity securities 34.9 32.8 46.5 Other financial investments 13.7 14.6 (0.4) Real estate projects and investments 49.3 21.5 24.2 Power projects (171.1) (252.5) (44.3) Other (60.8) (70.7) (41.4) Net cash used in investing activities (615.1) (711.3) (520.8)Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 2,801.9 1,962.2 2,719.0 Long-term debt 302.8 831.3 622.0 Common stock 9.6 51.8 Repayment of short-term borrowings (2,430.4)
  "*operations costs (labor, materials, and indirect costs)           costs as we collect them from or refund them to our customers.
(2,278.3)
associated with conservation programs approved by the We show our deferred fuel costs in the following table.
(2,736.1)
Maryland PSC, which we are amortizing over periods of four to five years in accordance with the Maryland PSC's         At December 31,                               1999           1998 orders, and                                                                                                         (In millions)
Reacquisition of long-term debt (584.4) (355.2) (343.3) Redemption of preference stock (7.0) (127.9) (104.5) Common stock dividends paid (251.1) (246.0) (239.2) Other 13.7 84.7 2.5 Net cash used in financing activities (144.9) (77.4) (79.6) Net (Decrease)
Electric                                      $60.0        $(11.5)
Increase in Cash and Cash Equivalents (81.0) 11.1 95.9 Cash and Cash Equivalents at Beginning of Year 173.7 162.6 66.7 Cash and Cash Equivalents at End of Year $ 92.7 $ 173.7 $ 162.6 Other Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized)
  "*revenues we collected from customers in 1996 in excess            Gas                                            13.8          24.2 of our profit limit under the conservation surcharge.
$ 245.3 $ 236.7 $ 224.2 Income taxes $165.6 $ 164.3 $ 171.2 Noncash Investing and Financing Activities:
Deferred fuel costs (net)                    $73.8         $12.7 In 1999, we wrote-off a portion of the unamortized electric conservation expenditures that will not be recovered under the Restructuring Order as discussed in Note 4 on page 59.             Under the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC.
In 1998, Corporate Office Properties Trust (COPT) assumed approximately
ConstellationEnergy Group Inc. and Subsidiaries
$62 million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0 million common shares and 985,000 convertible preferred shares. In exchange, COPT received 14 operating properties and two properties under development from CREG. See Notes to Consolidated Financial Statements.
 
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
CNote 6.                                                                                                                               /
Constellation Energy Group Inc. and Subsidiaries SConsoLidated Statements of Common Shareholders' Equity Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 1999, 1998, and 1997 Shares Amount Earnings (Loss) Income Amount (Dollar amounts in millions, number of shares in thousands)
Pension, Postretirement, Other Postemployment, and EmpLoyee Savings Plan Benefits We offer pension, postretirement, other postemployment, and        Postretirement Benefits employee savings plan benefits. We describe each of these          We sponsor defined benefit postretirement health care and separately below.                                                   life insurance plans which cover nearly all Constellation Energy and BGE employees, and certain employees of our subsidiaries. Generally, we calculate the benefits under these Pension Benefits plans based on age, years of service, and pension benefit We sponsor several defined benefit pension plans for our levels. We do not fund these plans.
Balance at December 31, 1996 147,667 $1,429.9 $1,419.1 $5.7 $2,854.7 Net income 254.1 254.1 Common stock dividends declared ($1.63 per share) (240.7) (240.7) Other 3.1 3.1 Net unrealized loss on securities (1.2) (1.2) Deferred taxes on net unrealized loss on securities 0.4 0.4 Balance at December 31, 1997 147,667 1,433.0 1,432.5 4.9 2,870.4 Net income 305.9 305.9 Common stock dividend declared ($1.67 per share) (248.1) (248.1) Common stock issued 1,579 51.8 51.8 Other 0.3 0.3 Net unrealized gain on securities 1.8 1.8 Deferred taxes on net unrealized gain on securities (0.6) (0.6) Balance at December 31, 1998 149,246 1,485.1 1,490.3 6.1 2,981.5 Net income 260.1 260.1 Common stock dividend declared ($1.68 per share) (251.3) (251.3) ýommon stock issued 310 9.6 9.6 "----Other (0.7) (0.7) Net unrealized loss on securities (9.6) (9.6) Deferred taxes on net unrealized loss on securities 3.4 3.4 Balance at December 31, 1999 149,556 $1,494.0 $1,499.1 $(0.1) $2,993.0 See Notes to Consolidated Financial Statements.
employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information        For nearly all of the health care plans, retirees make contribu about the participant. Our employees do not contribute to          tions to cover a portion of the plan costs. Contributions for these plans. Generally, we calculate the benefits under these      employees who retire after June 30, 1992 are calculated based plans based on age, years of service, and pay.                     on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the Sometimes we amend the plans retroactively. These retroactive life insurance plan, retirees do not make contributions to cover plan amendments require us to recalculate benefits related to a portion of the plan costs.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over      Effective January 1, 1993, we adopted SFAS No. 106, the average remaining service period of active employees.           Employers' Accounting for PostretirementBenefits Other Than Pensions. The adoption of that statement caused:
Constellation Energy Group Inc. and Subsidiaries Consolidated Statements of Capitalization At December 31, 1999 1998 (In millions)
In 1999, our Board of Directors approved the following amendments:                                                            "*a transition obligation, which we are amortizing over 20 years, and
Long-Term Debt First Refunding Mortgage Bonds of BGE Floating rate series, due April 15, 1999 $ -$ 125.0 8.40% Series, due October 15, 1999 -91.1 5X% Series, due July 15, 2000 124.3 125.0 8 3 A% Series, due August 15, 2001 122.3 122.3 7Y4% Series, due July 1, 2002 124.5 124.5 5%% Installment Series, due July 15, 2002 8.5 9.1 6X% Series, due February 15, 2003 124.8 124.8 6%% Series, due July 1, 2003 124.9 124.9 5!% Series, due April 15, 2004 125.0 125.0 Remarketed floating rate series, due September 1, 2006 125.0 125.0 7A% Series, due January 15, 2007 123.5 123.5 6%% Series, due March 15, 2008 124.9 124.9 7X% Series, due March 1, 2023 109.9 125.0 7X% Series, due April 15, 2023 84.1 84.1 Total First Refunding Mortgage Bonds of BGE 1,321.7 1,554.2 Other long-term debt of BGE Medium-term notes, Series B 60.0 60.0 Medium-term notes, Series C 101.0 116.0 Medium-term notes, Series D 128.0 215.0 Medium-term notes, Series E 200.0 200.0 Medium-term notes, Series G 200.0 140.0 Medium-term notes, Series H 177.0 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Variable rate pollution control loan, due June 1, 2027 8.8 8.8 Total other long-term debt of BGE 1,135.8 1,000.8 BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0 Long-term debt of diversified businesses Loans under revolving credit agreements 33.0 74.0 Mortgage and construction loans 7.90% mortgage note, due September 12, 2000 8.0 8.3 8.00% mortgage note, due July 31, 2001 0.1 0.1 8.00% mortgage note, due October 30, 2003 1.9 1.8 Variable rate mortgage notes and construction loans, due through 2004 112.0 149.5 4.25% mortgage note, due March 15, 2009 4.6 5.1 9.65% mortgage note, due February 1, 2028 9.6 9.6 8.00% mortgage note, due November 1, 2033 6.6 5.8 Unsecured notes 511.0 616.0 Total long-term debt of diversified businesses 686.8 870.2 Unamortized discount and premium (10.6) (12.4) Current portion of long-term debt (808.3) (534.7) Total long-term debt $2,575.4 $3,128.1 continued on page 4 See Notes to Consolidated Financial Statements.
    " eligible participants will be allowed to choose between an enhanced version of the current benefit formula and a new        "*an increase in annual postretirement benefit costs.
Constellation Energy Group Inc. and Subsidiaries Consolidated Statements of Capitalization 4t December 31, 1999 1998 (In millions)
pension equity plan (PEP) formula. Pension benefits for        For our diversified businesses, we expense all postretirement eligible employees hired after December 31, 1999 will be      benefit costs. For our utility business, we accounted for the based on a PEP formula, and                                    increase in annual postretirement benefit costs under two
BGE Preference Stock Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.85%, 1991 Series $ -$ 7.0 Current portion of redeemable preference stock -(7.0) Total redeemable preference stock -Preference stock not subject to mandatory redemption 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 Total preference stock not subject to mandatory redemption 190.0 190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 149,556,416 and 149,245,641 shares issued and outstanding at December 31, 1999 and 1998, respectively. (At December 31, 1999 166,893 shares were reserved for the Employee Savings Plan and 12,061,756 shares were reserved for the Shareholder Investment Plan.) Retained earnings Accumulated other comprehensive (loss) income Total common shareholders' equity Total Capitalization 1,494.0 1,499.1 (0.1) 2,993.0 $5.758.4 1,485.1 1,490.3 6.1 2,981.5 $6.299.6 See Notes to Consolidated Financial Statements.
    " pension and survivor benefits were increased for participants  Maryland PSC rate orders:
who retired prior to January 1, 1994 and for their surviving      "*in an April 1993 rate order, the Maryland PSC allowed spouses.                                                           us to expense one-half and defer, as a regulatory asset The financial impacts of the amendments are included in the              (see Note 5), the other half of the increase in annual tables on page 63.                                                      postretirement benefit costs related to our electric and gas businesses, and Also during 1999, our Board of Directors approved a Targeted Voluntary Special Early Retirement Program                    "*in a November 1995 rate order, the Maryland PSC allowed (TVSERP) to provide enhanced early retirement benefits                  us to expense all of the increase in annual postretirement to certain eligible participants in targeted jobs that elect to          benefit costs related to our gas business.
retire on June 1, 2000. The financial impacts of the TVSERP          Beginning in 1998, the Maryland PSC authorized us to:
will be reflected in the second quarter of 2000.
                                                                        "*expense all of the increase in annual postretirement benefit We fund the plans by contributing at least the minimum                  costs related to our electric business, and amount required under Internal Revenue Service regulations.
                                                                        "*amortize the regulatory asset for postretirement benefit We calculate the amount of funding using an actuarial method costs related to our electric and gas businesses over 15 years.
called the projected unit credit cost method. The assets in all of the plans at December 31, 1999 were mostly marketable equity and fixed income securities, and group annuity contracts.
Constellation Energy Group Inc. and Subsidiaries
Constellation Energy Group Inc. and Subsidiaries
$6299.6 F Year Ended December 31, 1999 1998 1997 (Dollar amounts in millions)
 
Income Taxes Current $182.0 $169.5 $158.1 Deferred Change in tax effect of temporary differences 9.6 14.2 (1.0) Change in income taxes recoverable through future rates -3.9 8.0 Deferred taxes credited (charged) to shareholders' equity 3.4 (0.6) 0.4 Deferred taxes charged to expense 13.0 17.5 7.4 Investment tax credit adjustments (8.6) (8.8) (7.5) Income taxes per Consolidated Statements of Income $186.4 $178.2 $158.0 Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends)
I Obligations, Assets, and Funded Status                                                                            Pension          Postretirement Ze show the change in the benefit obligations, plan assets,                                                       Benefits            Benefits and funded status of the pension and postretirement benefit                                                    1999     1998       1999    1998 plans in the following table:                                                                                              (In millions)
$526.3 $505.9 $440.8 Statutory federal income tax rate 35% 35% 35% Income taxes computed at statutory federal rate 184.2 177.1 154.3 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 15.3 13.6 13.9 Allowance for equity funds used during construction (2.2) (2.2) (1.9) Amortization of deferred investment tax credits (8.6) (8.8) (7.5) Tax credits flowed through to income (3.2) (0.3) (0.5) Amortization of deferred tax rate differential on regulated activities (3.0) (2.3) (2.3) State income taxes 8.9 9.8 6.2 Other (5.0) (8.7) (4.2) Total income taxes $186.4 $178.2 $158.0 Effective federal income tax rate 35.4% 35.2% 35.8%At December 31, Deferred Income Taxes Deferred tax liabilities Accelerated depreciation Allowance for funds used during construction Income taxes recoverable through future rates Deferred termination and postemployment costs Deferred fuel costs Leveraged leases Percentage repair allowance Conservation expenditures Energy trading activities Deferred electric generation-related regulatory assets Other Total deferred tax liabilities Deferred tax assets Accrued pension and postemployment benefit costs Deferred investment tax credits Capitalized interest and overhead Contributions in aid of construction Nuclear decommissioning liability Energy trading activities Other Total deferred tax assets Deferred tax liability, net 1999 1998 (Dollar amounts in millions)$ 962.7 202.3 35.7 14.7 25.8 19.9 35.0 4.7 71.4 100.3 187.9 1,660.4 63.6 38.3 48.3 49.1 25.4 15.1 131.8 371.6 $1,288.8$1,009.9 204.5 88.4 32.3 4.5 22.6 36.8 18.9 33.4 182.6 1,633.9 54.3 41.3 46.6 45.6 22.8 20.3 93.9 324.8 $1,309.1 Q Consolidated Statements of Income Taxes )See Notes to Consolidated Financial Statements.
Pens ion          Postretirement    Funded Status Bene-fits              Benefits      Funded status at 1999      1998        1999      1998    December 31                    $ 68.2    $(45.8) $(358.7) $(383.1)
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
(In millions)                  Unrecognized net Change in benefit obligation                                                  actuarial (gain) loss            (27.2)   137.6        23.6        59.7 Benefit obligation at                                                      Unrecognized prior January 1                $ 1,031.3 $ 902.0        $383.1                service cost                      59.0      16.9        (0.1)
Constellation Energy Group Inc. and Subsidiaries Notes to Consolidated Financial Statements
                                                                    $320.3 Service cost                      26.1        21.6          8.6      6.6  Unrecognized Interest cost                    65.3        63.0        24.4      23.4    transition obligation              -          -        143.4      159.3 Plan participants'                                                        Unamortized net asset from contributions                    -          -          2.0      2.0    adoption of SFAS No. 87          (0.5)     (0.7)       -
~Note 1. ,--4 ignificant Accounting Policies Nature of Our Business On April 30, 1999, Constellation Energy Group, Inc. (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE) and BGE's former subsidiary Constellation Enterprises, Inc. BGE's outstanding common stock automatically became shares of common stock of Constellation Energy. BGE's debt securities, obligated mandatorily redeemable trust preferred securities, and preference stock remain securities of BGE. Constellation Energy's subsidiaries primarily include BGE and a group of energy services businesses mostly focused on power marketing and merchant generation in North America.
Actuarial (gain) loss            (93.0)     102.9        (34.2)     48.9  Prepaid (accrued) benefit Plan amendments                  44.6          -        (5.0)               cost                            $99.5    $108.0      $(191.8) $164.1)
BGE is an electric and gas public utility company with a service territory that covers the City of Baltimore and all or part of ten counties in Central Maryland.
Benefits paid                    (57.6)      (58.2)      (20.2)     (18.1)
We describe our operating segments in Note 2 on page 54. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively.
Benefit obligation at December 31              $ 1,016.7 $1,031.3        $358.7    $383.1    Net Periodic Benefit Cost We show the components of net periodic pension benefit cost in the following table:
Reference in this report to the "utility business" is to BGE.  "onsolidation Policy ,-,,_Ve use three different accounting methods to report our investments in our subsidiaries or other companies:
Pension            Postretirement Benefits                Benefits      Year Ended December 31,                       1999        1998        1997 1999    1998          1999       1998                                                         (In millions)
consolidation, the equity method, and the cost method. Consolidation We use consolidation when we own a majority of the voting stock of the subsidiary.
(In millions)               Components of net periodic
This means the accounts of our subsidiaries are combined with our accounts.
-_, ,2hange in plan assets                                                        pension benefit cost Fair value of plan assets at                                              Service cost                                $26.1        $21.6    $16.8 January 1                  $ 985.5    $912.3       $-        $        Interest cost                                  65.3        63.0        61.3 Actual return on                                                          Expected return on plan assets                (76.6)      (72.1)    (66.9) plan assets                  139.4       116.9          -              Amortization of transition Employer contribution            17.6       14.5        18.2      16.1     obligation                                  (0.2)      (0.2)      (0.2)
We eliminate intercompany balances and transactions when we consolidate these accounts.
Plan participants'                                                        Amortization of prior service cost              2.5        2.5        2.5 contributions                    -          -          2.0        2.0  Recognized net actuarial loss                  10.1         5.6        4.6 Benefits paid                    (57.6)    (58.2)      (20.2)    (18.1) Amount capitalized as Fair value of plan assets                                                    construction cost                            (4.2)      (3.8)       (2.5) at December 31            $1,084.9    $985.5        $ -        $-      Net periodic pension benefit cost            $23.0        $16.6    $15.6 ConstellationEnergy Group Inc. and Subsidiaries
Our consolidated financial statements include the accounts of: "* Constellation Energy, "* BGE and its subsidiaries, "* Constellation Enterprises, Inc. and its subsidiaries, and "* Constellation Nuclear Group, LLC and its subsidiaries.
 
The Equity Method We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest.
We show the components of net periodic postretirement                    Other Postemployment Benefits benefit cost in the following table:                                    We provide the following postemployment benefits:
Under the equity method, we report: our interest in the entity as an investment in our Consolidated Balance Sheets beginning on page 42, and our percenitage share of the earnings from the entity in our Consolidated Statements of Income on page 41.The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation.
Year Ended December 31,                    1999        1998        1997  "*health and life insurance benefits to our employees and (In millions)            certain employees of our subsidiaries who are found to be Components of net periodic                                                  disabled under our Disability Insurance Plan, and postretirement benefit cost                                           "*income replacement payments for employees found to be Service cost                              $ 8.6      $ 6.6      $ 5.4      disabled before November 1995 (payments for employees Interest cost                              24.4        23.4      21.8      found to be disabled after that date are paid by an insur Amortization of transition                                                  ance company, and the cost is paid by employees).
BGE reports its investment in Safe Harbor Water Power Corporation (Safe Harbor) under the equity method. Safe Harbor is a producer of hydroelectric power. BGE owns two-thirds of Safe Harbor's total capital stock, including one-half of the voting stock, and a two-thirds interest in its retained earnings.
obligation                              11.0        11.4      11.4  The liability for these benefits totaled $46.5 million as of Recognized net actuarial loss                1.9        0.2        0.1  December 31, 1999 and $52.9 million as of December 31, 1998.
This investment is included in "Investments and Other Assets -Other" in our Consolidated Balance Sheets on page 42. The Cost Method We usually use the cost method if we hold less than a 20% voting interest in an investment.
Amount capitalized as construction cost                        (9.4)     (8.1)      (7.6) Effective December 31, 1993, we adopted SFAS No. 112, Amount deferred                              -         -         (7.2) Employers' Accounting for Postemployment Benefits. We Net periodic postretirement                                              deferred, as a regulatory asset (see Note 5 on page 61), the benefit cost                           $36.5      $33.5      $23.9  postemployment benefit liability attributable to our utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described Assumptions                                                              earlier in this note). We began to amortize the regulatory asset We made the assumptions below to calculate our pension and               over 15 years beginning in 1998. The Maryland PSC authorized postretirement benefit obligations.                                      us to reflect this change in our current electric and gas base Pension            Postretirement    rates to recover the higher costs in 1998.
Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method. Regulation of Utility Business The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses.
Benefits              Benefits      We assumed the discount rate for other postemployment At December 31,                1999      1998        1999      1998  benefits to be 5.5% in 1999 and 4.5% in 1998.
Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles.
Discount rate                  7.25%    6.50%      7.25%      6.50%
However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers.
Expected return on plan assets                  9.00      9.00        N/A        N/A    Employee Savings Plan Benefits Rate of compensation                                                    We also sponsor a defined contribution savings plan that increase                    4.00      4.00        4.00      4.00    is offered to all eligible Constellation Energy and BGE employees, and certain employees of our subsidiaries.
When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities.
In a defined contribution plan, the benefits a participant We assumed the health care inflation rates to be:                        is to receive result from regular contributions to a participant
We have recorded these regula tory assets and liabilities in our Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation.
    "*in 1999, 6.0% for both Medicare-eligible retirees and               account. Under this plan, we make matching contributions retirees not covered by Medicare, and                               to participant accounts. We made matching contributions
We summarize and discuss our regulatory assets and liabilities further in Note 5 on page 60. In 1997, the Financial Accounting Standards Board (FASB) through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statements No. 71 and 101. The EITF concluded that a company should cease to apply SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregu lated portion of the business.
    "*in 2000, 7.0% for Medicare-eligible retirees and 8.5% for           to this plan of:
Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery.Constellation Energy Group Inc. and Subsidiaries I I On November 10, 1999, the Maryland PSC issued a Restructuring Order that we believe provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business.
retirees not covered by Medicare.                                    * $10.4 million in 1999, After 2000, we assumed both inflation rates will decrease by              * $10.1 million in 1998, and 0.5% annually to a rate of 5.5% in the years 2003 and 2006,               * $8.5 million in 1997.
Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises
respectively. After these dates, the inflation rate will remain at 5.5%.
-Accounting for the Discontinuation of FASB Statement No. 71 and EITF No. 97-4 for BGE's electric generation business.
A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretire ment benefit obligation by approximately $46.7 million as of December 31, 1999 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.4 million annually.
BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated.
A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretire ment benefit obligation by approximately $37.4 million as of December 31, 1999 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.2 million annually.
We discuss this further in Note 4 on page 58. Utility Revenues We record utility revenues in our Consolidated Statements of Income when we provide service to customers.
i.ConstellationEnergy Group Inc. and Subsidiaries
Fuel and Purchased Energy Costs We incur costs for: "* the fuel we use to generate electricity, "* purchases of electricity from others, and "* natural gas that we resell. These costs are shown in our Consolidated Statements of Income as "Electric fuel and purchased energy" and "Gas purchased for resale." We discuss each of these separately below. Fuel Used to Generate Electricity and Purchases of Electricity From Others Until July 1, 2000, we will continue to recover our costs of electric fuel under the electric fuel rate clause set by the Maryland PSC. Under the electric fuel rate clause, we charge our electric customers for: "* the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and "* the net cost of purchases and sales of electricity.
 
We charge the actual costs of these items to customers with no profit to us. To do this, we must keep track of what we spend and what we collect from customers under the fuel rate in a given period. Usually these two amounts are not the same because there is a difference between the time we spend the money and the time we collect it from our customers.
Under the electric fuel rate clause, we currently defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the differ ence between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss this and the impact of the Restructuring Order on BGE's electric fuel rate clause further in Note 5 on page 61.We calculate the electric fuel rate using three factors: "* the mix of generating plants we used over the last 24 months, "* the latest three-month average fuel cost for each generating unit, and "* the net cost of purchases and sales of electricity over the last 24 months. Historically, we were able to change the fuel rate only if the calculated rate was more than 5% above or below the rate in effect. The fuel rate was affected most by the amount of electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal, gas, or oil. As a result of the Restructuring Order, the fuel rate is frozen at its current level until July 1, 2000, at which time it will be discontinued.
We will continue to defer the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate through June 30, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. Extended outages at Calvert Cliffs increase fuel costs. Any increase in fuel costs, including extended outages at Calvert Cliffs through June 30, 2000, may result in fuel rat,,, proceedings before the Maryland PSC. In these proceedings, the Maryland PSC would consider whether any portion of the extra fuel costs should be paid by BGE instead of passed on to customers.
We also report two other items as "Electric fuel and purchased energy" in our Consolidated Statements of Income: "* amortization of nuclear fuel (described under "Utility Plant" later in this note). We amortize nuclear fuel based on the energy produced over the life of the fuel. We pay quarterly fees to the Department of Energy for the future disposal of spent nuclear fuel, and accrue these fees based on the kilowatt-hours of electricity sold. We bill our customers for nuclear fuel as described earlier in this note, and "* amortization of deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities.
We discuss these costs further in Note 5 on page 61.Constellation Energy Group Inc. and Subsidiaries r
Natural Gas ,Ve charge our gas customers for the natural gas they purchase "--from us using "gas cost adjustment clauses" set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described earlier in this Note. However, the Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market based rates incentive mechanism.
Under market based rates our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers.
Risk Management We engage in risk management activities in our gas business and in our diversified businesses.
We separately describe these activities for each business below. Gas Business We use basis swaps in the winter months (November through March) to hedge our price risk associated with natural gas purchases under our market based rates incentive mechanism.
We also use fixed-to-floating and floating-to-fixed swaps to hedge our price risk associated with our off-system gas sales. The fixed portion represents a specific dollar amount that we will pay or receive and the floating portion represents a luctuating amount based on a published index that we will "ýrýeceive or pay. Our gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. BGE's off-system gas activities represent trading activities under EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities.
Accordingly, we use mark-to-market accounting to record these transactions.
We defer, as unrealized gains or losses, the changes in fair value of the swap agreements under the market based rates incentive mechanism and the customers' portion of off-system gas sales in our Consolidated Balance Sheets. When amounts are paid under the agreements, we report the payments as gas costs in our Consolidated Statements of Income. We report the changes in fair value for the shareholders' portion of off system gas sales in earnings as a component of gas costs.Diversified Businesses Our subsidiary, Constellation Power Source, engages in power marketing activities, which include trading electricity, other energy commodities, and related derivatives (such as futures, forwards, options, and swaps). Constellation Power Source uses the mark-to-market method of accounting for its trading activities.
Under the mark-to-market method of accounting, we report: "* commodity positions and derivatives at fair value as "Assets from energy trading activities" or "Liabilities from energy trading activities" in our Consolidated Balance Sheets, and "* changes in fair value as components of "Diversified business revenues" in our Consolidated Statements of Income. Taxes We summarize our income taxes in our Consolidated Statements of Income Taxes on page 48. As you read this section, it may be helpful to refer to those statements.
Income Tax Expense We have two categories of income taxes in our Consolidated Statements of Income-current and deferred.
We describe each of these below. Our current income tax expense consists solely of regular tax less applicable tax credits.
Our deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to common shareholders' equity. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this Note) during the year. Investment Tax Credits We have deferred the investment tax credit associated with our regulated utility business in our Consolidated Balance Sheets. The investment tax credit is amortized evenly to income over the life of each property.
We reduce income tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated diversified businesses, other than leveraged leases.Constellation Energy Group Inc. and Subsidiaries I I Deferred Income Tax Assets and Liabilities We must report some of our revenues and expenses differently for our financial statements than we do for income tax purposes.
The tax effects of the differences in these items are reported as deferred income tax assets or liabilities in our Consolidated Balance Sheets. We measure the assets and liabilities using income tax rates that are currently in effect. A portion of our total deferred income tax liability relates to our utility business, but has not been reflected in the rates we charge our customers.
We refer to this portion of the liability as "Income taxes recoverable through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 5 on page 60. State and Local Taxes Through December 31, 1999, we paid Maryland public service company franchise tax instead of state income tax on our utility revenue from sales in Maryland.
We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income. As discussed in Note 4 on page 58, the tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities.
Inventory We report the majority of our fuel stocks and materials and supplies at average cost. Real Estate Projects and Investments In Note 3 on page 56, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. The projects and investments consist of: "* land under development in the Baltimore-Washington corridor, "* a mixed-use planned-unit development, and "* an equity interest in Corporate Office Properties Trust, a real estate investment trust. The costs incurred to acquire and develop properties are included as part of the cost of the properties.
Financial Investments and Trading Securities In Note 3 on page 57, we summarize the financial investment that are in our Consolidated Balance Sheets. SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities.
We report those investments at fair value, and we use specific identification to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available-for-sale securities, which we describe separately below. We report investments that are not covered by SFAS No. 115 at their cost. Trading Securities Our diversified businesses classify some of their investments in marketable equity securities and financial limited partner ships as trading securities.
We include any unrealized gains or losses on these securities in "Diversified business revenues" in our Consolidated Statements of Income. Available-for-Sale Securities We classify our investments in the nuclear decommissioning trust fund as available-for-sale securities.
We include any unrealized gains or losses on the trust assets as a change in the decommissioning reserve. We describe the nuclear decommissioning trust and the reserve under the heading "Decommissioning Costs" later in this note on page 53. In addition, our diversified businesses classify some of their investments in marketable equity securities as available-for sale securities.
We include any unrealized gains or losses on these securities in "Accumulated other comprehensive (loss) income" in our Consolidated Statements of Common Shareholders' Equity on page 45 and in the Consolidated Statements of Capitalization on page 47. We also include our diversified businesses' portion of unrealized gains or losses on securities of equity-method (described earlier in this note) investees in our Consolidated Statements of Common Shareholders' Equity. Evaluation of Assets for Impairment SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, applies particular requirements to some of our assets that have long lives (some examples are utility property and equipment and real estate). We determine if those assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We recog nize an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset. See Note 4 on page 59 for further discussion.
Constellation Energy Group Inc. and Subsidiaries F
'Itility Plant, Depreciation, Amortization, )id Decommissioning
"ý4Jtility Plant Utility plant is the term we use to describe our utility business property and equipment that is in use, being held for future use, or under construction.
We summarize utility plant in our Consolidated Balance Sheets. We report our utility plant at its original cost, unless impaired under the provisions of SFAS No. 121. Our original cost includes:
"* material and labor, "* contractor costs, "* construction overhead costs (where applicable), and "* an allowance for funds used during construction (described later in this note). We charge retired or otherwise-disposed-of utility plant to accumulated depreciation.
We own an undivided interest in the Keystone and Conemaugh electric generating plants in Western Pennsylvania, as well as in the transmission line that transports the plants' output to the joint owners' service territories.
Our ownership interests in these plants are 20.99% in Keystone and 10.56% in Conemaugh.
These ownership interests represented a net investment of $156 million at December 31, 1999 and $152 million at December 31, 1998. We report these roperties in the same accounts we use for our other _._,tility plant (described above). Depreciation Expense Generally, we compute depreciation by applying composite, straight-line rates (approved by the Maryland PSC) to the average investment in classes of depreciable property.
We depreciate vehicles based on their estimated useful lives. Amortization Expense Amortization is an accounting process of reducing an amount in our Consolidated Balance Sheets evenly over a period of time. When we reduce amounts in our Consolidated Balance Sheets, we increase amortization expense in our Consolidated Statements of Income. An amount is considered fully amortized when it has been reduced to zero. Decommissioning Costs We must accumulate a reserve for the costs that we expect to incur in the future to decommission the radioactive portion of Calvert Cliffs. We do this based on a sinking fund methodology.
The Maryland PSC authorized us to record decommissioning expense based on a facility-specific cost estimate so we can accumulate a decommissioning reserve of $521 million in 1993 dollars by the end of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation.
We have reported the decommissioning reserve in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $287.5 million at December 31, 1999 and $244.0 million at December 31, 1998. To fund the costs we expect to incur to decommission the plant, we established an external decommissioning trust in accordance with Nuclear Regulatory Commission (NRC) regulations.
We report the assets in the trust in "Nuclear decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires utilities to provide financial assur ance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic NRC formula or a facility-specific decommissioning cost estimate.
We use the facility-specific cost estimate for funding these costs and providing the required financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest Allowance for Funds Used During Construction (AFC) We finance utility construction projects with borrowed funds and equity funds. We are allowed by the Maryland PSC to record the costs of these funds as part of the cost of construc tion projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized by the Maryland PSC. We bill our customers for the AFC plus a return after the utility plant is placed in service.
The AFC rates are 9.04% for gas plant, 9.35% for common plant, and 9.40% for electric plant. We compound AFC annually.
Capitalized Interest With the issuance of the Restructuring Order, we ceased accruing AFC for electric generation-related construction projects and began using SFAS No. 34, Capitalizing Interest Costs, to calculate the cost during construction of debt funds used to finance our electric generation-related construction projects.
Our diversified businesses capitalize interest costs incurred to finance real estate developed for internal use and certain power projects.Constellation Energy Group Inc. and Subsidiaries I
Long-Term Debt We defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) all costs related to the issuance of long-term debt. These costs include underwriters' commissions, discounts or premiums, and other costs such as legal, accounting, and regulatory fees, and printing costs. We amortize these costs over the life of the debt. When we incur gains or losses on debt that we retire prior to maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt. Cash Flows For the purpose of reporting our cash flows, we define cash equivalents as highly liquid investments that mature in three months or less. Use of Accounting Estimates Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles.
These estimates and assumptions affect various matters, including:
our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements,"* our disclosure of contingent assets and liabilities at the dates of the financial statements, and "* our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual amounts could differ from these estimates.
Reclassifications We have reclassified certain prior-year amounts for comparative purposes.
These reclassifications did not affect consolidated net income for the years presented.
Accounting Standards Issued In July 1999, the FASB issued SFAS No. 137 that delays the effective date for SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, by one year. Therefore, we must adopt the provisions of SFAS No. 133 in our financial statements for the quarter ended March 31, 2001. We have not determined the effects of SFAS No. 133 on our financial results.(Note 2.Information by Operating Segment.
We have three reportable operating segments-Electric, Gas, and Energy Services:
"* Our Electric business generates, purchases, and sells electricity, "* Our Gas business purchases, transports, and sells natural gas, and "* Our Energy Services businesses consist of certain diversified businesses that: -develop, own, and operate power projects, -provide power marketing and risk management services, -provide nuclear consulting services, -sell natural gas through mass marketing efforts, -sell and service electric and gas appliances, heating and air conditioning systems, and engage in home improvements, and -provide cooling services to commercial customers in Baltimore.
Our remaining diversified businesses:
"* engage in financial investments, and "* develop, own, and manage real estate and senior-living facilities.
These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies.
The segments have the same accounting policies as those described in the summary of significant accounting policies in Note 1. The Company evaluates the performance of these segments based on net income. We account for intersegment revenues using market prices. A summary of information by operating segment is shown on page 55. We are realigning our organization combining all of our domestic merchant energy businesses.
We have not determined the impact of this reorganization on our operating segments, but such changes will impact our operating segments in the future Constellation Energy Group Inc. and Subsidiaries r
Energy Electric Gas Services "Business Business Businesses Other Unallocated Diversified Corporate Businesses Items (a)Eliminations Consolidated 1999 Unaffiliated revenues Intersegment revenues (In millions)$2,258.8 1.2$476.5 11.6$ 937.0 30.4$113.9 (0.4}(42.8')$3,786.2 Total revenues 2,260.0 488.1 967.4 113.5 -(42.8) 3,786.2 Depreciation and amortization 376.4 44.9 23.1 5.2 0.2 -449.8 Equity in income of equity method investees (b) 5.1 ----5.1 Net interest expense 162.4 24.4 24.6 31.1 0.4 (1.4) 241.5 Income tax expense (benefit) 149.2 18.1 34.8 (12.1) (0.9) (2.7) 186.4 Extraordinary loss 66.3 --.. 66.3 Net income (loss) (c) 198.8 33.0 50.6 (19.3) (1.7) (1.3) 260.1 Segment assets 6,312.6 915.3 1,681.2 743.2 129.2 (97.7) 9,683.8 Utility construction expenditures 322.1 63.8 ---385.9 1998 Unaffiliated revenues $2,219.2 $449.4 $ 524.1 $165.4 $- $ -$3,358.1 Intersegment revenues 1.6 1.7 12.0 0.5 -(15.8) -Total revenues Depreciation and amortization Equity in income of equity method investees (b) Net interest expense Income tax expense (benefit)
Net income (loss) (d) Segment assets Utility construction expenditures
..1997 Unaffiliated revenues Intersegment revenues Total revenues Depreciation and amortization Equity in income of equity method investees (b) Net interest expense Income tax expense (benefit)
Net income (loss) (e) Segment assets Utility construction expenditures 2,220.8 313.0 5.0 164.9 146.6 259.6 6,342.8 279.0 $2,191.7 0.3 2,192.0 286.5 5.0 160.7 135.7 224.0 6,404.4 278.7 451.1 45.4 23.6 13.4 26.1 934.6 60.4 $521.6 521.6 39.3 20.3 13.9 25.6 907.7 94.5 536.1 9.2 16.0 34.1 43.4 1,315.0 $ 399.4 0.6 400.0 6.9 10.1 23.8 27.5 700.9 165.9 9.3 38.6 (15.8) (24.2) 811.6 $194.9 9.7 204.6 9.9 32.5 (13.5) (21.1) 885.4-(15.8) 3,358.1 0.2 377.1 (1.9) (0.1) (0.1) (14.0)(0.3) 1.1 (115.0)(10.6) (10.6) 0.3 6.4 (1.9) (3.6) 10.7 1.7 (9.1)5.0 240.9 178.2 305.9 9,275.0 339.4 $3,307.6 3,307.6 342.9 5.0 230.0 158.0 254.1 8,900.0 373.2 (a) We do not allocate certain items presented in the table for Constellation Energy Group and a holding company for our diversified businesses.  (b) Our Energy Services and our Other Diversified businesses record their equity in the income of equity method investees in their unaffiliated revenues.  (c) Our Electric business recorded costs of $4.9 million after-tax related to Hurricane Floyd as discussed in the "Electric Operations and Maintenance Expenses" section of Management's Discussion and Analysis on page 28. Our Other Diversified businesses recorded a $16.0 million write-down of its investment in Capital Re stock to reflect the market value of this investment as discussed in Note 3 and a $5.8 million write-down of certain senior-living facilities as discussed in the "Other Diversified Businesses" section of "Management's Discussion and Analysis on page 33. In addition, 3ur Energy Services businesses recorded $18.7 million in write-downs of certain power projects as discussed in Note 3.(d) Our Energy Services businesses recorded $10.4 million for its share of earnings in a partnership as discussed in Note 3 and a $5.5 million write-off of an energy services investment as discussed in the "Other Energy Services" section of Management's Discussion and Analysis on page 33. In addition, our Other Diversified businesses recorded a $15.4 million write-down of a real estate project as discussed in Note 3.  (e) Our Electric business recorded a $37.5 million write-off related to the terminated merger with Potomac Electric Power Company as discussed in the "Other Income and Expenses" section of Management's Discussion and Analysis on page 34. In addition, our Other Diversified businesses recorded a $46.0 million write down of two real estate projects as discussed in Note 3.Constellation Energy Group Inc. and Subsidiaries I I S_
I (Note 3. Investments Real Estate Projects and Investments Real estate projects and investments held by Constellation Real Estate Group (CREG), consist of the following:
At December 31, 1999 1998 (In millions)
Properties under development
$197.8 $210.6 Rental and operating properties (net of accumulated depreciation) 9.2 38.9 Equity interest in real estate investment trust 103.1 104.0 Other real estate ventures -0.4 Total real estate projects and investments
$310.1 $353.9 In 1999, CREG sold Church Street Station -an entertainment, dining, and retail complex in Orlando, Florida -for $11.5 million, the approximate book value of the complex.
In 1998, CREG recorded a $15.4 million after-tax write-down of the investment in Church Street Station that occurred because the fair value of the project declined based upon competitive bids. In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust based in Philadelphia, under which COPT assumed approxi mately $62 million of CREG's outstanding debt, paid CREG approximately
$22.8 million in cash, and issued to CREG approximately 7.0 million common shares representing a 41.9% equity interest in COPT and 985,000 convertible preferred shares. Each convertible preferred share yields 5.5% per year, and is convertible after two years from the date of the agreement into 1.8748 common shares. In exchange, COPT received 14 operating properties and two properties under development from CREG as well as certain other assets, options, and first refusal rights. These options and first refusal rights are related to approximately 91 acres of identified properties which are adjacent to operating properties acquired by COPT. At December 31, 1999, 48 acres remain under these options and first refusal rights and have terms that range from 1 to 4 years.In 1997, CREG recorded the following write-downs of real estate projects:
"* a $14.1 million after-tax write-down of the investment in Church Street Station that occurred because CREG decided to sell rather than keep the project, and "* a $31.9 million after-tax write-down of the investment in Piney Orchard-a mixed-use, planned-unit development that occurred because the expected future cash flow from the project was less than CREG's investment in the project.
Power Projects Power projects held by our diversified businesses consist of the following:
At December 31, 1999 1998 (In millions)
Domestic East $ 55.7 $ 46.0 West 475.6 427.4 International South America 12.3 21.6 Central America 241.8 248.1 Total power projects $785.4 $743.1 Our Domestic-West power projects include investments of $301.8 million in 1999 and $310.6 in 1998 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements.
We discuss these projects further in Note 10 on page 71. In 1999, our power projects business recorded a $14.2 million after-tax write-off of two geothermal power projects.
These write-offs occurred because the expected future cash flows from the projects are less than the investment in the projects.
For the first project, this resulted from the inability to restruc ture certain project agreements.
For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production.
In 1999, we recorded a $4.5 million after-tax write-down to reflect the fair value of our investment in a generating company in Bolivia as a result of our international exit strategy.
In 1998, our power projects business recorded $10.4 million after-tax gain for its share of earnings in a partnership.
The partnership recognized a gain on the sale of its ownership interest in a power sales contract.Constellation Energy Group Inc. and Subsidiaries Financial Investments inancial investments held by Constellation Investments, Inc. consist of the following:
At December 31, 1999 1998 (In millions)
Insurance company $ -$102.5 Marketable equity securities 84.2 25.3 Financial limited partnerships 35.8 41.9 Leveraged leases 25.4 28.3 Total financial investments
$145.4 $198.0 In 1999, our financial investments business announced that it would exchange its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE), another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock of Capital Re. Through September 30, 1999, our financial investments business wrote-down its $94.2 million investment in Capital Re stock by $20.9 million after-tax to reflect the market value of this investment.
The agreement between ACE and Capital Re was subsequently revised on a more favorable basis for Capital Re to include both cash and kCE stock. In December 1999, the transaction was finalized our financial investments business recorded a $4.9 million after-tax gain on this investment to reflect the closing price of the business combination.
As a result of this business combination, this investment no longer qualifies as an equity-method investment.
Accordingly, in 1999, we have included this investment in the marketable equity securities amount above. Investments Classified as Available-for-Sale We classify our investments in the nuclear decommissioning trust fund as available-for-sale.
In addition, we classify some of our diversified businesses' marketable equity securities (shown above) as available-for-sale.
This means we do not expect to hold them to maturity and we do not consider them trading securities.
We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, exclusive of $6.2 million in 1998 of unrealized net gains on securities held by Capital Re as an equity method investee, in the following tables.Amortized Unrealized Unrealized Fair At December 31, 1999 Cost Basis Gains Losses Value (In millions)
Marketable equity securities
$167.1 $42.8 $(2.1) $207.8 Corporate debt and U.S. Government agency 14.4 --14.4 State municipal bonds 74.2 -(0.8) 73.4 Totals $255.7 $42.8 $(2.9) $295.6 Amortized Unrealized Unrealized Fair At December 31, 1998 Cost Basis Gains Losses Value (In millions)
Marketable equity securities
$ 82.9 $24.2 $(0.4) $106.7 Corporate debt and U.S. Government agency 12.7 0.4 -13.1 State municipal bonds 64.8 2.7 -67.5 Totals $160.4 $27.3 $(0.4) $187.3 The above tables include $40.5 million in 1999 and $23.9 million in 1998 of unrealized net gains associated with the nuclear decommissioning trust fund which are reflected as a change in the nuclear decommissioning trust fund on the Consolidated Balance Sheets. Gross and net realized gains and losses on available-for-sale securities were as follows: Year Ended December 31, 1999 1998 1997 (In millions)
Gross realized gains $11.7 $4.2 $9.3 Gross realized losses (38.8) (0.7) (0.6) Net realized (losses) gains $(27.1) $3.5 $8.7 The Corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule:
At December 31, 1999 Amount (In millions)
Less than 1 year $ 1.0 1-5 years 46.4 5-10 years 21.8 More than 10 years 18.6 Total maturities of debt securities
$87.8 Constellation Energy Group Inc. and Subsidiaries I I (Note 4. Rate Matters and Accounting Impacts of Deregulation On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that will significantly restructure Maryland's electric utility industry and modify the industry's tax structure.
In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities.
Effective January 1, 2000, the Maryland public service franchise tax will be altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland.
The Maryland 2% franchise tax on electric and natural gas utilities will continue to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results will become subject to the Maryland corporate income tax. Beginning July 1, 2000, the tax legislation also provides for a two-year phase-in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolves the major issues surrounding electric restructuring, accelerates the timetable for customer choice, and addresses the major provisions of the Act. The Restructuring Order also resolves the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are: " All customers, except a few commercial and industrial companies that have signed contracts with BGE, will be able to choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an altemative supplier.
In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE.  " BGE's current electric base rates are frozen at their current levels until July 1, 2000."* BGE will reduce residential base rates by approximately 6.5% on average, about $54 million a year, beginning July 1, 2000. These rates will not change before July 2006.  "* Commercial and industrial customers will have up to four service options that will fix electric energy rates and transition charges for a period that generally ranges from four to six years.  "* Electric delivery service rates will be frozen for a four year period for commercial and industrial customers.
The generation and transmission components of rates will be frozen for different time periods depending on the service options selected by those customers. 
"* BGE will be allowed to recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on customers' bills. Residential customers will pay this charge for six years. Commercial and industrial customers will pay in a lump sum or over the four to six-year period, depending on the service option selected by each customer. 
"* Generation-related regulatory assets and nuclear decom missioning costs will be included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their existing amortization schedules. 
"* Starting July 1, 2000, BGE will unbundle rates to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and taxes.  "* On July 1, 2000, BGE will transfer, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy.  "* BGE will reduce its generation assets, as described later in this section, by $150 million pre-tax during the period July 1, 1999 -June 30, 2000 to mitigate a portion of its potentially stranded investments. 
"* Universal service will be provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually.Constellation Energy Group Inc. and Subsidiaries V
As discussed in Note 1 on page 49, EITF 97-4 requires that / company should cease applying SFAS No. 71 when either "-legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business.
Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery.
We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business.
Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101 and EITF 97-4 for BGE's electric generation business.
SFAS No. 101 requires the elimination of the effects of rate regulation that have been recognized as regulatory assets and liabilities pursuant to SFAS No. 71. However, EITF 97-4 requires that regulatory assets and liabilities that will be recovered in the regulated portion of the business continue to be classified as regulatory assets and liabilities.
The Restructuring Order provides for the creation of a single, new generation-related regulatory asset to be recovered through BGE's regulated transmission and distribution business.
We discuss this further in Note 5 on page 60.  `ursuant to SFAS No. 101, the book value of property, plant, equipment may not be adjusted unless those assets are impaired under the provisions of SFAS No. 121. The process of evaluating and measuring impairment under the provisions of SFAS No. 121 involves two steps. First, we must compare the net book value of each generating plant to the estimated undiscounted future net operating cash flows from that plant. An electric generating plant is considered impaired when its undiscounted future net operating cash flows are less than its net book value. Second, we compute the fair value of each plant that is determined to be impaired based on the present value of that plant's estimated future net operating cash flows discounted using an interest rate that considers the risk of operating that facility in a competitive environment.
To the extent that the net book value of each impaired electric genera tion plant exceeds its fair value, we must record a write-down.
Under the Restructuring Order, BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through the competitive transition charge component of its customer rates beginning July 1, 2000. This recovery mostly relates to the stranded costs associated with Calvert Cliffs, whose book value is substantially higher than its estimated fair value. However, Calvert Cliffs is not consid ered impaired under the provisions of SFAS No. 121 since its estimated future undiscounted cash flows exceed its book value. Accordingly, BGE did not record any impairment write-down related to Calvert Cliffs. However, we recognized after-tax impairment losses totaling $115.8 million associated with certain of our fossil plants under the provisions of SFAS No. 121. BGE has contracts to purchase electric capacity and energy that are expected to be uneconomic upon the deregulation of electric generation.
Therefore, we recorded a $34.2 million after-tax charge based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts.
In addition, BGE has deferred certain energy conservation expenditures that will not be recovered through its transmis sion and distribution business under the Restructuring Order. Accordingly, we recorded a $10.3 million after-tax charge to eliminate the regulatory asset previously established for these deferred expenditures.
At December 31, 1999, the total charge for BGE's electric generating plants that are impaired, losses on uneconomic purchased capacity and energy contracts, and deferred energy conservation expenditures was approximately
$160.3 million after-tax.
BGE recorded approximately
$94.0 million of the $160.3 million on its balance sheet. This consisted of a $150.0 million regulatory asset of its regulated transmission and distribution business, net of approximately
$56.0 million of associated deferred income taxes. The regulatory asset will be amortized as it is recovered from ratepayers through June 30, 2000. This will accomplish the $150 million reduction of its generation plants required by the Restructuring Order. We recorded an after-tax, extraordinary charge against earnings for approximately
$66.3 million related to the remaining portion of the $160.3 million described above that will not be recovered under the Restructuring Order.Constellation Energy Group Inc. and Subsidiaries I
SNote 5. ReguLatory Assets (net) As discussed in Note 1 on page 49, the Maryland PSC provides the final determination of the rates we charge our customers for our regulated businesses.
Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles.
However, sometimes the Maryland PSC orders an accounting treatment different from that used by nonregulated companies to determine the rates we charge our customers.
When this happens, we must defer certain utility expenses and income in our Consolidated Balance Sheets as regulatory assets and liabilities.
We then record them in our Consolidated Statements of Income (using amortization) when we include them in the rates we charge our customers.
We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below.At December 31.Generation plant reduction recoverable in current rates Electric generation-related regulatory asset Income taxes recoverable through future rates (net) Deferred postretirement and postemployment benefit costs Deferred nuclear expenditures Deferred conservation expenditures Deferred costs of decommissioning federal uranium enrichment facilities Deferred environmental costs Deferred fuel costs (net) Other (net) Total regulatory assets (net)19'99 1998 (In millions)$75.0 $ 286.6 110.4 41.9 12.9 31.3 73.8 5.5 $637.4 252.6 90.0 73.3 53.4 38.5 33.4 12.7 11.8 $565.7 Generation Plant Reduction Recoverable in Current Rates As a condition of the Maryland PSC's consolidation of the September 3, 1998 Office of People's Counsel petition to lower electric base rates with BGE's electric restructuring transition proposal, we agreed to make our rates subject to refund effective July 1, 1999. Under the Restructuring Order, BGE's rates are frozen through June 30, 2000. However, BGE was required to record a reduction to its generation plant of $150 million which it will recover through its current rates between July 1, 1999 and June 30, 2000. BGE recorded a $150 million regulatory asset for the required generation plant reduction that will be amortized as it is recovered from ratepayers through June 30, 2000. Electric Generation-Related Regulatory Asset With the issuance of the Restructuring Order, BGE no longer met the requirements for the application of SFAS No. 71 for the electric generation portion of its business.
In accordance with SFAS No. 101 and EITF 97-4, all individual generation related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities will be recovered in the regulated portion of the business.
Pursuant to the Restructuring Order, BGE wrote-off all of its \ individual, generation-related regulatory assets and liabilities.
A single, new generation-related regulatory asset was estab lished for amounts to be collected through BGE's regulated transmission and distribution business.
The new regulatory asset will be amortized on a basis that approximates the pre existing individual regulatory asset amortization schedules.
Income Taxes Recoverable Through Future Rates (net) As described in Note 1 on page 51, income taxes recoverable through future rates is the portion of our net deferred income tax liability that is applicable to our utility business, but has not been reflected in the rates we charge our customers.
These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.
In 1999, the electric generation-related portion of this regulatory asset is included in the electric generation-related regulatory asset discussed earlier in this note.Constellation Energy Group Inc. and Subsidiaries F At December 31I Deferred Postretirement and Postemployment 3enefit Costs Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers.
We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 6 on page 62. In 1999, we reclassified the electric generation-related portion of this regulatory asset to the electric generation-related regulatory asset discussed earlier in this note. Deferred Nuclear Expenditures Deferred nuclear expenditures are the net unamortized balance of certain operations and maintenance costs at Calvert Cliffs. These expenditures consist of: "* costs incurred from 1979 through 1982 for inspecting and repairing seismic pipe supports, "* expenditures incurred from 1989 through 1994 associated with nonrecurring phases of certain nuclear operations projects, and "* expenditures incurred during 1990 for investigating leaks in the pressurizer heater sleeves.
In 1999, these expenditures were reclassified to the electric generation-related regulatory asset discussed earlier in this note. Deferred Conservation Expenditures Deferred conservation expenditures include two components:
"* operations costs (labor, materials, and indirect costs) associated with conservation programs approved by the Maryland PSC, which we are amortizing over periods of four to five years in accordance with the Maryland PSC's orders, and "* revenues we collected from customers in 1996 in excess of our profit limit under the conservation surcharge.
In 1999, we wrote-off a portion of the unamortized electric conservation expenditures that will not be recovered under the Restructuring Order as discussed in Note 4 on page 59.Deferred Costs of Decommissioning Federal Uranium Enrichment Facilities Deferred costs of decommissioning federal uranium enrichment facilities are the unamortized portion of our required contribu tions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities.
We are required, along with other domestic utilities, by the Energy Policy Act of 1992 to make contributions to the fund. The contributions are generally payable over 15 years with escala tion for inflation and are based upon the proportionate amount of uranium enriched by the Department of Energy for each utility. We are amortizing these costs over the contribution period as a cost of fuel. We also discuss this in Note 1 on page 50. In 1999, these expenditures were reclassified to the electric generation-related regulatory asset discussed earlier in this note. Deferred Environmental Costs Deferred environmental costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss this further in Note 10 on page 69. We are amortizing
$21.6 million of these costs (the amount we had incurred through October 1995) over a 10-year period in accordance with the Maryland PSC's November 1995 order. Deferred Fuel Costs As described in Note 1 on page 50, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases and sales of electricity, and natural gas and our fuel rate revenues collected from customers.
We reduce deferred fuel costs as we collect them from or refund them to our customers.
We show our deferred fuel costs in the following table. At December 31, 1999 1998 (In millions)
Electric $60.0 $(11.5) Gas 13.8 24.2 Deferred fuel costs (net) $73.8 $12.7 Under the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC.Constellation Energy Group Inc. and Subsidiaries I
CNote 6.Pension, Postretirement, Other Postemployment, and EmpLoyee Savings Plan Benefits We offer pension, postretirement, other postemployment, and employee savings plan benefits.
We describe each of these separately below. Pension Benefits We sponsor several defined benefit pension plans for our employees.
A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant.
Our employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay. Sometimes we amend the plans retroactively.
These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees.
In 1999, our Board of Directors approved the following amendments: " eligible participants will be allowed to choose between an enhanced version of the current benefit formula and a new pension equity plan (PEP) formula. Pension benefits for eligible employees hired after December 31, 1999 will be based on a PEP formula, and " pension and survivor benefits were increased for participants who retired prior to January 1, 1994 and for their surviving spouses.
The financial impacts of the amendments are included in the tables on page 63. Also during 1999, our Board of Directors approved a Targeted Voluntary Special Early Retirement Program (TVSERP) to provide enhanced early retirement benefits to certain eligible participants in targeted jobs that elect to retire on June 1, 2000. The financial impacts of the TVSERP will be reflected in the second quarter of 2000. We fund the plans by contributing at least the minimum amount required under Internal Revenue Service regulations.
We calculate the amount of funding using an actuarial method called the projected unit credit cost method. The assets in all of the plans at December 31, 1999 were mostly marketable equity and fixed income securities, and group annuity contracts.
/Postretirement Benefits We sponsor defined benefit postretirement health care and life insurance plans which cover nearly all Constellation Energy and BGE employees, and certain employees of our subsidiaries.
Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans. For nearly all of the health care plans, retirees make contribu tions to cover a portion of the plan costs. Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions.
The adoption of that statement caused: "* a transition obligation, which we are amortizing over 20 years, and "* an increase in annual postretirement benefit costs. For our diversified businesses, we expense all postretirement benefit costs. For our utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders: "* in an April 1993 rate order, the Maryland PSC allowed us to expense one-half and defer, as a regulatory asset (see Note 5), the other half of the increase in annual postretirement benefit costs related to our electric and gas businesses, and "* in a November 1995 rate order, the Maryland PSC allowed us to expense all of the increase in annual postretirement benefit costs related to our gas business.
Beginning in 1998, the Maryland PSC authorized us to: "* expense all of the increase in annual postretirement benefit costs related to our electric business, and "* amortize the regulatory asset for postretirement benefit costs related to our electric and gas businesses over 15 years.Constellation Energy Group Inc. and Subsidiaries Obligations, Assets, and Funded Status Ze show the change in the benefit obligations, plan assets, and funded status of the pension and postretirement benefit plans in the following table: Pens Bene 1999 Change in benefit obligation Benefit obligation at January 1 $ Service cost Interest cost Plan participants' contributions Actuarial (gain) loss Plan amendments Benefits paid Benefit obligation at December 31 $ion Postretirement -fits Benefits 1998 1999 1998 (In millions)1,031.3 $ 902.0 $383.1 $320.3 26.1 21.6 8.6 6.6 65.3 63.0 24.4 23.4 --2.0 2.0 (93.0) 102.9 (34.2) 48.9 44.6 -(5.0) (57.6) (58.2) (20.2) (18.1)1,016.7 $1,031.3 $358.7 $383.1 Pension Postretirement Benefits Benefits 1999 1998 1999 1998 (In millions)
-_, ,2hange in plan assets Fair value of plan assets at January 1 $ 985.5 $912.3 $ -$ Actual return on plan assets 139.4 116.9 -Employer contribution 17.6 14.5 18.2 16.1 Plan participants' contributions
--2.0 2.0 Benefits paid (57.6) (58.2) (20.2) (18.1) Fair value of plan assets at December 31 $1,084.9 $985.5 $ -$ -Pension Postretirement Benefits Benefits 1999 1998 1999 1998 (In millions)
Funded Status Funded status at December 31 $ 68.2 $(45.8) $(358.7) $(383.1) Unrecognized net actuarial (gain) loss (27.2) 137.6 23.6 59.7 Unrecognized prior service cost 59.0 16.9 (0.1) Unrecognized transition obligation
--143.4 159.3 Unamortized net asset from adoption of SFAS No. 87 (0.5) (0.7) -Prepaid (accrued) benefit cost $99.5 $108.0 $(191.8) $164.1) Net Periodic Benefit Cost We show the components of net periodic pension benefit cost in the following table: Year Ended December 31, 1999 1998 1997 (In millions)
Components of net periodic pension benefit cost Service cost $26.1 $21.6 $16.8 Interest cost 65.3 63.0 61.3 Expected return on plan assets (76.6) (72.1) (66.9) Amortization of transition obligation (0.2) (0.2) (0.2) Amortization of prior service cost 2.5 2.5 2.5 Recognized net actuarial loss 10.1 5.6 4.6 Amount capitalized as construction cost (4.2) (3.8) (2.5) Net periodic pension benefit cost $23.0 $16.6 $15.6 Constellation Energy Group Inc. and Subsidiaries I
We show the components of net periodic postretirement benefit cost in the following table: Year Ended December 31, 1999 1998 1997 (In millions)
Components of net periodic postretirement benefit cost Service cost $ 8.6 $ 6.6 $ 5.4 Interest cost 24.4 23.4 21.8 Amortization of transition obligation 11.0 11.4 11.4 Recognized net actuarial loss 1.9 0.2 0.1 Amount capitalized as construction cost (9.4) (8.1) (7.6) Amount deferred --(7.2) Net periodic postretirement benefit cost $36.5 $33.5 $23.9 Assumptions We made the assumptions below to calculate our pension and postretirement benefit obligations.
At December 31, Discount rate Expected return on plan assets Rate of compensation increase Pension Benefits 1999 1998 7.25% 6.50%Postretirement Benefits 1999 1998 7.25% 6.50%9.00 9.00 N/A N/A 4.00 4.00 4.00 4.00 We assumed the health care inflation rates to be: "* in 1999, 6.0% for both Medicare-eligible retirees and retirees not covered by Medicare, and "* in 2000, 7.0% for Medicare-eligible retirees and 8.5% for retirees not covered by Medicare.
After 2000, we assumed both inflation rates will decrease by 0.5% annually to a rate of 5.5% in the years 2003 and 2006, respectively.
After these dates, the inflation rate will remain at 5.5%. A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretire ment benefit obligation by approximately
$46.7 million as of December 31, 1999 and would increase the combined service and interest costs of the postretirement benefit cost by approximately
$5.4 million annually.
A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretire ment benefit obligation by approximately
$37.4 million as of December 31, 1999 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately
$4.2 million annually.
Constellation Energy Group Inc. and Subsidiaries Other Postemployment Benefits We provide the following postemployment benefits:
"* health and life insurance benefits to our employees and certain employees of our subsidiaries who are found to be disabled under our Disability Insurance Plan, and "* income replacement payments for employees found to be disabled before November 1995 (payments for employees found to be disabled after that date are paid by an insur ance company, and the cost is paid by employees).
The liability for these benefits totaled $46.5 million as of December 31, 1999 and $52.9 million as of December 31, 1998. Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits.
We deferred, as a regulatory asset (see Note 5 on page 61), the postemployment benefit liability attributable to our utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this note). We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our current electric and gas base rates to recover the higher costs in 1998. We assumed the discount rate for other postemployment benefits to be 5.5% in 1999 and 4.5% in 1998. Employee Savings Plan Benefits We also sponsor a defined contribution savings plan that is offered to all eligible Constellation Energy and BGE employees, and certain employees of our subsidiaries.
In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Under this plan, we make matching contributions to participant accounts.
We made matching contributions to this plan of: * $10.4 million in 1999, * $10.1 million in 1998, and * $8.5 million in 1997.i.
I Note 7.
I Note 7.
Borrowings Our short-term borrowings may include bank loans, commercial paper notes, and bank lines of credit. Short-term borrowings mature within one year from the date of issuance.
*-'Short-Term          Borrowings Our short-term borrowings may include bank loans, commercial    In addition, Constellation Energy had unused committed paper notes, and bank lines of credit. Short-term borrowings    bank lines of credit totaling $35 million and interim lines mature within one year from the date of issuance. We pay        totaling $125 million supporting its commercial paper notes commitment fees to banks for providing us lines of credit.      at December 31, 1999.
We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates. Constellation Energy At December 31, 1999, Constellation Energy had $242.5 million outstanding consisting entirely of commercial paper notes. At December
When we borrow under the lines of credit, we pay market          The weighted average effective interest rate for Constellation interest rates.                                                  Energy's commercial paper notes was 5.
* a $6.7 million after-tax write-off of a power project (see Note 3), and
* a $6.7 million after-tax write-off of a power project (see Note 3), and
* a $3.4 million after-tax write-down of certain senior-living facilities (see Note 2). Our fourth quarter results include:
* a $3.4 million after-tax write-down of certain senior-living facilities (see Note 2).
Our fourth quarter results include:
* a $66.3 million extraordinary charge associated with the Restructuring Order (see Note 4),
* a $66.3 million extraordinary charge associated with the Restructuring Order (see Note 4),
* the recognition of the $37.5 million of revenues that were deferred in the third quarter (see above), * $75 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order (see the "Electric Depreciation and Amortization Expense" section of Management's Discussion and Analysis),
* the recognition of the $37.5 million of revenues that were deferred in the third quarter (see above),
* a $4.9 million after-tax gain on a financial investment (see Note 3), * $12.0 million after-tax write-downs of certain power projects (see Note 3), and
    * $75 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order (see the "Electric Depreciation and Amortization Expense" section of Management's Discussion and Analysis),
* a $2.4 million after-tax write-down of certain 3/4. senior-living facilities (see Note 2). The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding.Constellation Energy Group Inc. and Subsidiaries I Christian H. Poindexter Chairman, President and Chief Executive Officer, Constellation Energy Group Age 61 BGO Director since 1988 Elected April 1999 H. Furlong Baldwin Chairman, President and Chief Executive Officer, Mercantile Bankshares Corporation Age 68 BGE Director from 1988-1999 Elected April 1999 Douglas L. Becker President and Co-Chief Executive Officer, Sylvan Learning Systems, Inc. Age 34 BGE Director from 1998-1999 Elected April 1999 James T. Brady Former Secretary, Maryland Department of Business and Economic Development Age 59 Constellation Enterprises Director from 1998-1999 Elected May 1999 Beverly B. Byron Former Congresswoman, U.S. House of Representatives Age 67 BGE Director from 1993-1999 Elected April 1999 J. Owen Cole Director, AllFirst Financial, Inc. and AllFirst Bank Age 70 BGE Director from 1977-1999 Elected April 1999-WA W Dan A. Colussy Edward A. Crooke Former Chairman, Former Vice President and Chief Chairman, Executive Officer, Constellation Energy UNC Incorporated Group; Former Age 68 Chairman, President, BGE Director from and Chief Executive 1992-1999 Officer, Constellation Elected April 1999 Enterprises, Inc. Age 61 BGE Director from 1988-1999 Elected April 1999 James R. Curtiss, Esq. Partner, Winston & Strawn Age 46 BGE Director from 1994-1999 Elected April 1999 Roger W. Gale President and Chief Executive Officer, PHB Hagler Bailly Age 53 Constellation Enterprises Director from 1998-1999 Elected May 1999 Jerome W. Geckle Retired Chairman, PHH Corporation Age 70 BGE Director from 1980-1999 Elected April 1999 Dr. Freeman A. Hrabowski, III President, University of Maryland Baltimore County Age 49 BGE Director from 1994-1999 Elected April 1999 Nancy Lampton Chairman and Chief Executive Officer, American Life and Accident Insurance Company of Kentucky Age 57 BGE Director from 1994-1999 Elected April 1999 Charles R. Larson Admiral, United States Navy (Retired)
* a $4.9 million after-tax gain on a financial investment (see Note 3),
Age 63 BGE Director from 1998-1999 Elected April 1999 George V. McGowan t Former Chairman and Chief Executive Officer, BGE Age 72 BGE Director from 1980-1999 Elected April 1999 Srm George L. Russell, Jr., Esq. Attorney at Law, Law Offices of Peter G. Angelos Age 70 BGE Director from 1988-1999 Elected April 1999 Mayo A. Shattuck, III Co-Chairman and Co-Chief Executive Officer, DB Alex. Brown, LLC and Deutsche Banc Securities, Inc. Age 45 Constellation Enterprises Director from 1998-1999 Elected May 1999=X= Michael D. Sullivan Chairman, Golf America Stores, Inc. Age 60 BGE Director from 1992-1999 Elected April 1999 Constellation Energy Group Inc. and Subsidianes SConstellation Energy Group Board of Directors*
    * $12.0 million after-tax write-downs of certain power projects (see Note 3), and
I Committees of the Board Audit Committee J. Owen Cole, Chairman Douglas L. Becker James T. Brady George L. Russell, Jr. Committee on Management Jerome W. Geckle, Chairman J. Owen Cole Dan A. Colussy Mayo A. Shattuck, I1H Michael D. Sullivan Committee on Nuclear Power James R. Curtiss, Chairman Beverly B. Byron Charles R. Larson George V. McGowan Executive Committee George V. McGowan, Chairman H. Furlong Baldwin James T. Brady Edward A. Crooke Dr. Freeman A. Hrabowski, III Christian H. Poindexter  
* a $2.4 million after-tax write-down of certain 3/4. senior-living facilities (see Note 2).
-/ George L. Russell, Jr. Long-Range Strategy Committee H. Furlong Baldwin, Chairman Douglas L. Becker Dan A. Colussy Edward A. Crooke James R. Curtiss Roger W. Gale Jerome W. Geckle Nancy Lampton Charles R. Larson Mayo A. Shattuck, HI Michael D. Sullivan Constettation Energy Group Off icers Christian H. Poindexter Chairman, President and Chief Executive Officer Age 61 Thomas F. Brady Vice President, Corporate Strategy & Development Age 50 David A. Bruane Vice President Finance & Accounting, Chief Financial Officer and Secretary Age 59 Robert S. Fleishmnan Vice President, Corporate Affairs and General Counsel Age 46 Linda D. Miller Vice President, Human Resources Age 49 Richard .Bange, Jr. Controller and Assistant Secretary Age 55 Thomas E. Ruezin, Jr. Treasurer and Assistant Secretary Age 45 Business Unit Leaders Frank 0. Heintz President-Elect Baltimore Gas and Electric Co. Age 55 Charles W. Shivery President Constellation Power Source, Inc. Age 54 Robert E. Denton President Constellation Nuclear Group, LLC Age 57 John F. Walter President Constellation Power, Inc. Age 65 William H. Munn President BGE Home Products & Services, Inc. Age 52 Steven D. Kesler President Constellation Real Estate Group, Inc. Constellation Investments, Inc. Age 48 Gregory S. Jaroelnski President Constellation Energy Source, Inc. Age 47 Committee on Workplace Diversity Beverly B. Byron, Chairman Roger W. Gale Dr. Freeman A. Hrabowski, IH Nancy Lampton
The sum of the quarterlyearningsper share amounts may not equal the totalfor the year due to the effects of rounding.
* The Board is divided into three classes with one class of directors elected at each annual shareholder meeting for a three-year term. 4 George V. McGowan will retire from the Board in April 2000.Constellation Energy Group Inc. and Subsidiaries I N F 1999 1998 Common Stock Data Quarterly Earnings Per Share First Quarter Second Quarter Third Quarter Fourth Quarter Total Earnings Per Share Before Nonrecurring Charges Included in Operations Dividends Dividends Declared Per Share Dividends Paid Per Share Dividend Payout Ratio Reported Excluding nonrecurring charges to earnings Market Prices High Low Close Capital Structure Consolidated Long-Term Debt Short-Term Borrowings BGE Preferred and Preference Stock Common Shareholders' Equity Utility Only Long-Term Debt Short-Term Borrowings BGE Preferred and Preference Stock Common Shareholders' Equity$2.48 $2.20 $2.28 $2.27 $2.02$1.68 1.68$1.67 1.66$1.63 1.62$1.59 1.58$1.55 1.54 96.6% 81.1% 94.8% 85.9% 76.7% 67.7% 75.9% 71.5% 70.0% 76.7%$ 31'P 24"/16 29 48.8% 5.4 2.7 43.1 50.9% 2.4 3.5 43.2$ 35', 29'/ 307A 53.5% 2.9 43.6 51.5% 3.6 44.9$ 34'/A6 $ 291/b $ 29 24'A 25 22 34'A 261A 28'h 48.0% 4.7 4.8 42.5 45.4% 5.8 5.9 42.9 45.0% 5.1 6.5 43.4 42.5% 6.1 7.8 43.6 42.8% 4.4 8.5 44.3 40.4% 5.2 10.0 44.4 The sum of the quarterly earnings per share amounts may not equal the totalfor the year due to the effects of rounding and changes in the average number of shares outstanding throughout the year. The quarterly earnings per share amounts include certain one-time adjustments as shown in Note 12 to the Consolidated Financial Statements.
Constellation Energy Group Inc. and Subsidiaries
Constellation Energy Group Inc. and Subsidiaries Q Five-Year Statistical 1997$0.43 0.05 1.11 0.12$1.72$0.55 0.45 0.91 (0.18)$1.74 1996$0.62 0.36 0.93 (0.06)$1.85$0.50 0.39 1.08 0.09$2.06 1995$0.41 0.28 1.04 0.29$2.02 Total Summary SShareho lder Information Common Stock Dividends*
 
and Price Ranges 1999 First Quarter Second Quarter Third Quarter Fourth Quarter Total Dividend Declared $ .42 .42 .42 .42 $1.68 Price High Low $31% $2411/46 31 % 25X 30X 273/6 31 X 27%First Quarter Second Quarter Third Quarter Fourth Quarter Total Dividend Declared $ .41 .42 .42 .42 $1.67 1998 Price High Low $34 X $29/4 325%6 29 1/4 335/ 29'/16 35 X 30X Dividend*
I   SConstellation                        Energy Group Board                            of Directors*
Policy The common stock is entitled to dividends when and as declared by the Board of Directors.
Christian H.           H. Furlong             Douglas L. Becker      James T. Brady            Beverly B. Byron          J. Owen Cole Poindexter            Baldwin                 President and          FormerSecretary,          Former                    Director,AllFirst Chairman,President      Co-ChiefExecutive    MarylandDepartment        Congresswoman,            Financial,Inc. and Chairman,President and Chief Executive     Officer, Sylvan      of Business and          U.S. House of              AllFirst Bank and ChiefExecutive Officer, Mercantile                            Economic                  Representatives            Age 70 Officer, Constellation                        Learning Systems, Inc.
There are no limitations in any indenture or other agreements on payment of dividends.
Bankshares              Age 34               Development              Age 67                    BGE Director from Energy Group Corporation              BGE Director from    Age 59                   BGE Director from         1977-1999 Age 61 Age 68                  1998-1999             Constellation            1993-1999                  Elected April 1999 BGO Director since 1988            BGE Director from       Elected April 1999    Enterprises Director      Elected April 1999 Elected April 1999    1988-1999                                      from 1998-1999 Elected April 1999                             Elected May 1999
Dividends have been paid on the common stock continuously since 1910. Future dividends depend upon future earnings, the financial condition of the company, and other factors.
                          -WA W                                         Roger W. Gale            Jerome W. Geckle          Dr. Freeman A.
Common Stock Dividend Dates Record dates are normally on the 10th of March, June, September, and December.
Dan A. Colussy         Edward A. Crooke         James R.
Quarterly dividends are customarily mailed to each shareholder on or about the 1 st of April, July, October, and January.
Curtiss, Esq.        Presidentand Chief       Retired Chairman,         Hrabowski, III Former Chairman,       Former Vice Partner,Winston      Executive Officer,       PHHCorporation            President, University Presidentand Chief    Chairman,
Stock Trading Constellation Energy Group's common stock, which is traded under the ticker symbol CEG, is listed on the New York, __._. Chicago, and Pacific stock exchanges, and has unlisted trading privileges on the Boston, Cincinnati, and Philadelphia exchanges.
                                                  & Strawn              PHB HaglerBailly          Age 70                    of Maryland Executive Officer,     ConstellationEnergy Age 46                 Age 53                  BGE Director from         Baltimore County UNC Incorporated      Group; Former BGE Director from      Constellation            1980-1999                 Age 49 Age 68                Chairman,President, 1994-1999              Enterprises Director    Elected April 1999         BGE Director from BGE Director from    and Chief Executive Elected April 1999    from 1998-1999                                       1994-1999 1992-1999            Officer, Constellation Enterprises,Inc.                                Elected May 1999                                     Elected April 1999 Elected April 1999 Age 61 BGE Director from 1988-1999 Elected April 1999 Srm                              =X=
As of December 31, 1999, there were 66,093 common shareholders of record. Annual Meeting The annual meeting of shareholders will be held at 10 a.m. on Friday, April 28,2000, in the 2nd floor Conference Room of the Gas and Electric Building, located at 39 W. Lexington St., Baltimore, Maryland 21201. Form 10-K Upon written request, the company will furnish, without charge, a copy of its and BGE's Annual Report on Form 10-K, including financial statements.
Michael D.
Requests should be addressed to David A. Brune, Chief Financial Officer and Secretary, Vice President, Finance & Accounting, 20th Floor, 250 W. Pratt St., Baltimore, Maryland 21201. Auditors PricewaterhouseCoopers LLP
Nancy Lampton          Charles R. Larson        George V.            George L.                Mayo A.
* Dividends paid prior to April 30, 1999 were on BGE common stock. As a result of the common stock share -.._ exchange, Constellation Energy is the successor to BGE.Executive Offices 250 W. Pratt Street Baltimore, Maryland 21201 Mail: P.O. Box 1475, Baltimore, Maryland 21203-1475 Shareholder Investment Plan Constellation Energy Group's Shareholder Investment Plan provides common shareholders an easy and economical way to acquire additional shares of common stock. The plan allows shareholders to reinvest all or part of their common stock dividends; purchase additional shares of common stock; deposit the common stock they hold into the plan; and request a transfer or sale of shares held in their accounts.
McGowan t              Russell, Jr., Esq.        Shattuck, III             Sullivan Chairmanand Chief      Admiral, United States Navy (Retired)          Former Chairman        Attorney at Law,          Co-Chairmanand            Chairman,Golf Executive Officer, Age 63                  and Chief Executive    Law Offices of           Co-ChiefExecutive          America Stores, Inc.
Stock Transfer Agents and Registrars Transfer Agent and Registrar:
American Life and Accident Insurance    BGE Director from       Officer, BGE          PeterG. Angelos          Officer, DB Alex. Brown, Age 60 Company of Kentucky    1998-1999                Age 72               Age 70                    LLC andDeutsche Banc BGE Director from Elected April 1999       BGE Director from    BGE Director from        Securities, Inc.           1992-1999 Age 57 1980-1999              1988-1999                Age 45                    Elected April 1999 BGE Director from 1994-1999                                       Elected April 1999   Elected April 1999        Constellation Enterprises Elected April 1999                                                                              Director from 1998-1999 Elected May 1999 I  ConstellationEnergy Group Inc. and Subsidianes
Constellation Energy Group, Inc. Baltimore, Maryland Co-Transfer Agent and Registrar:
 
Harris Trust and Savings Bank Chicago, Illinois Shareholder Assistance and Inquiries If you need assistance with lost or stolen stock certificates or dividend checks, name changes, address changes, stock transfers, the Shareholder Investment Plan, or other matters, you may contact our shareholder service representatives as follows: By telephone (Monday-Friday, 8 a.m. -4:45 p.m. EST): Baltimore Metropolitan Area 410-783-5920 Within Maryland 1-800-492-2861 Outside Maryland 1-800-258-0499 By U.S. mail: Constellation Energy Group, Inc. Shareholder Services P.O. Box 1642 Baltimore, MD 21203-1642 In person or by overnight delivery:
I Committees of the Board                                                                                                                 N Constettation Energy Group Off icers                            Business Unit Leaders Audit Committee                                      Christian H. Poindexter                Frank 0. Heintz J. Owen Cole, Chairman                             Chairman, Presidentand                  President-Elect Douglas L. Becker                                 Chief Executive Officer                Baltimore Gas and Electric Co.
Constellation Energy Group, Inc. Shareholder Services, Room 820 39 W. Lexington Street Baltimore, MD 21201 Constellation Energy Group Inc. and Subsidiaries I  
James T. Brady                                     Age 61                                  Age 55 George L. Russell, Jr.
Thomas F.Brady                          Charles W.Shivery Committee on Management                              Vice President, Corporate              President Jerome W. Geckle, Chairman                         Strategy & Development                  ConstellationPower Source, Inc.
J. Owen Cole                                       Age 50                                  Age 54 Dan A. Colussy Mayo A. Shattuck, I1H                             David A. Bruane                        Robert E. Denton Michael D. Sullivan                               Vice President Finance& Accounting,    President ChiefFinancialOfficer and Secretary    ConstellationNuclear Group, LLC Committee on Nuclear Power                           Age 59                                Age 57 James R. Curtiss, Chairman Beverly B. Byron                                   Robert S. Fleishmnan                  John F. Walter Charles R. Larson                                 Vice President, CorporateAffairs      President George V. McGowan                                   and GeneralCounsel                    Constellation Power, Inc.
Age 46                                Age 65 Executive Committee George V. McGowan, Chairman                         Linda D. Miller                        William H. Munn H. Furlong Baldwin                                 Vice President,Human Resources        President James T. Brady                                     Age 49                                BGE Home Products & Services,  Inc.
Edward A. Crooke                                                                           Age 52 Dr. Freeman A. Hrabowski, III                       Richard . Bange, Jr.
Christian H. Poindexter                           Controller and Assistant Secretary      Steven D. Kesler
-/ George L. Russell, Jr.                               Age 55                                  President ConstellationReal Estate Group, Inc.
Long-Range Strategy Committee                         Thomas E. Ruezin, Jr.                  ConstellationInvestments, Inc.
H. Furlong Baldwin, Chairman                       Treasurer andAssistant Secretary        Age 48 Douglas L. Becker                                 Age 45 Dan A. Colussy                                                                             Gregory S. Jaroelnski Edward A. Crooke                                                                           President James R. Curtiss                                                                           ConstellationEnergy Source, Inc.
Roger W. Gale                                                                             Age 47 Jerome W. Geckle Nancy Lampton Charles R. Larson Mayo A. Shattuck, HI Michael D. Sullivan Committee on Workplace Diversity Beverly B. Byron, Chairman Roger W. Gale Dr. Freeman A. Hrabowski, IH Nancy Lampton
* The Board is divided into three classes with one class of directors elected at each annual shareholder meeting for a three-year term.
4  George V. McGowan will retire from the Board in April 2000.
ConstellationEnergy Group Inc. and Subsidiaries
 
FQ    Five-Year                Statistical Summary 1999          1998            1997        1996          1995 Common Stock Data QuarterlyEarningsPerShare First Quarter                                                              $0.55       $0.50          $0.43      $0.62        $0.41 0.45          0.39          0.05        0.36          0.28 Second Quarter 0.91          1.08            1.11      0.93          1.04 Third Quarter (0.18)        0.09          0.12      (0.06)          0.29 Fourth Quarter Total                                                                      $1.74        $2.06          $1.72      $1.85        $2.02 Total EarningsPerShare Before NonrecurringCharges Includedin Operations                                                     $2.48        $2.20          $2.28      $2.27        $2.02 Dividends Dividends Declared Per Share                                               $1.68        $1.67          $1.63      $1.59        $1.55 1.68        1.66            1.62        1.58          1.54 Dividends Paid Per Share Dividend Payout Ratio Reported                                                                  96.6%        81.1%          94.8%      85.9%        76.7%
Excluding nonrecurring charges to earnings                                                      67.7%       75.9%           71.5%       70.0%         76.7%
Market Prices High                                                                      $ 31'P       $ 35',        $  34'/A6  $ 291/b      $ 29 24"/16       29'/          24'A        25            22 Low                                                                                                        34'A        261A          28'h Close                                                                          29            307A Capital Structure Consolidated 48.8%       53.5%          48.0%      45.0%        42.8%
Long-Term Debt                                                                                                                        4.4 5.4                          4.7        5.1 Short-Term Borrowings 2.7          2.9             4.8        6.5           8.5 BGE Preferred and Preference Stock 43.1        43.6            42.5       43.4         44.3 Common Shareholders' Equity Utility Only                                                                                                                          40.4%
50.9%         51.5%          45.4%      42.5%
Long-Term Debt 2.4                          5.8         6.1          5.2 Short-Term Borrowings 3.5           3.6            5.9        7.8          10.0 BGE Preferred and Preference Stock                                                                                                44.4 43.2          44.9          42.9        43.6 Common Shareholders' Equity The sum of the quarterlyearningsper share amounts may not equal the totalfor the yeardue to the effects of roundingand changes in the average number of sharesoutstanding throughout the year.
The quarterlyearningsper share amounts include certain one-time adjustmentsas shown in Note 12 to the ConsolidatedFinancialStatements.
Constellation Energy Group Inc. and Subsidiaries
 
SShareho lder Information                                      I Common Stock Dividends* and Price Ranges 1999                                                                  1998 Dividend                  Price                                        Dividend                  Price Declared          High        Low                                    Declared          High        Low First Quarter            $ .42          $31%        $2411/46          First Quarter            $ .41          $34 X        $29/4 Second Quarter              .42            31 %        25X          Second Quarter              .42          325%6        29 1/4 Third Quarter              .42            30X          273/6        Third Quarter                .42          335/        29'/16 Fourth Quarter              .42            31 X        27%          Fourth Quarter              .42          35  X        30X Total                  $1.68                                          Total                  $1.67 Dividend* Policy                                                      Executive Offices The common stock is entitled to dividends when and as declared        250 W. Pratt Street by the Board of Directors. There are no limitations in any            Baltimore, Maryland 21201 indenture or other agreements on payment of dividends.               Mail: P.O. Box 1475, Baltimore, Maryland 21203-1475 Dividends have been paid on the common stock continuously since 1910. Future dividends depend upon future earnings, the        Shareholder Investment Plan financial condition of the company, and other factors.               Constellation Energy Group's Shareholder Investment Plan provides common shareholders an easy and economical way to Common Stock Dividend Dates                                          acquire additional shares of common stock. The plan allows Record dates are normally on the 10th of March, June, September,      shareholders to reinvest all or part of their common stock and December. Quarterly dividends are customarily mailed to each      dividends; purchase additional shares of common stock; deposit shareholder on or about the 1st ofApril, July, October, and January. the common stock they hold into the plan; and request a transfer or sale of shares held in their accounts.
Stock Trading Constellation Energy Group's common stock, which is traded            Stock Transfer Agents and Registrars under the ticker symbol CEG, is listed on the New York,               Transfer Agent and Registrar:
__._. Chicago, and Pacific stock exchanges, and has unlisted trading                   Constellation Energy Group, Inc.
privileges on the Boston, Cincinnati, and Philadelphia                           Baltimore, Maryland exchanges. As of December 31, 1999, there were 66,093                 Co-Transfer Agent and Registrar:
common shareholders of record.                                                   Harris Trust and Savings Bank Chicago, Illinois Annual Meeting The annual meeting of shareholders will be held at 10 a.m. on         Shareholder Assistance and Inquiries Friday, April 28,2000, in the 2nd floor Conference Room of             If you need assistance with lost or stolen stock certificates or the Gas and Electric Building, located at 39 W. Lexington St.,        dividend checks, name changes, address changes, stock transfers, Baltimore, Maryland 21201.                                             the Shareholder Investment Plan, or other matters, you may contact our shareholder service representatives as follows:
Form 10-K Upon written request, the company will furnish, without              By telephone (Monday-Friday,8 a.m. -4:45 p.m. EST):
charge, a copy of its and BGE's Annual Report on Form                        Baltimore Metropolitan Area        410-783-5920 10-K, including financial statements. Requests should be                    Within Maryland                  1-800-492-2861 addressed to David A. Brune, Chief Financial Officer and                    Outside Maryland                  1-800-258-0499 Secretary, Vice President, Finance & Accounting, 20th Floor, 250 W. Pratt St., Baltimore, Maryland 21201.                         By U.S. mail:
Constellation Energy Group, Inc.
Auditors                                                                    Shareholder Services PricewaterhouseCoopers LLP                                                  P.O. Box 1642 Baltimore, MD 21203-1642 In person or by overnightdelivery:
* Dividends paidprior to    April 30, 1999 were on BGE                      Constellation Energy Group, Inc.
Shareholder Services, Room 820 common stock. As a result of the common stock share                      39 W. Lexington Street
-.. _    exchange, Constellation Energy is the successor to BGE.                  Baltimore, MD 21201 ConstellationEnergy Group Inc. and Subsidiaries
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 1O-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended SEPTEMBER 30, 2000 Commission                                                                                        IRS Employer File Number                  Exact name of registrant as specified in its charter              Identification No.
1-12869                CONSTELLATION ENERGY GROUP, INC.                                         524964611 1-1910              BALTIMORE GAS AND ELECTRIC COMPANY                                          52-0280210 MARYLAND (State of Incorporation) 250 W. PRATT STREET,           BALTIMORE, MARYLAND                              21201 (Address of principal executive offices)                        (Zip Code) 410-234-5000 (Registrants' telephone number, including area code)
NOT APPLICABLE (Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days.
Yes X        No Common Stock, without par value 150,531,716 shares outstanding of Constellation Energy Group, Inc. on October 31, 2000.
 
TABLE OF CONTENTS Lal Part I--Financial Information Item I -  Financial Statements ConstellationEnergy Group, Inc. and Subsidiaries Consolidated Statements of Income ................................................................................................                              3 Consolidated Statements of Comprehensive Income .....................................................................                                            3 Consolidated Balance Sheets .............................................................................................................                        4 Consolidated Statements of Cash Flows ...........................................................................................                                6 Baltimore Gas and Electric Company and Subsidiaries Consolidated Statements of Income ................................................................................................                              7 Consolidated Statements of Comprehensive Income ...................................                                                                              7 Consolidated Balance Sheets .............................................................................................................                        8 Consolidated Statem ents of Cash Flows ...........................................................................................                              10 Notes to Consolidated Financial Statements ..................................................................................                                  II Item 2-- Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction ........................................................................................................................................          18 Strategy ...............................................................................................................................................      19 Current Issues .....................................................................................................................................          20 Results of Operations .........................................................................................................................                24 Financial Condition ............................................................................................................................              32 Capital Resources ...............................................................................................................................              33 Other M atters ......................................................................................................................................        35 Item 3 -    Quantitative and Qualitative Disclosures About M arket Risk ........................................................                                          35 Part II    Other Information Item 1 -    Legal Proceedings ..............................................................................................................................              36 Item 5 --  Other Inform ation ...............................................................................................................................            37 Item 6 -- Exhibits and Reports on Form 8-K ....................................................................................................                          38 Signature ............................................................................................................................................................... 39 2
 
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION Item 1 - Financial Statements Iionsolidated Statements of Income (Unaudited)
Three Months Ended                                  Nine Months Ended September 30,                                    September 30, 2000                1999                        2000                1999 (In Millions, Except Per-ShareAmounts)
Revenues Nonregulated revenues                                                  $        296.7        $      258.9              $        781.4      $        782.2 Regulated electric revenues                                                      598.2                691.2                      1,688.0            1,737.2 Regulated gas revenues                                                            86.7                60.1                        372.8              332.7 Total revenues                                                                  981.6              1,010.2                      2,842.2            2,852.1 Expenses Operating expenses                                                              512.2                574.5                      1,680.8            1,761.3 Depreciation and amortization                                                    107.6                92.9                        370.7              274.0 Taxes other than income taxes                                                    46.4                65.1                        158.8              177.2 Total expenses                                                                  666.2                732.5                      2,210.3            2,212.5 Income From Operations                                                            315.4                277.7                        631.9              639.6 Other Income                                                                        0.9                  1.2                          7.0                5.7 Income Before Fixed Charges and Income Taxes                                      316.3                278.9                        638.9              645.3 Fixed Charges Interest expense (net)                                                            66.6                61.7                        192.0              181.1 BGE preference stock dividends                                                    3.3                  3.4                        9.9                10.2 Total fixed charges                                                              69.9                65.1                        201.9              191.3
      'ncome Before Income Taxes                                                        246.4                213.8                        437.0              454.0
'4ncome Taxes Current                                                                        108.3                  76.7                        215.1              152.6 Deferred                                                                          (7.3)                  3.2                      (31.0)              20.9 Investment tax credit adjustments                                                (2.1)                (2.2)                        (6.3)                (6.4)
Total income taxes                                                                98.9                77.7                        177.8              167.1 Net Income                                                                $      147.5        $      136.1              $        259.2      $        286.9 Earnings Applicable to Common Stock                                      $      147.5        $      136.1              $        259.2      $        286.9 Average Shares of Common Stock Outstanding                                        150.1                149.6                        149.8              149.6 Earnings per Common Share and Earnings Per Common Share Assuming Dilution                                            $0.98              $0.91                        $1.73              $1.92 Dividends Declared Per Common Share                                              $0.42              $0.42                        $1.26              $1.26 Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended                                Nine Months Ended September 30,                                    September 30, 2000                1999                        2000                1999 (In Millions)
Net Income                                                                $        147.5        $    136.1              $        259.2      $      286.9 Other comprehensive income (loss), net of taxes                                    17.7                  5.0                        41.8                (6.5)
Comprehensive Income                                                      $        165.2        $    141.1              $        301.0      $      280.4
,;,.ee    Notes to ConsolidatedFinancialStatements.
Certain priorperiod amounts have been reclassified to conform with the current period'spresentation.
3
 
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements Consolidated Balance Sheets September 30,          December 31, 2000*                    1999 (In Millions)
Assets Current Assets Cash and cash equivalents                                                                          $        50.4          $        92.7 Accounts receivable (net of allowance for uncollectibles of $25.5 and $36.6 respectively)                                                                      842.1                  578.5 Trading securities                                                                                        180.2                  136.5 Assets from energy trading activities                                                                    1,573.7                  312.1 Fuel stocks                                                                                                101.9                    94.9 Materials and supplies                                                                                    155.6                  149.1 Prepaid taxes other than income taxes                                                                      140.2                    72.4 Other                                                                                                      36.4                    54.0 Total current assets                                                                                    3,080.5                  1,490.2 Investments and Other Assets Real estate projects and investments                                                                      296.4                  310.1 Investments in power projects                                                                              538.8                  547.3 Financial investments                                                                                      192.2                  145.4 Nuclear decommissioning trust fund                                                                        235.0                  217.9 Net pension asset                                                                                          97.2                    99.5 Investment in Orion Power Holdings, Inc.                                                                  232.1                  105.7 Other                                                                                                      120.4                  154.3 Total investments and other assets                                                                      1,712.1                1,580.2 Property, Plant and Equipment Regulated property, plant and equipment:
Plant in service                                                                                  4,746.0                8,620.1 Construction work in progress                                                                            68.8                  222.3 Plant held for future use                                                                                9.7                    13.0 Total regulated property, plant and equipment                                                        4,824.5                8,855.4 Nonregulated generation property, plant and equipment                                                  4,906.5                  341.3 Other nonregulated property, plant and equipment                                                          165.1                  152.7 Nuclear fuel (net of amortization)                                                                        137.4                  133.8 Accumulated depreciation                                                                              (3,745.6)              (3,559.1)
Net property, plant and equipment                                                                      6,287.9                5,924.1 Deferred Charges Regulatory assets (net)                                                                                  514.2                  637.4 Other                                                                                                      61.3                    51.9 Total deferred charges                                                                                    575.5                  689.3 Total Assets                                                                                          $  11,656.0            $    9,683.8
* Unaudited See Notes to ConsolidatedFinancialStatements.
Certain priorperiod amiounts have been reclassifiedto confbrin with the currentperiod's presentation.
4


UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 1O-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended SEPTEMBER 30, 2000 Commission File Number Exact name of registrant as specified in its charter IRS Employer Identification No.1-12869 1-1910 CONSTELLATION ENERGY GROUP, INC. BALTIMORE GAS AND ELECTRIC COMPANY 524964611 52-0280210 MARYLAND (State of Incorporation) 250 W. PRATT STREET, BALTIMORE, MARYLAND 21201 (Address of principal executive offices) (Zip Code) 410-234-5000 (Registrants' telephone number, including area code) NOT APPLICABLE (Former name, former address and former fiscal year, if changed since last report)Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)
Item 1 - Financial Statements Consolidated Balance Sheets September 30,        December 31, 2000*                1999 (In Millions)
Liabilities and Capitalization Current Liabilities Short-term borrowings                                                                              $      505.0          $      371.5 Current portion of long-term debt                                                                        660.9                808.3 Accounts payable                                                                                          693.7                365.1 Liabilities from energy trading activities                                                              1,260.6                163.8 Dividends declared                                                                                        66.2                  66.1 Accrued taxes                                                                                              90.8                  19.2 Other                                                                                                    206.8                209.4 Total current liabilities                                                                              3,484.0              2,003.4 Deferred Credits and Other Liabilities Deferred income taxes                                                                                  1,273.9              1,288.8 Postretirement and postemployment benefits                                                                261.7                269.8 Deferred investment tax credits                                                                          103.4                109.6 Other                                                                                                    355.7                253.8 Total deferred credits and other liabilities                                                            1,994.7              1,922.0 Long-term Debt First refunding mortgage bonds of BGE
* the sale of electricity in bulk power markets,
* the sale of electricity in bulk power markets,
* competing with alternative energy suppliers, and
                                                                "* Electric delivery service  rates are frozen for a four
* electric sales to retail customers.
* competing with alternative energy suppliers, and                year period for commercial and industrial
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that has significantly restructured Maryland's electric utility industry and modified the industry's tax structure.
* electric sales to retail customers.                              customers. The generation and transmission components of rates are frozen for different time On April 8, 1999, Maryland enacted the Electric periods depending on the service options selected Customer Choice and Competition Act of 1999 (the by those customers.
In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 4 of our 1999 Annual Report on Form 10-K. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring, accelerated the timetable for customer choice, and addressed the major provisions of the Act. The Restructuring Order also resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are discussed below."* All customers, except a few commercial and industrial companies that have signed contracts with BGE, can choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer
"Act") and accompanying tax legislation that has significantly restructured Maryland's electric utility          "*BGE will recover $528      million after-tax of its industry and modified the industry's tax structure.                potentially stranded investments and utility restructuring costs through a competitive transition In the Restructuring Order discussed below, the Maryland            charge on customers' bills. Residential customers PSC addressed the major provisions of the Act. The                  will pay this charge
Investment requirements:
Investment requirements:
Domestic Merchant Energy Other Total investment requirements Retirement of long-term debt Total nonregulated capital requirements Utility Capital Requirements:
Domestic Merchant Energy                                           $ 803    *      $ 1,241        S 1,077 Other                                                                   37              48              41 Total investment requirements                                         840            1,289            1,118 Retirement of long-term debt                                             575              446                7 Total nonregulated capital requirements                                 1,415            1,735            1,125 Utility Capital Requirements:
Construction expenditures (excluding AFC): Regulated Electric:
Construction expenditures (excluding AFC):
Generation (including nuclear fuel) Transmission and distribution Total regulated electric Regulated Gas Common Total construction expenditures Retirement of long-term debt and redemption of preference stock Total utility capital requirements Total capital requirements
Regulated Electric:
$ 803
Generation (including nuclear fuel)                               94 Transmission and distribution                                     177              177              171 Total regulated electric                                         271              177              171 Regulated Gas                                                           56              56              52 Common                                                                   23              26              26 Total construction expenditures                                       350              259              249 Retirement of long-term debt and redemption of preference stock                                                         122              194              147 Total utility capital requirements                                       472              453              396 Total capital requirements                                           $1,887           $2,188          S1,521
* 37 840 575 1,415 94 177 271 56 23 350 122 472 $1,887$ 1,241 48 1,289 446 1,735 177 177 56 26 259 194 453 $2,188 2002 S 1,077 41 1,118 7 1,125 171 171 52 26 249 147 396 S1,521* Effective July 1, 2000, includes approximately
* Effective July 1, 2000, includes approximately $110 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business.
$110 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business.33 Capital Requirements Domestic Merchant Energy Business Our domestic merchant energy business will require additional funding for growing its power marketing business and developing and acquiring power projects.
33
Our domestic merchant energy business investment requirements include the planned construction of 1,100 megawatts of peaking capacity in the Mid-Atlantic/Mid West region by the summer of 2001 and an additional 4,300 megawatts of peaking and combined cycle production facilities scheduled for completion in 2002 and beyond in the Mid-West and South regions. Longer range, our plans are to own or control approximately 30,000 megawatts of generation capacity by 2005. For further information see the Strategy section on page 19. Electric Generation Electric construction expenditures for our regulated electric business include improvements to generating plants and costs for replacing the steam generators at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are reflected in our domestic merchant energy business.
 
In March 2000, we received the license extension from the NRC that extends our operating licenses to 2034 for Unit 1 and 2036 for Unit 2 as discussed in the Current Issues Calvert Cliffs License Extension section on page 23. If we do not replace the steam generators, we will not be able to operate these units through our operating licenses period. We expect the steam generator replacement to occur during the 2002 refueling outage for Unit I and during the 2003 refueling outage for Unit 2. We estimate these Calvert Cliffs' costs to be:$ 38 million in 2000, $63 million in 2001, $ 91 million in 2002, and $ 60 million in 2003.Additionally, our estimates of future electric generation construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction regulations as follows: * $ 55 million in 2000, $55 million in 2001, and * $ 8 million in 2002. We discuss the NOx regulations and timing of expenditures in the Environmental Matters section of the Notes to Consolidated Financial Statements on page 14.Electric Transmission and Distribution, and Gas Regulated electric transmission and distribution, and gas construction expenditures primarily include new business construction needs and improvements to existing facilities.
Capital Requirements                                          ElectricTransmission and Distribution,and Gas DomesticMerchant Energy Business                              Regulated electric transmission and distribution, and gas Our domestic merchant energy business will require             construction expenditures primarily include new business additional funding for growing its power marketing             construction needs and improvements to existing business and developing and acquiring power projects.          facilities.
Funding for Capital Requirements Domestic Merchant Energy Business Funding for the expansion of our domestic merchant energy business is expected from internally generated fiuds, commercial paper issuances, long-term debt, and other financing instruments by Constellation Energy and its subsidiaries, and from time to time equity contributions from Constellation Energy. In addition, on October 23, 2000 we announced initiatives designed to advance our growth strategies in the domestic merchant energy business as discussed in the Subsequent Event section in the Notes to Consolidated Financial Statements on page 11. As part of these initiatives, our domestic merchant energy business expects to initially reinvest its earnings and not pay a dividend to fund its growth. At September 30, 2000, Constellation Energy has a commercial paper program where it can issue up to $500 million in short-term notes to fund its nonregulated businesses.
Our domestic merchant energy business investment               Funding for Capital Requirements requirements include the planned construction of 1,100         Domestic Merchant Energy Business megawatts of peaking capacity in the Mid-Atlantic/Mid         Funding for the expansion of our domestic merchant West region by the summer of 2001 and an additional           energy business is expected from internally generated 4,300 megawatts of peaking and combined cycle                 fiuds, commercial paper issuances, long-term debt, and production facilities scheduled for completion in 2002         other financing instruments by Constellation Energy and and beyond in the Mid-West and South regions. Longer           its subsidiaries, and from time to time equity range, our plans are to own or control approximately           contributions from Constellation Energy.
To support its commercial paper program, Constellation Energy maintains two revolving credit agreements totaling $565 million, of which one facility can also issue letters of credit. In addition, Constellation Energy has access to interim lines of credit as required from time to time to support its outstanding commercial paper. BGE Funding for utility capital expenditures is expected from internally generated funds, commercial paper issuances, available capacity under credit facilities, the issuance of long-term debt, trust securities, or preference stock, and/or from time to time equity contributions from Constellation Energy. At September 30, 2000, FERC authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. In addition, BGE maintains
30,000 megawatts of generation capacity by 2005. For further information see the Strategy section on page 19.       In addition, on October 23, 2000 we announced initiatives designed to advance our growth strategies in Electric Generation                                            the domestic merchant energy business as discussed in Electric construction expenditures for our regulated          the Subsequent Event section in the Notes to electric business include improvements to generating          ConsolidatedFinancialStatements on page 11. As part plants and costs for replacing the steam generators at        of these initiatives, our domestic merchant energy Calvert Cliffs through June 30, 2000. Thereafter, these        business expects to initially reinvest its earnings and not expenditures are reflected in our domestic merchant            pay a dividend to fund its growth.
$183 million in annual committed bank lines of credit and has $25 million in bank revolving credit agreements to support the commercial paper program. In addition, BGE has access to interim lines of credit as required from time to time to support its outstanding commercial paper.34 D Other Nonregulated Businesses BGE Home Products & Services may meet capital requirements through sales of receivables.
energy business.
ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs. If we can get a reasonable value for our real estate projects, senior-living facilities, and other investments, additional cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss the real estate and senior-living facilities business and market conditions in the Other Nonregulated Businesses section on page 31. Other Matters Environmental Matters We are subject to federal, state, and local laws and regulations that work to improve or maintain the quality of the environment.
At September 30, 2000, Constellation Energy has a In March 2000, we received the license extension from the     commercial paper program where it can issue up to $500 NRC that extends our operating licenses to 2034 for Unit 1    million in short-term notes to fund its nonregulated and 2036 for Unit 2 as discussed in the CurrentIssues          businesses. To support its commercial paper program, CalvertCliffs License Extension section on page 23. If we      Constellation Energy maintains two revolving credit do not replace the steam generators, we will not be able to    agreements totaling $565 million, of which one facility operate these units through our operating licenses period. can also issue letters of credit. In addition, Constellation We expect the steam generator replacement to occur during      Energy has access to interim lines of credit as required the 2002 refueling outage for Unit I and during the 2003      from time to time to support its outstanding commercial refueling outage for Unit 2. We estimate these Calvert        paper.
If certain substances were disposed of or released at any of our properties, whether currently operating or not, these laws and regulations require us to remove or remedy the effect on the environment.
Cliffs' costs to be:
This includes Environmental Protection Agency Superfund sites. You will find details of our environmental matters in the Environmental Matters section of the Notes to Consolidated Financial Statements beginning on page 14 and in our 1999 Annual Report on Form 10-K in Item I. Business -Environmental Matters. These details include financial information.
BGE
Some of the information is about costs that may be material.
      $ 38 million  in 2000,                                  Funding for utility capital expenditures is expected from
Accounting Standards Issued In June 2000, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, that amends certain provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and addresses a limited number of implementation issues related to SFAS No. 133. In July 1999, the FASB issued SFAS No. 137 that delays the effective date for SFAS No. 133 by one year. Therefore, we must adopt the provisions of SFAS No. 133 in our financial statements for the quarter ended March 31,2001.
      $63  million  in 2001,                                  internally generated funds, commercial paper issuances, D
We are evaluating the implications of SFAS Nos. 133 and 138, but have not determined the effects on our financial results. However, SFAS Nos. 133 and 138 will not significantly impact our power marketing business as this business uses mark-to-market accounting.
      $ 91 million  in 2002, and                             available capacity under credit facilities, the issuance of
Item 3. Quantitative and Qualitative Disclosures About Market Risk We discuss the following information related to our market risk: "* risk associated with the purchase and sale of energy in a deregulated environment as discussed in the Current Issues Electric Competition section of Management's Discussion and Analysis on page 20, "* financing activities in the Notes to Consolidated Financial Statements on page 13, and "* activities of our power marketing business in the Domestic Merchant Energy Business section of Management's Discussion and Analysis beginning on page 25.35 PART II. OTHER INFORMATION Item 1. Legal Proceedings Employment Discrimination Miller v. Baltimore Gas and Electric Company, et al. This action was filed on September 20, 2000 in the U.S. District Court for the District of Maryland.
      $ 60 million  in 2003.                                 long-term debt, trust securities, or preference stock, and/or from time to time equity contributions from Additionally, our estimates of future electric generation      Constellation Energy.
Besides BGE, Constellation Energy Group, Constellation Nuclear and Calvert Cliffs Nuclear Power Plant are also named defendants.
construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State          At September 30, 2000, FERC authorized BGE to issue of Maryland nitrogen oxides emissions (NOx) reduction          up to $700 million of short-term borrowings, including regulations as follows:                                        commercial paper. In addition, BGE maintains $183 million in annual committed bank lines of credit and has
The action seeks class certification for approximately 150 past and present employees and alleges racial discrimination at Calvert Cliffs Nuclear Power Plant. The amount of damages is unspecified, however the plaintiffs seek back and front pay, along with compensatory and punitive damages. We believe this case is without merit. However, we cannot predict the timing, or outcome, of it or its possible effect on our, or BGE's, financial results.
*    $ 55 million in 2000,                                  $25 million in bank revolving credit agreements to
Moore v. Constellation Energy Group -This action was filed on October 23, 2000 in the U.S. District Court for the District of Maryland by an employee alleging employment discrimination.
      $55 million in 2001, and                                support the commercial paper program. In addition, BGE
Besides Constellation Energy, BGE and Constellation Holdings, Inc. are also named defendants.
*    $ 8 million in 2002.                                   has access to interim lines of credit as required from time to time to support its outstanding commercial paper.
The Equal Employment Opportunity Commission has previously concluded that it was unable to establish a violation of law. The plaintiff seeks, among other things, unspecific monetary damages and back pay. We believe this case is without merit. Asbestos Since 1993, we have been involved in several actions concerning asbestos.
We discuss the NOx regulations and timing of expenditures in the EnvironmentalMatters section of the Notes to ConsolidatedFinancialStatements on page 14.
The actions are based upon the theory of "premises liability," alleging that we knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims. The first type is direct claims by individuals exposed to asbestos.
34
We described these claims in BGE's Report on Form 8-K filed August 20, 1993. We are involved in these claims with approximately 70 other defendants.
 
Approximately 530 individuals that were never employees of BGE each claim $6 million in damages ($2 million compensatory and $4 million punitive).
Other NonregulatedBusinesses                                          ConsolidatedFinancialStatements beginning on page 14 BGE Home Products & Services may meet capital                        and in our 1999 Annual Report on Form 10-K in Item I.
These claims were filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include: "* the identity of our facilities at which the plaintiffs allegedly worked as contractors, "* the names of the plaintiffs employers, and "* the date on which the exposure allegedly occurred.
requirements through sales of receivables. ComfortLink has           Business - EnvironmentalMatters. These details include a revolving credit agreement totaling $50 million to provide          financial information. Some of the information is about liquidity for short-term financial needs.                             costs that may be material.
Ifwe can get a reasonable value for our real estate projects,         Accounting Standards Issued senior-living facilities, and other investments, additional           In June 2000, the FASB issued Statement of Financial cash may be obtained by selling them. Our ability to sell or           Accounting Standards (SFAS) No. 138, Accountingfor liquidate assets will depend on market conditions, and we             CertainDerivativeInstruments and CertainHedging cannot give assurances that these sales or liquidations could         Activities, that amends certain provisions of SFAS No.
be made. We discuss the real estate and senior-living                   133, Accountingfor Derivative Instrumentsand facilities business and market conditions in the Other                 Hedging Activities and addresses a limited number of NonregulatedBusinessessection on page 31.                             implementation issues related to SFAS No. 133.
Other Matters                                                         In July 1999, the FASB issued SFAS No. 137 that delays Environmental Matters                                                  the effective date for SFAS No. 133 by one year.
We are subject to federal, state, and local laws and                   Therefore, we must adopt the provisions of SFAS No.
regulations that work to improve or maintain the quality of            133 in our financial statements for the quarter ended the environment. If certain substances were disposed of or            March 31,2001.
released at any of our properties, whether currently operating or not, these laws and regulations require us to            We are evaluating the implications of SFAS Nos. 133 remove or remedy the effect on the environment. This                  and 138, but have not determined the effects on our includes Environmental Protection Agency Superfund                    financial results. However, SFAS Nos. 133 and 138 will sites. You will find details of our environmental matters in          not significantly impact our power marketing business as the EnvironmentalMatters section of the Notes to                      this business uses mark-to-market accounting.
Item 3. Quantitative and Qualitative Disclosures About Market Risk We discuss the following information related to our market risk:
  "*risk associated  with the purchase and sale of energy in a deregulated environment as discussed in the CurrentIssues Electric Competition section of Management's Discussion and Analysis on page 20,
  "* financing activities in the Notes to ConsolidatedFinancialStatements on page 13, and
  "*activities of our power marketing business in the Domestic MerchantEnergy Business section of Management's Discussion and Analysis beginning on page 25.
35
 
PART II. OTHER INFORMATION Item 1. Legal Proceedings Employment Discrimination                                      The second type is claims by one manufacturer Miller v. Baltimore Gas and Electric Company, et al.            Pittsburgh Coming Corp. (PCC) - against us and This action was filed on September 20, 2000 in the U.S.        approximately eight others, as third-party defendants. On District Court for the District of Maryland. Besides            April 17, 2000, PCC declared bankruptcy and we do not BGE, Constellation Energy Group, Constellation                  expect PCC to prosecute this claim.
Nuclear and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks class certification          These claims relate to approximately 1,500 individual for approximately 150 past and present employees and           plaintiffs and were filed in the Circuit Court for alleges racial discrimination at Calvert Cliffs Nuclear        Baltimore City, Maryland in the fall of 1993. To date, Power Plant. The amount of damages is unspecified,              about 350 cases have been resolved, all without any however the plaintiffs seek back and front pay, along           payments by BGE. We do not know the specific facts with compensatory and punitive damages. We believe             necessary to estimate our potential liability for these this case is without merit. However, we cannot predict         claims. The specific facts we do not know include:
the timing, or outcome, of it or its possible effect on our,
                                                                  "*  the identity of our facilities containing asbestos or BGE's, financial results.
manufactured by the manufacturer, Moore v. Constellation Energy Group - This action was             "*  the relationship (if any) of each of the individual filed on October 23, 2000 in the U.S. District Court for             plaintiffs to us, the District of Maryland by an employee alleging                 "*  the settlement amounts for any individual plaintiffs employment discrimination. Besides Constellation                     who are shown to have had a relationship to us, and Energy, BGE and Constellation Holdings, Inc. are also             "*  the dates on which/places at which the exposure named defendants. The Equal Employment Opportunity allegedly occurred.
Commission has previously concluded that it was unable to establish a violation of law. The plaintiff seeks, among     Until the relevant facts for both types of claims are other things, unspecific monetary damages and back pay.         determined, we are unable to estimate what our liability, if We believe this case is without merit.                         any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs Asbestos                                                        may cover a portion of any awards in the actions, our Since 1993, we have been involved in several actions           potential liability could be material.
concerning asbestos. The actions are based upon the theory of "premises liability," alleging that we knew of       Restructuring Order and exposed individuals to an asbestos hazard. The             In early December 1999, the Mid-Atlantic Power Supply actions relate to two types of claims.                         Association (MAPSA), Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed The first type is direct claims by individuals exposed to       appeals of the Restructuring Order, which were consolidated asbestos. We described these claims in BGE's Report on in the Baltimore City Circuit Court. MAPSA also filed a Form 8-K filed August 20, 1993. We are involved in these motion to delay implementation of the Restructuring Order, claims with approximately 70 other defendants.
pending a decision on the merits of the appeals by the court.
Approximately 530 individuals that were never employees of BGE each claim $6 million in damages ($2 million             On April 21,2000, the Circuit Court dismissed MAPSA's compensatory and $4 million punitive). These claims were       appeal based on a lack of standing (the right of a party to filed in the Circuit Court for Baltimore City, Maryland in     bring a lawsuit to court) and denied its motion for a delay of the summer of 1993. We do not know the specific facts           the Restructuring Order. However, MAPSA filed an appeal necessary to estimate our potential liability for these claims. of this decision. On May 24, 2000, the Circuit Court The specific facts we do not know include:                     dismissed both the Trigen and Sweetheart Cup appeals.
"*   the identity of our facilities at which the plaintiffs   MAPSA subsequently filed several appeals with the allegedly worked as contractors,                         Maryland Court of Special Appeals, the Maryland Court of
"*   the names of the plaintiffs employers, and               Appeals, and the Baltimore City Circuit Court. The effect
"*   the date on which the exposure allegedly occurred.        of the appeals was to delay the implementation of customer choice in BGE's service territory.
To date, 27 of these cases were settled for amounts that were not significant.
To date, 27 of these cases were settled for amounts that were not significant.
The second type is claims by one manufacturer Pittsburgh Coming Corp. (PCC) -against us and approximately eight others, as third-party defendants.
 
On April 17, 2000, PCC declared bankruptcy and we do not expect PCC to prosecute this claim. These claims relate to approximately 1,500 individual plaintiffs and were filed in the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date, about 350 cases have been resolved, all without any payments by BGE. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include: "* the identity of our facilities containing asbestos manufactured by the manufacturer, "* the relationship (if any) of each of the individual plaintiffs to us, "* the settlement amounts for any individual plaintiffs who are shown to have had a relationship to us, and "* the dates on which/places at which the exposure allegedly occurred.
However, on August 4, 2000, the delay was rescinded and         Asset Transfer Order BGE retroactively adjusted its rates as if customer choice had   On July 6, 2000, MAPSA and Shell Energy LLC filed, in been implemented July 1, 2000.                                  the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the On September 29, 2000, the Baltimore City Circuit Court transfer of BGE's generation assets issued on June 19, 2000.
Until the relevant facts for both types of claims are determined, we are unable to estimate what our liability, if any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions, our potential liability could be material.
issued an order upholding the Restructuring Order.
Restructuring Order In early December 1999, the Mid-Atlantic Power Supply Association (MAPSA), Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order, which were consolidated in the Baltimore City Circuit Court. MAPSA also filed a motion to delay implementation of the Restructuring Order, pending a decision on the merits of the appeals by the court. On April 21,2000, the Circuit Court dismissed MAPSA's appeal based on a lack of standing (the right of a party to bring a lawsuit to court) and denied its motion for a delay of the Restructuring Order. However, MAPSA filed an appeal of this decision.
The Court denied MAPSA's request for a delay on August On October 27, 2000, MAPSA filed an appeal with the              4, 2000, and after a hearing on the petition on August 23, Maryland Court of Special Appeals challenging the                2000 issued an order on September 29, 2000 upholding the September 29, 2000 order issued by the Circuit Court. We        Maryland PSC's order on the asset transfer. On October 27, believe that this petition is without merit. However, we        2000, MAPSA filed an appeal with the Maryland Court of cannot predict the timing, or outcome, of this case, which      Special Appeals challenging the September 29, 2000 order could have a material adverse effect on our, and BGE's,          issued by the Circuit Court. We also believe that this petition financial results.                                              is without merit. However, we cannot predict the timing, or outcome, of this case, which could have a material adverse effect on our, and BGE's, financial results.
On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals.
Item 5. Other Information Forward-Looking Statements We make statements in this report that are considered
MAPSA subsequently filed several appeals with the Maryland Court of Special Appeals, the Maryland Court of Appeals, and the Baltimore City Circuit Court. The effect of the appeals was to delay the implementation of customer choice in BGE's service territory.
* operating our generation assets in a deregulated forward-looking statements within the meaning of the                   market without the benefit of a fuel rate adjustment Securities Exchange Act of 1934. Sometimes these                       clause, statements will contain words such as "believes,"
However, on August 4, 2000, the delay was rescinded and BGE retroactively adjusted its rates as if customer choice had been implemented July 1, 2000. On September 29, 2000, the Baltimore City Circuit Court issued an order upholding the Restructuring Order. On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. We believe that this petition is without merit. However, we cannot predict the timing, or outcome, of this case, which could have a material adverse effect on our, and BGE's, financial results.Asset Transfer Order On July 6, 2000, MAPSA and Shell Energy LLC filed, in the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the transfer of BGE's generation assets issued on June 19, 2000. The Court denied MAPSA's request for a delay on August 4, 2000, and after a hearing on the petition on August 23, 2000 issued an order on September 29, 2000 upholding the Maryland PSC's order on the asset transfer.
                                                                  °    loss of revenue due to customers choosing "expects," "intends," "plans," and other similar words.               alternative suppliers, These statements are not guarantees of our future performance and are subject to risks, uncertainties and
On October 27, 2000, MAPSA filed an appeal with the Maryland Court of Special Appeals challenging the September 29, 2000 order issued by the Circuit Court. We also believe that this petition is without merit. However, we cannot predict the timing, or outcome, of this case, which could have a material adverse effect on our, and BGE's, financial results.Item 5. Other Information Forward-Looking Statements We make statements in this report that are considered forward-looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "expects," "intends," "plans," and other similar words. These statements are not guarantees of our future performance and are subject to risks, uncertainties and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to: "* general economic, business, and regulatory conditions, "* energy supply and demand, "* competition,
* higher volatility of earnings and cash flows, other important factors that could cause our actual
* federal and state regulations,
* increased financial requirements of our nonregulated performance or achievements to be materially different                 subsidiaries, from those we project. These risks, uncertainties, and
* availability, terms, and use of capital,
* inability to recover all costs associated with factors include, but are not limited to:                               providing electric retail customers service during the electric rate freeze period, and
* nuclear and environmental issues,
  "* general economic, business, and regulatory conditions,                                                °     implications from the transfer of BGE's generation assets and related liabilities to nonregulated
* weather,
  "*  energy supply and demand, subsidiaries of Constellation Energy, including the
* implications of the Restructuring Order issued by the Maryland PSC, including the outcome of MAPSA's appeal,
  "*  competition,                                                    outcome of an appeal of the Maryland PSC's Order
* commodity price risk,* operating our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause, ° loss of revenue due to customers choosing alternative suppliers,
* federal and state regulations,                                  regarding the transfer of generation assets.
* higher volatility of earnings and cash flows,
* availability, terms, and use of capital,                  Given these uncertainties, you should not place undue
* increased financial requirements of our nonregulated subsidiaries,
* nuclear and environmental issues,                          reliance on these forward-looking statements. Please see
* inability to recover all costs associated with providing electric retail customers service during the electric rate freeze period, and ° implications from the transfer of BGE's generation assets and related liabilities to nonregulated subsidiaries of Constellation Energy, including the outcome of an appeal of the Maryland PSC's Order regarding the transfer of generation assets. Given these uncertainties, you should not place undue reliance on these forward-looking statements.
* weather,                                                  the other sections of this report and our other periodic
Please see the other sections of this report and our other periodic reports filed with the SEC for more information on these factors. These forward-looking statements represent our estimates and assumptions only as of the date of this report.37 Item 6. Exhibits and Reports on Form 8-K (a) Exhibit No. 3 Exhibit No. 12(a) Exhibit No. 12(b) Exhibit No. 27(a) Exhibit No. 27(b)By-laws of Constellation Energy Group, Inc. Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
* implications of the Restructuring Order issued by          reports filed with the SEC for more information on these the Maryland PSC, including the outcome of                factors. These forward-looking statements represent our estimates and assumptions only as of the date of this MAPSA's appeal, report.
Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
* commodity price risk, 37
Constellation Energy Group, Inc. Financial Data Schedule.
 
Baltimore Gas and Electric Company Financial Data Schedule.(b) Reports on Form 8-K for the quarter ended September 30, 2000: Items Reported Item 2. Acquisition or Disposition of Assets Item 7. Financial Statements and Exhibits 38 Date Filed July 7, 2000 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Item 6. Exhibits and Reports on Form 8-K (a) Exhibit No. 3             By-laws of Constellation Energy Group, Inc.
CONSTELLATION ENERGY GROUP, INC. (Registrant)
Exhibit No. 12(a)        Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.
Exhibit No. 12(b)          Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.
Exhibit No. 27(a)          Constellation Energy Group, Inc. Financial Data Schedule.
Exhibit No. 27(b)          Baltimore Gas and Electric Company Financial Data Schedule.
(b)   Reports on Form 8-K for the quarter ended September 30, 2000:
Date Filed                Items Reported July 7, 2000              Item 2. Acquisition or Disposition of Assets Item 7. Financial Statements and Exhibits 38
 
SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)
November 14, 2000 Is/ D.A. Brune D. A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 39 Date:
Date:        November 14, 2000                                               Is/ D.A. Brune D. A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 39
EXHIBIT 12(a) CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 12 Months Ended September December December December 2000 1999 1998 1997 (In Millions of Dollars)Income from Continuing Operations (Before Extraordinary Loss) Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends Adjusted Income Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness Earnings required for BGE Preference Stock Dividends Capitalized Interest Interest Factor in Rentals Total Fixed Charges "x"-a-ramings (1) Ratio of Earnings to Fixed Charges$ 298.7 $ 326.4 $ 305.9 $ 254.1 $ 272.3 $ 297.4 192.3 182.5 169.3 145.1 148.3 152.0 $ 491.0 $ 508.9 $ 475.2 $ 399.2 $ 420.6 $ 449.4 $ 256.5 $ 245.7 $ 255.3 $ 234.2 $ 203.9 $ 206.7 21.4 21.0 33.8 45.1 59.4 61.0 11.6 2.7 3.6 8.4 15.7 15.0 2.2 1.8 1.9 1.9 1.5 2.1 $ 291.7 $ 271.2 $ 294.6 $ 289.6 $ 280.5 $ 284.8 $ 771.1 $ 777.4 $ 766.2 $ 680.4 $ 685.4 $ 719.2 2.64 2.87 2.60 2.35 2.44 2.52 (1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest.December 1996 December 1995 EXHIBIT 12(b)BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS 12 Months Ended September December December December 2000 1999 1998 1997 (In Millions of Dollars)Income from Continuing Operations (Before Extraordinary Loss) Taxes on Income Adjusted Income Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness Capitalized Interest Interest Factor in Rentals Total Fixed Charges Preferred and Preference Dividend Requirements:
 
(1) -Preferred and Preference Dividends Income Tax Required Total Preferred and Preference Dividend Requirements Total Fixed Charges and Preferred and Preference Dividend Requirements Earnings (2) Ratio of Earnings to Fixed Charges Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements December December 1996 1995$ 146.0 $ 328.4 $ 327.7 $ 282.8 $ 310.8 $ 338.0 91.0 182.0 181.3 161.5 169.2 172.4 $ 237.0 $ 510.4 $ 509.0 $ 444.3 $ 480.0 $ 510.4 $ 184.1 $ 206.4 $ 255.3 $ 234.2 $ 203.9 $ 206.7 -0.4 3.6 8.4 15.7 15.0 0.9 1.0 1.9 1.9 1.5 2.1 $ 185.0 $ 207.8 $ 260.8 $ 244.5 $ 221.1 $ 223.8 $ 13.2 $ 13.5 $ 21.8 $ 28.7 $ 38.5 $ 40.6 8.2 7.5 12.0 16.4 20.9 20.4 $ 21.4 $ 21.0 $ 33.8 $ 45.1 $ 59.4 $ 61.0 $ 206.4 $ 228.8 $ 294.6 $ 289.6 $ 280.5 $ 284.8 $ 422.0 $ 717.8 $ 766.2 $ 680.4 $ 685.4 $ 719.2 2.28 2.04 3.45 3.14 2.94 2.60 2.78 2.35 3.10 2.44 3.21 2.52 (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.
EXHIBIT 12(a)
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 12 Months Ended September     December      December December             December  December 2000         1999         1998             1997         1996      1995 (In Millions of Dollars)
Income from Continuing Operations (Before Extraordinary Loss)               $     298.7 $       326.4 $       305.9 $         254.1   $   272.3 $   297.4 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends                192.3         182.5         169.3           145.1       148.3     152.0 Adjusted Income                              $     491.0 $       508.9 $       475.2 $         399.2 $     420.6 $   449.4 Fixed Charges:
Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness          $     256.5 $       245.7 $       255.3     $     234.2 $     203.9 $   206.7 Earnings required for BGE Preference Stock Dividends                            21.4         21.0           33.8             45.1       59.4       61.0 Capitalized Interest                            11.6           2.7           3.6             8.4       15.7       15.0 Interest Factor in Rentals                      2.2           1.8           1.9             1.9         1.5       2.1 Total Fixed Charges                      $     291.7 $       271.2 $       294.6 $         289.6 $     280.5 $   284.8 "x"-a-ramings(1)                                $     771.1 $       777.4 $       766.2 $         680.4 $     685.4 $   719.2 Ratio of Earnings to Fixed Charges                  2.64         2.87           2.60             2.35       2.44       2.52 (1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest.
 
EXHIBIT 12(b)
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS 12 Months Ended September   December    December December             December     December 2000         1999         1998             1997         1996        1995 (In Millions of Dollars)
Income from Continuing Operations (Before Extraordinary Loss)               $     146.0 $     328.4 $     327.7 $           282.8 $   310.8 $       338.0 Taxes on Income                                      91.0       182.0         181.3           161.5       169.2       172.4 Adjusted Income                              $     237.0 $     510.4 $     509.0 $         444.3 $     480.0 $       510.4 Fixed Charges:
Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness          $     184.1 $     206.4 $     255.3 $           234.2 $   203.9 $       206.7 Capitalized Interest                              -           0.4           3.6             8.4       15.7         15.0 Interest Factor in Rentals                          0.9         1.0           1.9             1.9         1.5         2.1 Total Fixed Charges                      $     185.0 $     207.8 $     260.8 $           244.5 $   221.1 $       223.8 Preferred and Preference Dividend Requirements: (1)
-  Preferred and Preference Dividends      $       13.2 $     13.5 $       21.8 $           28.7 $     38.5 $       40.6 Income Tax Required                                8.2       7.5         12.0             16.4       20.9         20.4 Total Preferred and Preference Dividend Requirements                $       21.4 $       21.0 $       33.8 $           45.1 $     59.4 $       61.0 Total Fixed Charges and Preferred and Preference Dividend Requirements $         206.4 $     228.8 $     294.6 $           289.6 $   280.5 $       284.8 Earnings (2)                                $     422.0 $     717.8 $     766.2 $           680.4 $   685.4 $       719.2 Ratio of Earnings to Fixed Charges                  2.28         3.45          2.94            2.78        3.10        3.21 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements                            2.04        3.14          2.60             2.35       2.44         2.52 (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock.
(2) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.
 
Exhibit 13A [PROPRIETARY]
Exhibit 13A [PROPRIETARY]
Additional Funding Assurances for Decommissioning Pre Realignment  
Additional Funding Assurances for Decommissioning Pre Realignment & Spin - Constellation Energy Group NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)
& Spin -Constellation Energy Group NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2) NRC minimum requirement for Unit 1 and 82% of Unit 2 (millions)  
NRC minimum requirement for Unit 1 and 82% of Unit 2 (millions)                                       $722 Funds transferred after 2% real rate of return to decommissioning credit (millions)                   $635 Amount assured through Parental Guarantee                                                               $87 FinancialTest II.A.2 Source: September 30, 2000 IO-Q (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy Unsecured Standard & Poor's Rating (September 2000)                                 A Constellation Energy Unsecured Moody's Rating (September 2000)                                           A3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth (Intangible Assets are $43 million)                                                 $3,109 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount)                                 $87 Ratio of Tangible Net Worth to Guarantee Amount                                                         35.7 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth                                                                                     $3,109 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof Total Assets                                                                                           $11,656 Total Foreign Assets                                                                                   $260 Total U.S. Assets                                                                                     $11,396 jAmount of Decommissioning Funds Assured for Unit 1 &2 (Guarantee Amount)                                 $87 I         ot u.S.
$722 Funds transferred after 2% real rate of return to decommissioning credit (millions)  
01atlo    Assets to (Juarantee Amount                                                     I    131.0     1
$635 Amount assured through Parental Guarantee  
 
$87 Financial Test II.A.2 Source: September 30, 2000 IO-Q (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy Unsecured Standard & Poor's Rating (September 2000) A Constellation Energy Unsecured Moody's Rating (September 2000) A3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s));
EXHIBIT 13A (PROPRIETARY)(CONT.)
and Tangible Net Worth (Intangible Assets are $43 million) $3,109 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount) $87 Ratio of Tangible Net Worth to Guarantee Amount 35.7 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth $3,109 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof Total Assets $11,656 Total Foreign Assets $260 Total U.S. Assets $11,396 jAmount of Decommissioning Funds Assured for Unit 1 &2 (Guarantee Amount) $87 I 01atlo ot u.S. Assets to (Juarantee Amount 131.0 1 I EXHIBIT 13A (PROPRIETARY)(CONT.)
Post Realignment & Pre Spin NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)
Post Realignment  
NRC minimum requirement for Unit I and 82% of Unit 2 (millions)                                       $722 Funds transferred after 2% real rate of return to decommissioning credit (millions)                   $635 Amount assured through Parental Guarantee                                                               $87 FinancialTest II.A.2 Source: Proforma September 30, 2000 (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy Unsecured Standard & Poor's Rating (September 2000)                               A Constellation Energy Unsecured Moody's Rating (September 2000)
& Pre Spin NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2) NRC minimum requirement for Unit I and 82% of Unit 2 (millions)
A3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth (Intangible Assets are $43 million)                                               $3,109 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount)                                 $87 Ratio of Tangible Net Worth to Guarantee Amount                                                         35.7 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth                                                                                   $3,109 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof Total Assets                                                                                         $11,656 Total Foreign Assets                                                                                   $260 Total U.S. Assets                                                                                     $11,396 jAmount of Decommissioning Funds Assured for Unit l&2 (Guarantee Amount)                                 $87 lRatio of U.S. Assets to Guarantee Amount                                                               131.0
Funds transferred after 2% real rate of return to decommissioning credit (millions)
 
Amount assured through Parental Guarantee$722 $635 $87 Financial Test II.A.2 Source: Pro forma September 30, 2000 (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy Unsecured Standard & Poor's Rating (September 2000) Constellation Energy Unsecured Moody's Rating (September 2000)A A3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s));
EXHIBIT 13A (PROPRIETARY)(CONTINUED)
and Tangible Net Worth (Intangible Assets are $43 million) $3,109 Amount of Decommissioning Funds Assured for Unit 1 &2 (Guarantee Amount) $87 Ratio of Tangible Net Worth to Guarantee Amount 35.7 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth $3,109 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof Total Assets $11,656 Total Foreign Assets $260 Total U.S. Assets $11,396 jAmount of Decommissioning Funds Assured for Unit l&2 (Guarantee Amount) $87 lRatio of U.S. Assets to Guarantee Amount 131.0 EXHIBIT 13A (PROPRIETARY)(CONTINUED)
Post Realignment & Post Spin NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)
Post Realignment  
NRC minimum requirement for Unit I and 82% of Unit 2 (millions)                                       $722 Funds transferred after 2% real rate of return to decommissioning credit (millions)                   $635 Amount assured through Parental Guarantee                                                               $87 FinancialTest II.A.2 Source: Proforma September 30, 2000 (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy expects to be investment grade after the spin (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth                                                                                   $1,467 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount)                                 $87 Ratio of Tangible Net Worth to Guarantee Amount                                                         16.9 (iii) Tangible net worth of at least $10 million; and
& Post Spin NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2) NRC minimum requirement for Unit I and 82% of Unit 2 (millions)
[Tangible Net Worth                                                                                   $1,467 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof.
Funds transferred after 2% real rate of return to decommissioning credit (millions)
Total Assets                                                                                         $6,236 Total Foreign Assets                                                                                     $
Amount assured through Parental Guarantee$722 $635 $87 Financial Test II.A.2 Source: Pro forma September 30, 2000 (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy expects to be investment grade after the spin (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s));
Total U.S. Assets                                                                                     $6,236 IAmount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount)                                 $87 IRatio of U.S. Assets to Guarantee Amount                                                               71.7
and Tangible Net Worth $1,467 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount) $87 Ratio of Tangible Net Worth to Guarantee Amount 16.9 (iii) Tangible net worth of at least $10 million; and [Tangible Net Worth $1,467 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof.
 
Total Assets $6,236 Total Foreign Assets $ Total U.S. Assets $6,236 IAmount of Decommissioning Funds Assured for Unit 1 &2 (Guarantee Amount) $87 IRatio of U.S. Assets to Guarantee Amount 71.7 Exhibit 14 10 CFR § 50.75 (c) CALCULATION WORKSHEETS Unit 1 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt) BWR Formula Base 1986 Cost (1986$) Adjustment Factor (2000$) Adjusted Amount (2000$)1,850 (104+0.009*1,850) 120,650,000 3.1213 376,583,056 NRC Adjustment Factor Calculation NRC Adjustment Formula Factor L Factc Weight 0.65 2000$ 1.7790 1.2 0.65 L + 0.13 E + 0.22 B or E Factor B 0.13 0.22 2565 8.1890 1.1564 0.1633 1.8016 NRC Adjustment Factor 3.1213 Energy Factor Calculation Energy Factor Formula Px: Power Factor Fx: Fuel Oil Factor 1986$ 114.2 82 09/2000$ 137.6 108.0 0.54Px + 0.46Fx Factor 1.2049 1.3171 1.2565 Energy Factor Labor Factor Calculation 1986$ 09/2000$ Factor 130.5 232.16 1.7790 Exhibit 14 (Continued)
Exhibit 14 10 CFR § 50.75 (c) CALCULATION WORKSHEETS Unit 1 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt)                                           1,850 BWR Formula                                       (104+0.009*1,850)
Unit 2 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt) BWR Formula Base 1986 Cost (1986$) Adjustment Factor (2000$) Adjusted Amount (2000$) 82% of Adjusted Amount 3,467 >3400MWt = 135 135,000,000 3.1213 421,373,499 345,526,269 NRC Adjustment Factor Calculation NRC Adjustment Formula Factor L Weight 0.65 2000$ 1.7790 Factor E 0.13 1.2565 0.65 L + 0.13 E + 0.22 B Factor B 0.22 8.1890 3.1213 1. lb654 0.16r33 .816.U NRC Adjustment Factor Energy Factor Calculation Energy Factor Formula Px: Power Factor Fx: Fuel Oil Factor Energy Factor 1986$ 114.2 82 09/2000$ 137.6 108.0 0.54Px + 0.46Fx Factor 1.2049 1.3171 1.2565 Labor Factor Calculation 1986$ 09/2000$ 130.5 232.16 Factor 1.7790 Exhibit 15A [PROPRIETARY]
Base 1986 Cost (1986$)                                 120,650,000 Adjustment Factor (2000$)                                   3.1213 Adjusted Amount (2000$)                               376,583,056 NRC Adjustment Factor Calculation NRC Adjustment Formula                     0.65 L + 0.13 E + 0.22 B Factor L Factcor E Factor B Weight          0.65      0.13       0.22 2000$        1.7790    1.22565    8.1890 1.1564   0.1633     1.8016 NRC Adjustment Factor                                       3.1213 Energy Factor Calculation Energy Factor Formula                               0.54Px + 0.46Fx 1986$     09/2000$   Factor Px: Power Factor        114.2      137.6     1.2049 Fx: Fuel Oil Factor      82        108.0     1.3171 Energy Factor                                                 1.2565 Labor Factor Calculation 1986$     09/2000$     Factor 130.5     232.16   1.7790
PROJECTIONS OF EARNINGS CREDIT ON DECOMMISSIONING FUNDS USING 2% ANNUAL REAL RATE OF RETURN FOR NMP 1 AND NMP 2 Unit 1 Proiected Fund Performance and Underfunding Calculation Funds Transferred at Closing Non-Qualified Funds Qualified Funds I otal t-unds 76,800,000 189,200,000 266,UUU,UUU Beginning Balance 266,000,000 323,684,927 330,158,626 336,761,799 343,497,034 350,366,975 357,374,315 364,521,801 371,812,237 Additional Fund Assurance 54,495,836 Return Rate 2% 2% 2% 2% 2% 2% 2% 2% 2%Fund Earnings 3,189,092 6,473,699 6,603,173 6,735,236 6,869,941 7,007,340 7,147,486 7,290,436 4,770,819 Ending Balance 323,684,927 330,158,626 336,761,799 343,497,034 350,366,975 357,374,315 364,521,801 371,812,237 376,583,056 NRC Minimum Requirement Ending Balance for 2009 Underrunded Amount Additional Funding Assured 376,583,056 376,583,056 54,495,836 2001 fund earnings are propated for 07/01/01 transaction close 2009 fund earnings are prorated for 08/22/09 license expiration Year 2001 2002 2003 2004 2005 2006 2007 2008 2009 Exhibit 15A (PROPRIETARY)(continued)
 
Unit 2 Projected Fund Performance and Underfunding Calculation Funds Transferred at Closing Non-Qualified Funds Qualified Funds Total Funds 3,900,000 172,800,000 176,700,000 Beginning Balance 176,700,000 211,305,178 215,531,281 219,841,907 224,238,745 228,723,520 233,297,990 237,963,950 242,723,229 247,577,693 252,529,247 257,579,832 262,731,429 267,986,058 273,345,779 278,812,694 284,388,948 290,076,727 295,878,262 301,795,827 307,831,743 313,988,378 320,268,146 326,673,509 333,206,979 339,871,119 Additional Fund Return Assurance Rate 32,523,302 2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2% -2%NRC Minimum Requirement Ending Balance for 2009 Underfunded Amount Additional Funding Assured Fund Earnings Ending Balance 2,081,875 4,226,104 4,310,626 4,396,838 4,484,775 4,574,470 4,665,960 4,759,279 4,854,465 4,951,554 5,050,585 5,151,597 5,254,629 5,359,721 5,466,916 5,576,254 5,687,779 5,801,535 5,917,565 6,035,917 6,156,635 6,279,768 6,405,363 6,533,470 6,664,140 5,655,150 345,526,269 345,526,269 32,523,302 211,305,178 215,531,281 219,841,907 224,238,745 228,723,520 233,297,990 237,963,950 242,723,229 247,577,693 252,529,247 257,579,832 262,731,429 267,986,058 273,345,779 278,812,694 284,388,948 290,076,727 295,878,262 301,795,827 307,831,743 313,988,378 320,268,146 326,673,509 333,206,979 339,871,119 345,526,269 2001 fund earnings are prorated for 07/01/01 transaction close 2026 fund earnings are prorated for 10/31/26 license expiration date Year 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Exhibit 16 Affidavit of Robert E. Denton STATE OF MARYLAND ) ) ss CITY OF BALTIMORE ) Robert E. Denton, upon being first duly sworn according to law, under oath, deposes and states: 1. I am President and Chief Executive Officer of Constellation Nuclear, LLC. I have reviewed the information contained in the "Application for Order and Conforming Administrative Amendments for License Transfers (NRC Facility Operating License Nos. DPR-63 and NPF-69)" and Exhibits thereto, and have been authorized by Constellation Nuclear, LLC to file this Affidavit on its behalf with respect to such information.
Exhibit 14 (Continued)
: 2. The information identified within brackets in the "Application for Order and Conforming Administrative Amendments for License Transfers (NRC Facility Operating License Nos. DPR-63 and NPF-69)," and the information in Exhibits 7A, 10A, 11 A, 13A and 16A to the Application contain financial projections related to the operation of Nine Mile Point Units 1 and 2 and confidential financial and corporate information.
Unit 2 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt)                                           3,467 BWR Formula                                         >3400MWt = 135 Base 1986 Cost (1986$)                                   135,000,000 Adjustment Factor (2000$)                                     3.1213 Adjusted Amount (2000$)                                 421,373,499 82% of Adjusted Amount                                   345,526,269 NRC Adjustment Factor Calculation NRC Adjustment Formula                       0.65 L + 0.13 E + 0.22 B Factor L Factor E Factor B Weight            0.65       0.13     0.22 2000$        1.7790      1.2565    8.1890 1.lb654     0.16r33     .816.U NRC Adjustment Factor                                         3.1213 Energy Factor Calculation Energy Factor Formula                                 0.54Px + 0.46Fx 1986$    09/2000$    Factor Px: Power Factor         114.2     137.6     1.2049 Fx: Fuel Oil Factor        82      108.0     1.3171 Energy Factor                                                 1.2565 Labor Factor Calculation 1986$     09/2000$   Factor 130.5   232.16   1.7790
These documents constitute proprietary commercial and financial information that should be held in confidence by the Nuclear Regulatory Commission pursuant to 10 CFR§ 9.17(a)(4) and the policy reflected in 10 CFR§ 2.790, because: (i) This information is of a type that is held in confidence by Constellation Energy Group, Inc. and Constellation Nuclear, LLC and there is a rational basis for doing so because the information contains sensitive financial information concerning the projected revenues and operating expenses of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities.  (ii) This information is being and has been held in confidence by Constellation Energy Group, Inc. and Constellation Nuclear, LLC.  (iii) This information is being transmitted to the Nuclear Regulatory Commission in confidence.  (iv) This information is not available in public sources and could not be gathered readily from other publicly available information.  (v) Public disclosure of this information would create substantial harm to the competitive position of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities by disclosing internal financial projections for these entities and confidential financial and corporate information to other parties whose commercial interests may be adverse to those of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities.
 
: 3. Accordingly, Constellation Energy Group, Inc. and Constellation Nuclear, LLC request that the designated documents be withheld from public disclosure pursuant to 10 CFR 2.790(a)(4) and 10 CFR 9.17(a)(4).
Exhibit 15A [PROPRIETARY]
Subscribed and sworn to me, a Notary Public, in and for the county and state above named, this .__day of/", 200W1 My Commission Expires: (Notary7 ublic)}}
PROJECTIONS OF EARNINGS CREDIT ON DECOMMISSIONING FUNDS USING 2% ANNUAL REAL RATE OF RETURN FOR NMP 1 AND NMP 2 Unit 1 Proiected Fund Performance and Underfunding Calculation Funds Transferred at Closing Non-Qualified Funds                                       76,800,000 Qualified Funds                                          189,200,000 I otal t-unds                                          266,UUU,UUU Beginning Additional Fund  Return Year        Balance     Assurance      Rate    Fund Earnings  Ending Balance 2001    266,000,000     54,495,836      2%          3,189,092    323,684,927 2002    323,684,927                      2%          6,473,699    330,158,626 2003    330,158,626                      2%          6,603,173    336,761,799 2004    336,761,799                      2%          6,735,236    343,497,034 2005    343,497,034                      2%         6,869,941    350,366,975 2006    350,366,975                      2%          7,007,340   357,374,315 2007    357,374,315                      2%          7,147,486   364,521,801 2008    364,521,801                      2%          7,290,436   371,812,237 2009    371,812,237                      2%          4,770,819   376,583,056 NRC Minimum Requirement                                  376,583,056 Ending Balance for 2009                                  376,583,056 Underrunded Amount Additional Funding Assured                                54,495,836 2001 fund earnings are propated for 07/01/01 transaction close 2009 fund earnings are prorated for 08/22/09 license expiration
 
Exhibit 15A (PROPRIETARY)(continued)
Unit 2 Projected Fund Performance and Underfunding Calculation Funds Transferred at Closing Non-Qualified Funds                                     3,900,000 Qualified Funds                                      172,800,000 Total Funds                                          176,700,000 Beginning     Additional Fund Return Year        Balance        Assurance      Rate Fund Earnings Ending Balance 2001    176,700,000       32,523,302    2%      2,081,875 211,305,178 2002    211,305,178                -    2%      4,226,104 215,531,281 2003    215,531,281                -    2%      4,310,626 219,841,907 2004    219,841,907                -    2%      4,396,838 224,238,745 2005    224,238,745                -    2%      4,484,775 228,723,520 2006    228,723,520                -    2%      4,574,470 233,297,990 2007    233,297,990                -    2%      4,665,960 237,963,950 2008    237,963,950                -    2%      4,759,279 242,723,229 2009    242,723,229                -     2%       4,854,465 247,577,693 2010    247,577,693                -     2%       4,951,554 252,529,247 2011    252,529,247                -     2%       5,050,585 257,579,832 2012    257,579,832                -     2%     5,151,597 262,731,429 2013    262,731,429                -     2%     5,254,629 267,986,058 2014    267,986,058                -     2%     5,359,721 273,345,779 2015    273,345,779                -     2%     5,466,916 278,812,694 2016    278,812,694                -     2%     5,576,254 284,388,948 2017    284,388,948                -     2%     5,687,779 290,076,727 2018    290,076,727                -     2%     5,801,535 295,878,262 2019    295,878,262                -     2%     5,917,565 301,795,827 2020    301,795,827                -     2%     6,035,917 307,831,743 2021    307,831,743                -     2%     6,156,635 313,988,378 2022    313,988,378                -     2%     6,279,768 320,268,146 2023    320,268,146                -     2%     6,405,363 326,673,509 2024    326,673,509                -      2%      6,533,470 333,206,979 2025    333,206,979                -      2%      6,664,140 339,871,119 2026    339,871,119                -      2%      5,655,150 345,526,269 NRC Minimum Requirement                              345,526,269 Ending Balance for 2009                              345,526,269 Underfunded Amount Additional Funding Assured                            32,523,302 2001 fund earnings are prorated for 07/01/01 transaction close 2026 fund earnings are prorated for 10/31/26 license expiration date
 
Exhibit 16 Affidavit of Robert E. Denton STATE OF MARYLAND                      )
                                      ) ss CITY OF BALTIMORE                      )
Robert E. Denton, upon being first duly sworn according to law, under oath, deposes and states:
: 1.      I am President and Chief Executive Officer of Constellation Nuclear, LLC. I have reviewed the information contained in the "Application for Order and Conforming Administrative Amendments for License Transfers (NRC Facility Operating License Nos. DPR-63 and NPF-69)" and Exhibits thereto, and have been authorized by Constellation Nuclear, LLC to file this Affidavit on its behalf with respect to such information.
: 2.      The information identified within brackets in the "Application for Order and Conforming Administrative Amendments for License Transfers (NRC Facility Operating License Nos. DPR-63 and NPF-69)," and the information in Exhibits 7A, 10A, 11 A, 13A and 16A to the Application contain financial projections related to the operation of Nine Mile Point Units 1 and 2 and confidential financial and corporate information. These documents constitute proprietary commercial and financial information that should be held in confidence by the
 
Nuclear Regulatory Commission pursuant to 10 CFR§ 9.17(a)(4) and the policy reflected in 10 CFR§ 2.790, because:
(i)      This information is of a type that is held in confidence by Constellation Energy Group, Inc. and Constellation Nuclear, LLC and there is a rational basis for doing so because the information contains sensitive financial information concerning the projected revenues and operating expenses of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities.
(ii)    This information is being and has been held in confidence by Constellation Energy Group, Inc. and Constellation Nuclear, LLC.
(iii)    This information is being transmitted to the Nuclear Regulatory Commission in confidence.
(iv)    This information is not available in public sources and could not be gathered readily from other publicly available information.
(v)      Public disclosure of this information would create substantial harm to the competitive position of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities by disclosing internal financial projections for these entities and confidential financial and corporate information to other parties whose commercial interests may be adverse to those of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities.
: 3.     Accordingly, Constellation Energy Group, Inc. and Constellation Nuclear, LLC request that the designated documents be withheld from public disclosure pursuant to 10 CFR 2.790(a)(4) and 10 CFR 9.17(a)(4).
Subscribed and sworn to me, a Notary Public, in and for the county and state above named, this
.__day of/",                200W1 My Commission Expires:
(Notary7 ublic)}}

Revision as of 05:01, 24 November 2019

Power Purchase Agreement for NMP 1 and NMP 2
ML010370043
Person / Time
Site: Nine Mile Point  Constellation icon.png
Issue date: 01/30/2001
From: Denton R
Constellation Nuclear
To:
Office of Nuclear Reactor Regulation
References
-RFPFR, NMPIL 1566-P
Download: ML010370043 (233)
v • d • e


Text

Exhibit 8 Power Purchase Agreements for NMP 1 and NMP 2

Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Niagara Mohawk Power Corporation ("CUSTOMER"), a New York company with offices located at 300 Erie Boulevard West, Syracuse, NY 13202 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").

WITNESSETH:

WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");

WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in Nine Mile Point Unit No. 1 Nuclear Generating Station ("NMP-1I"), dated December 11, 2000 (the "NMP-2 APA");

WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &

Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").

NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:

1. DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:

1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include DCLAN01:1!28365. I scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),

and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.4. "Closing" shall have the meaning set forth in the NMP-2 APA.

1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.

1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A.

1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.

1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and DCLANOI:128365.1 transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.

1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.

1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and-Control Area Services Tariff, as amended or superseded from time to time.

1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.

1.12. "Effective Date" shall mean the date of the Closing.

1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, ortransmitted over a period of time, and measured or calculated in megawatt hours (MWh).

1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.

1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council

("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules DCLANO I: 128365.1 and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.

1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.

1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".

1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the Off-Peak Monthly Price Factor for the respective

-Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.

1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.

1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.

1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.

DCLANOI:128365.1 4-

1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.

1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.

1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,

prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.

1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.

inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.

2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is

=exactl ten years after the lastday of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.

4. INSTALLED CAPACITY.

4.1. Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) forty-one percent (41%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum DCLANOI:128365.1 of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.

4.2. Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.

5. ENERGY.

5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) forty-one percent (41%) times (ii)ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.

5.2. Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.

If for any reason which is not-prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.

5.3. Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.

5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by DCLANOI:128365.1 PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.

5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.

5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.

5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.

5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.

5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other

.thantaxes based on PRODUCER's and/or CUSTOMER's net income),

shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.

5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.

DCLANO1: 128365.1

6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
8. BILLINGS AND PAYMENTS.

8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5k" day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth ( 2 5 th) day of the calendar month in which the invoice is rendered. In the event the 25t" is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.

8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.

8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.

DCLAN01:128365.I

8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)

(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note in relation to the NMP-1 APA and the NMP-2 APA against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement, or the NMP-1 Power Purchase Agreement. CUSTOMER hereby acknowledges and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.

9. DEFAULT, TERMINATION AND LIABILITY.

9.1. Breach, Cure and Default.

9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.

9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.

9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such DCLANOI :128365.1 breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii)where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the breach cannot be cured within any commercially reasonable period of time.

9.1.4. Remedies upon Default Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof.

9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.

9.2. Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.

9.3. Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.

DCLANO i: 128365.1 9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.

9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.

10. CONTRACT ADMINISTRATION AND OPERATION.

10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.

10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.

PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.

10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:

If to PRODUCER:

Constellation Nuclear, LLC 39 West Lexington Street DCLANO 1:128365.1 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 If to CUSTOMER:

Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse, NY 13202 Title: Director of Energy Transactions Attn.: Scott Leuthauser Phone: (315) 428-6006 Facsimile: (315) 428-6129 If given by electronic transmission (including telex, facsimile or telecopy),

notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.---

11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.

In addition, the rates, terms, and conditions contained in this Agreement are not DCLAN01:128365.1 'a

subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.

14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
15. DISPUTE RESOLUTION.

15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.

15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.

The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.

15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.

16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be DCLANOI:128365.

-

construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.

17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
18. ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poors Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are DCLAN01:128365.1 satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the

-Assignee-Entity may have any control or management or operational rights or role with respect to the Assignee Entity, and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.

All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.

20. SIGNATORS' AUTHORITYICOUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.

This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.

21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.

DC LANO1:128365.1 DE:ý-'-C TUE - 2;,10 AM ECONO LODGE FXN.3~412 FAX NO. 3IS3431222 P. 06/,l-,

R'M vSkC W'&.C:H7 41 (N1i2. 11!' 19: 15/ST.7 19 14;/-N0 4E6 '79 ',20cE ? 4 IN WITNESS WHEREOF,. 2nd intending to be levelty bound, the Parties hav'e W~ecuted this Agreement by the undersigned duly auihorized representatives as of the date first stated above.

PRODUCER CUSTOMER By: By:

Name* 4UT Namne:

Title: PRF5ioecWfr TM*t:

DATE: December 11. 200 0

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(-- SIdflOd i03fO~d GT:00 0002/ZT/ET

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DEC-11-00 MO0N 21:38 I MKON) 12. 11' 00 IS8:-53/ST. 18:52WK.4861798207 P 2 1Rov S&C WASHINGTON INd WITNE88 WHUIRCOF, and Intending to be legaib' bound, the Paitle hawe duly authoFIlmd representmatie as of the 6www~tad thts Agreement by the undersigned CUSTOMER P~RODUCER Name: Name: WiILLIAM F. r~J.RDW-lP TMtl: "a;r VIC. ?rplvAT A-L~

DATE. Dmmber 11, 2000

SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLANO 1:128365.I

SCHEDULE B "Monthly Price Factors" Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 DCLANOI:128365.I

Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and New York State Electric & Gas Corporation ("CUSTOMER"), a New York company with offices located at Corporate Drive, Kirkwood Industrial Park, Binghamton, NY 13902-5224 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").

WITNESSETH:

WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");

WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &

Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").

NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:

1. DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:

1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),

DCLAN 128366.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.4. "Closing" shall have the meaning set forth in the NMP-2 APA.

1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date.

For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.

1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A.

1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.

1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN128366.1

shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.

1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.

1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.

1.12. "Effective Date" shall mean the date of the Closing.

1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).

1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.

1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council

("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When DCLAN128366.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.

1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.

1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".

1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.

1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.

1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.

1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.

1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.

DCLAN128366.1 4-

1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.

1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,

prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.

1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.

inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.

2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
4. INSTALLED CAPACITY.

4.1. Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.

4.2. Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the DCLAN128366.1 Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.

5. ENERGY.

5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) eighteen percent (18%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.

5.2. Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.

If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.

5.3. Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.

5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.

DCLAN128366.1 5.3.2. Net Electric Output CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.

5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.

5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.

5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.

5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income),

shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.

5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.

6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN128366.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii) the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
8. BILLINGS AND PAYMENTS.

8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth ( 2 5 th) day of the calendar month in which the invoice is rendered. In the event the 2 5th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.

8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.

8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.

8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)

(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement. CUSTOMER hereby acknowledges DCLAN128366.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.

9. DEFAULT, TERMINATION AND LIABILITY.

9.1. Breach, Cure and Default.

9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.

9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.

9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii)where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN128366.1 breach cannot be cured within any commercially reasonable period of time.

9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof.

9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.

9.2. Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.

9.3. Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.

9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.

9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN128366.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.

10. CONTRACT ADMINISTRATION AND OPERATION.

10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.

10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.

PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.

10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:

If to PRODUCER:

Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 DCLAN128366.1 If to CUSTOMER:

New York State Electric & Gas Corporation Corporate Drive Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Title: Senior Vice President Attn.: Jeffrey K. Smith Phone: (607) 762-4440 Facsimile: (607) 762-4345 If given by electronic transmission (including telex, facsimile or telecopy),

notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.

11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.

In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.

DCLAN128366.1

14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
15. DISPUTE RESOLUTION.

15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.

15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.

The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.

15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.

16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.

DCLAN128366.1

17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
18. ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which DCLAN128366.1 have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity, and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.

All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.

20. SIGNATORS' AUTHORITY/COUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.

This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.

21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.

DCLAN128366.1 12/11/00 09:29 FAX HiUBER LAWRENCE & ABELL Q006 FAX NO, 0077024345 P. 01 DEO-11-2000 HN 0'o9 PH OHAIRfA OFFIOE

  • 1 IN WITNESS WHEREOF, and intending to be legally bound, the Parties have eXer-ktAd this Agreement by the undersigned duly authorized reprmentatlvoo as of the date first stated above.

PRODUCER CUSTOMER

!

Name: Name: %",firk'EY C- C ' 7P Title: Tite; S"VJF2,

  • I DATE: December 11, 2000 Rleceived 12-1l-OO 21805 Frou-90771l4045 T1u-NWIDER LAWRNICE &AN Pas 001

2-00 TUE 12:43 AM

.r ECONO LODGE FAX NO. 3153431222 P. 02/03 (MNJ?.I6 9:,'5/sT. ~I4C e1g25?6 Th execut.4WN WITNESS VWHEROp. and intendina to b&"eAlty this Agreenwnt by the undersigned boUnd, the parti.u have duly authorzrpr tvamuoth date first stated above. _idf~eettvaa ft, PRODUCER CUSTOMER By.

Namrne: -A-pgswr- By:

ThtIp OA~r: December 11 2000 C)

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SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLAN128366.1

SCHEDULE B "Monthly Price Factors" Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 DCLAN128366.1

Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Rochester Gas and Electric Corporation ("CUSTOMER"), a New York company with offices located at 89 East Avenue, Rochester, New York 14649 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").

WITNESSETH:

WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");

WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &

Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").

NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:

1. DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:

1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),

DCLAN128368.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.4. "Closing" shall have the meaning set forth in the NMP-2 APA.

1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.

1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A.

1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.

1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN128368 1 shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.

1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.

1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.

1.12. "Effective Date" shall mean the date of the Closing.

1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).

1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.

1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council

("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When DCLAN128368.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.

1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.

1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".

1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.

1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii)the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.

1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.

1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.

1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17199, as amended and superseded from time to time.

DCLAN128368.1 4-

1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.

1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,

prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.

1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.

inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.

2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
4. INSTALLED CAPACITY.

4.1. Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.

4.2. Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the DCLAN 128368.1 Energy generated by the plant. In no event, however, will PRODUCER be required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.

5. ENERGY.

5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) fourteen percent (14%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.

5.2. Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.

If for any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.

5.3. Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.

5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.

DCLAN128368.1 5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.

5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.

5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.

5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.

5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income),

shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.

5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.

6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN128368.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii)the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
8. BILLINGS AND PAYMENTS.

8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5 th) day of the calendar month in which the invoice is rendered. In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.

8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.

8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.

8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)

(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement. CUSTOMER hereby acknowledges DCLAN128368.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.

9. DEFAULT, TERMINATION AND LIABILITY.

9.1. Breach, Cure and Default.

9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.

9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.

9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii)where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN128368.1 breach cannot be cured within any commercially reasonable period of time.

9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii)terminate this Agreement in accordance with Section 9.2 hereof.

9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.

9.2. Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.

9.3. Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.

9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.

9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN128368.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.

10. CONTRACT ADMINISTRATION AND OPERATION.

10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.

10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.

PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.

10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:

If to PRODUCER:

Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 DCLAN128368.1 If to CUSTOMER:

Rochester Gas and Electric Corporation 89 East Avenue Rochester, NY 14649 Title: Senior Vice President Attn.: Paul C. Wilkens Phone: (716) 724-8076 Facsimile: (716) 724-8285 If given by electronic transmission (including telex, facsimile or telecopy),

notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.

11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.

In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.

14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of DCLAN 128368.1 negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
15. DISPUTE RESOLUTION.

15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.

15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.

The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.

15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.

16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and DCLAN 128368.1 therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
18. ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may S DCLAN128368.1 assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity , and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.

All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.

20. SIGNATORS' AUTHORITY/COUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.

This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.

21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.

DCLAN128368.1 DL.EC.-122-00 TUE 12:4C AM ECONO LODGE FAX NO. 3153431222 P.05/13 C ~3~'~;~~ i~~/S. :4,/N"" 48417SE208 P INWITNrI 4e '5eg1ally bound. the Pamiag havo C) executed this Agreement by the undersigned duly authorized represenlativeg date first staled above.

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INWITNESS WHEREOF, and intending to be legally bound, the Parties have executed this Agreement by the undersigned duly authorized representatives as of the date first stated above.

PRODUCER CUSTOMER By:

Name: Name: Pb*d &,'1/6 Title: Title:

DATE: December 11, 2000

SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLAN128368.1

SCHEDULE B "Monthly Price Factors" Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 DCLAN128368.1

Execution Copy PRODUCER - CUSTOMER NMP - 2 POWER PURCHASE AGREEMENT This Power Purchase Agreement (this "Agreement"), dated as of December 11, 2000 by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18th Floor, Baltimore, MD 21201, and Central Hudson Gas & Electric Corporation ("CUSTOMER"), a New York company with offices located at 284 South Avenue, Poughkeepsie, NY 12601 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").

WITNESSETH:

WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit No. 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");

WHEREAS, simultaneously with the execution of this Agreement, PRODUCER, Niagara Mohawk Power Corporation ("Niagara Mohawk") and New York State Electric &

Gas Company ("NYSEG") have executed an Interconnection Agreement of even date with this Agreement (the "NMP-2 ICA") governing the terms of interconnection of NMP-2 with the Transmission System, as that term is defined in the NMP-2 ICA; and WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have executed a Revenue Sharing Agreement of even date with this Agreement governing certain adjustments to the purchase price for NMP-2 (the "NMP-2 RSA").

NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:

1. DEFINITIONS. In addition to the terms defined elsewhere herein, the following capitalized terms shall have the meaning stated below when used in this Agreement:

1.1. "Ancillary Services" shall mean those services necessary to support the transmission of Energy from generators to loads, while maintaining reliable operation of the New York State power system in accordance with Good Utility Practice and reliability rules. Ancillary Services include scheduling, system control and dispatch service, reactive supply and voltage support service, regulation and frequency response service, energy imbalance service, operating reserve service (including spinning reserve, 10-minute non-synchronized reserves and 30-minute reserves),

'I-, DCLAN01:128367.1 and black start capability, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.2. "Bilateral Transaction" shall mean a transaction between two or more parties for the purchase and/or sale of Installed Capacity, Energy, and/or Ancillary Services other than those in the ISO Administered Markets, and as defined in Section 2.16 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.3. "Capability Period" shall mean six-month periods which are established as follows: (1) from May 1 through October 31 of each year (Summer Capability Period); and (2) from November 1 of each year through April 30 of the following year (Winter Capability Period), as defined in Section 2.17 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.4. "Closing" shall have the meaning set forth in the NMP-2 APA.

1.5. "Contract Year" shall mean each twelve (12) month period during the Term (as defined in Section 3 hereof) starting with the Effective Date. For the purposes of this Agreement, the first month of the Term starts on the Effective Date and ends on the last calendar day of the first full calendar month following the Effective Date. All subsequent months during the Term are calendar months.

1.6. "Contract Year Base Price" shall mean the prices so identified in Schedule A.

1.7. "Day-Ahead Market" (DAM) shall mean the NYISO administered market in which Energy and/or Ancillary Services are scheduled and sold day ahead consisting of the day-ahead scheduling process, price calculations and settlements, as defined at Definition 1.7d of the NYISO OATT, as amended or superseded from time to time.

1.8. "DAM Scheduled Net Electric Output" shall mean, for any hour, scheduled electric output with the NYISO in the DAM Market pursuant to Article 5.3, which shall be the Day-Ahead-Market expected Energy production generated by NMP-2 less (a) the Energy used to operate NMP 2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such DAM Scheduled Net Electric Output shall not be less than zero. Such DAM Scheduled Net Electric Output DCLAN01:128367.1 shall be estimated using Good Utility Practice and shall approximate as accurately as reasonably possible the expected Net Electric Output.

1.9. "Delivery Point" shall mean the "Delivery Points" as that term is defined in the NMP-2 ICA and as indicated on the one-line diagram included as part of Schedule A to the NMP-2 ICA.

1.10. "Dependable Maximum Net Capability" (DMNC) shall mean the sustained maximum net output of a generator, as demonstrated by the performance of a test or through actual operation, averaged over a continuous period of time, and as defined in Section 2.40 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.11. "Dependable Maximum Net Capability Test" (DMNC Test) shall mean a test performed in accordance with and as defined in Section 2.40 of the NYISO Services Tariff, as amended or superseded from time to time.

1.12. "Effective Date" shall mean the date of the Closing.

1.13. "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).

1.14. "First Hour" shall mean that full or portion of an hour occurring from the moment that the Parties jointly declare the NMP-2 APA consummated to the beginning of the next hour.

1.15. "Good Utility Practice" shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, expedition and compliance with applicable law and regulations. Good Utility Practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather to be practices, methods, or acts generally accepted in the electric utility industry. Good Utility Practices shall include, where applicable, but not be limited to North American Electric Reliability Council

("NERC") criteria, guidelines, rules and standards, Northeast Power Coordinating Council ("NPCC") criteria, guidelines, rules and standards, New York State Reliability Council ("NYSRC") criteria, guidelines, rules and standards, if any, and NYISO criteria, guidelines, rules and standards, as they may be amended from time to time including the rules, guidelines and criteria of any successor organization of the foregoing entities. When DCLAN01:128367.1 applied to PRODUCER, the term Good Utility Practice shall also include standards applicable to a generator were the generator a utility generator connecting to the distribution or transmission facilities or system of another utility.

1.16. "Installed Capacity" shall mean a generator or load facility that complies with the requirements of the reliability rules and is capable of supplying and/or reducing the demand for Energy in the New York Control Area for the purpose of ensuring that sufficient Energy and capacity are available to meet the reliability rules, as defined at Definition 1.14 of the NYISO OATT, as amended or superseded from time to time. The Installed Capacity requirement, established by the New York State Reliability Counsel and the NYISO, and applied by and through the NYISO OATT, includes a margin of reserve in accordance with the reliability rules.

1.17. "Interest Rate" means, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journal under "Money Rates".

1.18. "Monthly Off-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the Off-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B respectively.

1.19. "Monthly On-Peak Price" shall mean the product of (i) the Contract Year Base Price times (ii) the On-Peak Monthly Price Factor for the respective Contract Years and calendar months, such prices and factors being set forth in Schedules A and B, respectively.

1.20. "New York Control Area" (NYCA) shall have the meaning as defined Section 1.13 of the NYISO Market Administration and Control Area Services Tariff, as amended or superseded from time to time.

1.21. "New York Independent System Operator" (NYISO) shall mean the not for-profit corporation established in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.

1.22. "NYISO OATT" shall mean the New York Independent System Operator Open Access Transmission Tariff revised as of 12/27/99, as amended and superseded from time to time.

1.23. "NYISO Services Tariff" shall mean the New York Independent System Operator Market Administration and Control Area Services Tariff revised as of 11/17/99, as amended and superseded from time to time.

DC LANO1:128367.1 4-

1.24. "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.

1.25. "Off-Peak" shall mean the hours between 11:00 p.m. and 7:00 a.m.,

prevailing Eastern Time, Monday through Friday, and all hours on Saturday and Sunday, and NERC-defined holidays, or as otherwise decided by the NYISO.

1.26. "On-Peak" shall mean the hours between 7:00 a.m. and 11:00 p.m.

inclusive, prevailing Eastern Time, Monday through Friday, except NERC defined holidays, or as otherwise decided by the NYISO.

2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00 midnight prevailing Eastern Time on the day that is exactly ten years after the last day of the month during which the Effective Date occurs. Notwithstanding any other provision of this Agreement, this Agreement shall become ineffective and shall terminate in the event the NMP-2 APA terminates.
4. INSTALLED CAPACITY.

4.1. Sale of Installed Capacity. PRODUCER shall provide, and CUSTOMER shall accept, from the Effective Date through the end of the first Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) of the DMNC of NMP-2 during the first Capability Period occurring during the Term (up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period). PRODUCER shall provide, and CUSTOMER shall accept, from the end of the first Capability Period occurring during the Term through the end of the last Capability Period occurring during the Term an amount of Installed Capacity equal to the product of (i) nine percent (9%) times (ii)ninety percent (90%) of the seasonal DMNC of NMP-2 up to a maximum of 1,140 MW for the Summer Capability Period and 1,155 MW for the Winter Capability Period.

4.2. Performance. PRODUCER shall use good faith efforts to ensure that the Installed Capacity for NMP-2 is as high as practicable, consistent with the Energy generated by the plant. In no event, however, will PRODUCER be DCLAN01:128367.1 required to contract for, or take any other measure to obtain, additional installed capacity to satisfy its obligations under this Section. In accordance with NYISO requirements, PRODUCER shall perform DMNC Tests and PRODUCER shall use good faith efforts to maximize the output of the plant during such tests. The Parties will coordinate the scheduling of such tests.

5. ENERGY.

5.1. Sale of Energy. During the Term of this Agreement, PRODUCER shall deliver, and CUSTOMER shall accept, an amount of Energy equal to the product of (i) nine percent (9%) times (ii) ninety percent (90%) times (iii) the DAM Scheduled Net Electric Output or, if applicable, the Net Electric Output during each hour of the Term up to a maximum total amount of Energy in each such hour of 1,148 MWh.

5.2. Performance. Except as provided in Section 5.3.1, PRODUCER shall have no obligation to produce or deliver any amount of Energy hereunder.

Iffor any reason which is not prohibited by this Agreement PRODUCER generates an insufficient amount of Energy at the facilities to be able to deliver the amount specified in section 5.1 hereof, PRODUCER shall have no obligation to sell or deliver, and CUSTOMER shall have no obligation to buy or accept, the portion of the amount specified in section 5.1 not generated by PRODUCER, or any replacement Energy.

5.3. Scheduling. CUSTOMER shall have the option, exercisable at its sole discretion and upon written notice twenty-four (24) hours in advance of the NYISO's scheduling requirement for provision of the DAM schedule to PRODUCER to: (i) have PRODUCER deliver and schedule DAM Scheduled Net Electric Output as provided in section 5.3.1 below; or (ii) have PRODUCER deliver and CUSTOMER schedule Net Electric Output as provided in Section 5.3.2 below.

5.3.1. DAM Scheduled Net Electric Output. Notwithstanding Section 5.2, PRODUCER shall provide the NYISO with a request for a Bilateral Transaction schedule in the Day-Ahead Market, in accordance with the NYISO Market Administration and Control Area Services Tariff, for the DAM Scheduled Net Electric Output to be delivered to CUSTOMER under this Agreement. PRODUCER shall be solely responsible for all charges imposed by the NYISO as a result of any failure by PRODUCER to deliver the amount of DAM Scheduled Net Electric Output specified in the Bilateral Transaction schedule.

DC_LAN01:128367.1

5.3.2. Net Electric Output. CUSTOMER shall effectuate the scheduling with the NYISO for Net Electric Output delivered by PRODUCER to CUSTOMER under this Agreement.

5.3.3. Mitigation. The Party scheduling a Bilateral Transaction with the NYISO shall be obligated to mitigate any charges or penalties imposed by the NYISO on the non-scheduling Party.

5.4. Other Costs. With regard to DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement at the Delivery Point, except as the NMP-2 ICA provides, PRODUCER shall bear no cost or liability for the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output beyond the Delivery Point.

5.5. Title and Risk of Loss. Title and risk of loss transfers from PRODUCER to CUSTOMER upon receipt of the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output by CUSTOMER from PRODUCER at the Delivery Point.

5.6. Taxes. Taxes applicable to the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output delivered by PRODUCER to CUSTOMER pursuant to this Agreement, or to transactions involving such DAM Scheduled Net Electric Output or, if applicable, Net Electric Output, (other than taxes based on PRODUCER's and/or CUSTOMER's net income),

shall be borne by CUSTOMER if related to or arising after receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output, and shall be borne by PRODUCER if related to or arising before receipt at the Delivery Point of such DAM Scheduled New Electric Output or, if applicable, Net Electric Output.

5.7. Outages. PRODUCER shall schedule and perform all plant outages consistent with Good Utility Practice, and in accordance with the terms of the NMP-2 ICA. PRODUCER shall provide CUSTOMER with as much advance notice as possible of scheduled outages, unscheduled outages, power reductions, and deratings. Except as reasonably required by Good Utility Practice, PRODUCER shall not schedule any portion of a refueling outage during the months of June, July, August, or September.

6. OTHER PRODUCTS AND SALES. Nothing herein shall preclude PRODUCER from selling any Ancillary Service, Energy, Installed Capacity or other product or service or quantity thereof associated with NMP-2 to a third party or the NYISO not needed to fulfill PRODUCER's obligations hereunder.
7. PRICE. The price during each hour of the Term for such amount of Installed Capacity and Energy as is provided pursuant to Article 4 and Article 5 DCLAN01:128367.1 respectively of this Agreement, shall be determined using the data set forth in Schedules A and B. The amounts payable by CUSTOMER to PRODUCER shall be calculated monthly, and shall be equal to the sum of the product of (i) the DAM Scheduled Net Electric Output or, if applicable, Net Electric Output in MWh delivered by PRODUCER to CUSTOMER each hour times (ii)the applicable price for each hour as determined from Schedules A and B for all hours of the month. No other amount shall be payable by CUSTOMER for Installed Capacity or Energy provided by PRODUCER pursuant to this Agreement.
8. BILLINGS AND PAYMENTS.

8.1. Payment. PRODUCER shall provide CUSTOMER with an invoice setting forth the quantity of Energy (MWh), as recorded by the Revenue Meters defined and provided for in the NMP-2 ICA, which was delivered to CUSTOMER in the indicated month, on or before the 5 th day of each month for the preceding monthly period. CUSTOMER shall remit the amount due by wire transfer, or as otherwise agreed, pursuant to PRODUCER's invoice instructions, on the later of fifteen days from receipt of PRODUCER's invoice or the twenty-fifth (2 5th) day of the calendar month in which the invoice is rendered. In the event the 2 5 th is a weekend day or a holiday on which banking institutions are not open in New York State, then payment shall be made upon the following business day.

8.2. Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including, the due date to, but excluding, the date of payment.

8.3. Billing Dispute. If CUSTOMER, in good faith, disputes an invoice, CUSTOMER shall notify PRODUCER in writing within ten (10) business days of receipt of the invoice of the basis for the dispute and pay the portion of such statement not in dispute no later than the due date. If any amount withheld under dispute by CUSTOMER is ultimately determined (under the terms herein) to be due to PRODUCER, it shall be paid within three (3) business days of such determination along with interest accrued at the Interest Rate until the date paid. Inadvertent overpayments shall be returned by PRODUCER upon request or deducted by PRODUCER from subsequent invoices, with interest accrued at the Interest Rate until the date paid or deducted.

8.4. Mutual Rights of Offset. PRODUCER hereby acknowledges and agrees that, if an "Event of Default" has occurred under the promissory note(s)

(such Event as defined therein) executed by PRODUCER in favor of CUSTOMER at the Closing (the "Note"), CUSTOMER shall have the right to offset and/or net any payments then owed by PRODUCER under the Note against any payments or other amounts due from CUSTOMER to PRODUCER under this Agreement. CUSTOMER hereby acknowledges DCLAN01:128367.1 and agrees that, if CUSTOMER is deemed to be in default hereunder (as defined herein in Section 9.1.3 hereof), then PRODUCER may offset and/or net payments then owed by CUSTOMER hereunder against any payments or other amounts due from PRODUCER to CUSTOMER under the Note. Notwithstanding the foregoing, if pursuant to Section 14 of the Note, a Surety Bond, Letter of Credit or other financial assurance shall have been provided by CUSTOMER under the Note, PRODUCER's right of offset shall be deemed to no longer apply to the Note, and shall apply only to such Surety Bond, Letter of Credit or other financial assurance.

9. DEFAULT, TERMINATION AND LIABILITY.

9.1. Breach, Cure and Default.

9.1.1. Breach. A breach of this Agreement shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement as described in Section 9.1.2. of this Agreement.

9.1.2. Events of Breach. A breach of this Agreement shall include: (a) the failure to pay any amount due, unless such amount is disputed in compliance with Section 8.3 of this Agreement; (b) the failure to comply with any material term or condition of this Agreement; (c) the appointment of a receiver, liquidator or trustee for a Party, or of any property of a Party, if such receiver, liquidator or trustee is not discharged within sixty (60) days; (d) the entry of a decree adjudicating a Party bankrupt or insolvent if such decree is continued undischarged and unstayed for a period of sixty (60) days; and (e) the filing by a Party of a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law.

9.1.3. Cure and Default. Upon a Party's breach of its obligations under this Agreement, (except for breaches described in (c), (d), and (e) of Section 9.1.2, whose occurrence shall constitute a default by the Party), the other Party (hereinafter the "Non-Breaching Party") shall give such Party in breach (the "Breaching Party") a written notice specifying the nature of the breach, describing the breach in reasonable detail, and demanding that the Breaching Party cure such breach. The Breaching Party shall be deemed to be in default of its obligations under this Agreement (i) if it fails to cure its breach within thirty (30) days after its receipt of such notice, (ii) where the breach is such that it cannot be cured within thirty (30) days after its receipt of such notice, the Breaching Party does not in good faith commence within thirty (30) days all such steps as are commercially reasonable efforts that are necessary and appropriate to cure such breach and thereafter diligently pursue such steps to completion, or (iii) where the DCLAN01:128367.1 breach cannot be cured within any commercially reasonable period of time.

9.1.4. Remedies upon Default. Upon a Party's default as described in Section 9.1.3, the non-defaulting Party may, at its option (i) continue performance under this Agreement and exercise such other rights and remedies as it may have in equity, at law or under this Agreement; or (ii) terminate this Agreement in accordance with Section 9.2 hereof.

9.1.5. Waiver. No provision of this Agreement may be waived except by mutual agreement of the Parties as expressed in writing and executed by each Party. Any waiver that is not in writing and executed by each Party shall be null and void from its inception. No express waiver in any specific instance as provided in a required writing shall be construed as a waiver in future instances unless specifically so provided in the required writing. No express waiver of any specific default shall be deemed a waiver of any other default whether or not similar to the default waived, or a continuing waiver of any other right or default by a Party. The failure of any Party to insist in any one or more instances upon the strict performance of any of the provisions of this Agreement, or to exercise any right herein, shall not be construed as a waiver or relinquishment for the future of such strict performance of such provision or the exercise of such right. Further, delay by any Party in enforcing its rights under this Agreement shall not be deemed a waiver of such rights.

9.2. Termination. If a Breaching Party is deemed to be in default as described in Section 9.1.3, then the Non-Breaching Party may terminate this Agreement by providing ten (10) days advanced written notice to the Party in default. Termination of this Agreement shall not relieve any Party of any of their liabilities and obligations arising hereunder prior to the date termination becomes effective.

9.3. Additional Remedies. A Party's right to terminate as the result of an occurrence of a default of any other Party shall not serve to limit the rights such non-defaulting Party may have under law or equity as a result of such default.

9.4. Mitigation of Damages. A non-defaulting Party has a duty to mitigate damages in the event of a default. The provisions of this Section 9.4 shall survive termination of this Agreement.

9.5. Exclusion of Damages. In no event will either Party be liable under this Agreement, or under any cause of action relating to the subject matter of this Agreement, for any special, indirect, incidental, punitive, exemplary or consequential damages, including but not limited to loss of profits or DCLAN01:128367.1 revenues, loss of use of any property, cost of substitute equipment, facilities or services, downtime costs or claims of third parties for such damages, except to the extent that such damages arise from the gross negligence or intentional misconduct of the Party from whom such damages are sought. The provisions of this Section 9.5 shall survive termination of this Agreement.

10. CONTRACT ADMINISTRATION AND OPERATION.

10.1. Party Representatives. PRODUCER and CUSTOMER shall each appoint a representative who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.

10.2. Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities or the NYISO. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER.

PRODUCER and CUSTOMER, on a confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.

10.3. Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:

Ifto PRODUCER:

Constellation Nuclear, LLC 39 West Lexington Street 18th Floor Baltimore, MD. 21201 Title: President Attn: Robert E. Denton Phone: (410) 234-6149 Facsimile: (410) 234-5323 DCLAN01:128367.1 If to CUSTOMER:

Central Hudson Gas & Electric Corporation 284 South Avenue Poughkeepsie, NY 12601 Title: Senior Vice President Attn.: Arthur R. Upright Phone: (845) 486-5247 Facsimile: (845) 486-5782 If given by electronic transmission (including telex, facsimile or telecopy),

notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s), including its Company Representative, and the address to which notices are to be sent.

11. BUSINESS RELATIONSHIP. Each Party shall be solely liable for the payment of all wages, taxes, and other costs related to the employment by such Party of persons who perform this Agreement, including all federal, state, and local income, social security, payroll and employment taxes and statutorily-mandated workers' compensation coverage. None of the persons employed by either Party shall be considered employees of the other Party for any purpose.
12. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret protection from such authority and notify the other Party of the requirement.
13. GOVERNMENT REGULATION. This Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.

In addition, the rates, terms, and conditions contained in this Agreement are not subject to change under Section 205 of the Federal Power Act, as that section may be amended or superseded, absent the mutual written agreement of the Parties.

14. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of DC_LAN01:128367.1 negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof. Litigation of claims or disputes arising under this Agreement shall be brought in state or federal court in the State of New York.
15. DISPUTE RESOLUTION.

15.1. All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.

15.2. Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party.

The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid. Judgment may be entered upon the arbitration opinion and award in any court having jurisdiction.

15.3. The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.

16. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
17. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and DC LAN01 :128367.1 therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
18. ENTIRE AGREEMENT. This Agreement, including references to and incorporation of other agreements and tariffs, contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
19. ASSIGNMENT. CUSTOMER shall have the right to assign the Agreement in whole or in part, subject to a 50 MW minimum, without the consent of the PRODUCER, (A) provided that (i) such assignee's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade rated, and (ii) provided that the CUSTOMER's agreement with the assignee requires that for so long as the assignee's credit rating is reduced to the lesser of (a) below investment grade or (b) below its credit rating at the time of the assignment, the assignee shall deliver to PRODUCER, in a form reasonably satisfactory to PRODUCER, either (x) a guarantee of the assignee's obligations by its parent provided that such parent entity's long-term unsecured debt credit rating issue by Moody's Investors Service, Standard & Poor's Corporation or another nationally recognized rating agency is investment grade, or (y) an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee and then remain, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes or reestablishes the lesser of (a) an investment grade rating or (b) its credit rating at the time of the assignment); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain; or (B) to an entity that does not have an investment grade rating, provided that CUSTOMER's agreement with the assignee requires that the assignee deliver, in a form reasonably satisfactory to PRODUCER, an irrevocable, standby letter of credit issued by a banking or other financial institution, the long-term unsecured debt obligations of which is rated investment grade, with a drawing amount equal to the obligations under this Agreement which have been assigned to the assignee, and that such security remain in full force and effect until all amounts owed to the PRODUCER by the assignee are satisfied and paid in full (or such assignee establishes an investment grade rating); and provided, however, that assignee may reduce the drawing amount under such letter of credit from time to time provided such drawing amount is not less than the aggregated amount of the obligations under this Agreement which have been assigned and then remain. PRODUCER shall not have the right to assign this Agreement without CUSTOMER's prior written consent, provided that PRODUCER or its permitted assignee, without CUSTOMER's consent, may DCLAN01:128367.1 assign, transfer, pledge or otherwise dispose of (absolutely or as security) its rights and interests hereunder to an Affiliate (an "Assignee Entity") of PRODUCER at least 68% of the equity securities of which are owned by PRODUCER; provided, however, (i) any minority owner of the Assignee Entity shall be that entity contemplated to become an equity owner of PRODUCER's affiliated merchant energy group as set forth in that certain press release issued by Constellation Energy Group on October 23, 2000, (ii) no minority owner of the Assignee Entity may have any control or management or operational rights or role with respect to the Assignee Entity , and (iii) no such assignment shall relieve or discharge PRODUCER from any of its obligations hereunder or shall be made if it would reasonably be expected to prevent or materially impede, interfere with or delay the transactions contemplated by this Agreement or materially increase the costs of the transactions contemplated by this Agreement.

All assignments shall consist of the same proportion of Installed Capacity and Energy. Except as provided above, any authorized assignment shall relieve the assigning Party of any obligations or liability under the Agreement to the extent of the assignment.

20. SIGNATORS' AUTHORITY/COUNTERPARTS. The undersigned certify that they are authorized to execute this Agreement on behalf of their respective Party.

This Agreement may be executed in two or more counterparts, each of which shall be an original. It shall not be necessary in making proof of the contents of this Agreement to produce or account for more than one such counterpart.

21. NO DEDICATION OF FACILITIES. No undertaking by PRODUCER or CUSTOMER under any provision of this Agreement shall be deemed to constitute the dedication of any portion of NMP-2 to the public, to CUSTOMER, or to any other entity.
22. OPERATION OF NMP-2. PRODUCER at all times shall operate NMP-2 in accordance with Good Utility Practice.

DCLAN01:128367.1 S14 486 5782 TO 812022936330 P.03 DEC 11 2000 22:37 FR EXECUTIVE IN WITNESS WHEREOF, and Intending to be legally bound, the Parties have executed this Agreement by the undersigned duly authorized representatives as of the date first stated above.

PRODUCER CUSTOMER By:By Name: Name:

Title: Titse: ~ VŽ DATE: December 11,2000

FAX NO, 3153431222 P.

P 03/03 30 DEC-' 12-00 TUE 12:43 AMl ECONO LODGE 3ROY & ~ C X1fON) 12. 11.'00 IS9:151ST 115-VIO 486'i79S214' P 2 I IN W~TNE83 WHEREOF, and In~eiding to~ be )~aly bound. the Pertiee have executed this Agreemrent by the undersignod duty authorized repreaentaetives as of the date first stated above.

PRODUCER CUSTOMER By:

Narn.:

Title- ~e~7 rthle DATE- December ll..2000 (Th 0

SIW):Q -:,310a 000Z/Zl/Z' 6006 ?77-*ON

SCHEDULE A "Contract Year Base Prices" Contract Price Year ($ per MWh) 1 $35.70 2 $35.32 3 $33.95 4 $33.60 5 $33.56 6 $33.23 7 $33.91 8 $34.61 9 $35.32 10 $36.05 DCLAN01:128367.1

SCHEDULE B "Monthly Price Factors" Month On-Peak Off-Peak January 1.1865 0.6746 February 1.1865 0.6746 March 0.9492 0.6133 April 0.9492 0.6133 May 1.4238 0.7052 June 1.6611 0.7359 July 2.1357 0.7666 August 2.1357 0.7666 September 1.6611 0.7359 October 0.9492 0.6133 November 0.9492 0.6133 December 1.1865 0.6746 N-__, DCLAN01:128367.1

Exhibit 9 REVENUE SHARING AGREEMENT FOR NMP 2 BETWEEN NMPC AND NMP LLC

Execution Copy PRODUCER - CUSTOMER NMP-2 REVENUE SHARING AGREEMENT This Revenue Sharing Agreement ("Agreement"), dated as of the 11 th day of December, 2000, by and between Constellation Nuclear, LLC, ("PRODUCER"), a Maryland limited liability company with offices located at 39 West Lexington Street, 18tb Floor, Baltimore, MD 21201, and Niagara Mohawk Power Corporation ("CUSTOMER"),

a New York corporation with offices located at 300 Erie Boulevard West, Syracuse, NY 13202 (PRODUCER and CUSTOMER are each referred to herein as a "Party", and collectively as the "Parties").

WITNESSETH:

WHEREAS, PRODUCER and CUSTOMER have entered into an Asset Purchase Agreement pursuant to which CUSTOMER has agreed to sell and PRODUCER has agreed to purchase, certain interests in the Nine Mile Point Unit 2 Nuclear Generating Station ("NMP-2"), dated December 11, 2000 (the "NMP-2 APA");

WHEREAS, simultaneously with the execution of this Agreement, PRODUCER and CUSTOMER have entered into a Power Purchase Agreement of even date herewith pursuant to which PRODUCER has agreed to sell and CUSTOMER has agreed to purchase certain energy and installed capacity from NMP-2 (the "NMP-2 PPA"); and NOW, THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows:

1. DEFINITIONS.

1.1 "Contract Month" shall mean each consecutive calendar month starting with the calendar month in which the Effective Date occurs and ending with (but including) the calendar month during which the Agreement expires.

1.2 "Contract Quarter' shall mean each consecutive period comprised of three (3) consecutive Contract Months beginning with the Contract Month in which the Effective Date occurs. If the Agreement does not expire on the last day of a Contract Month, then the Contract Month during which the Agreement expires shall constitute a Contract Quarter.

1.3 "Effective Date" shall mean the first full day after the expiration or termination of the NMP-2 PPA pursuant to its terms.

DCLAN01:128295 1

1.4 "Energy" shall mean a quantity of electricity that is bid, produced, consumed, sold, or transmitted over a period of time, and measured or calculated in megawatt hours (MWh).

1.5 "Floor Price" shall mean the price as defined in Section 4.3 of this Agreement.

1.6 "Interest Rate" shall mean, for any date, the interest equal to the prime rate of Citibank as may from time to time be published in The Wall Street Journalunder "Money Rates".

1.7 "Market Capacity Price" shall mean the price as defined in Section 4.3 of this Agreement.

1.8 "Market Energy Price" shall mean the price as defined in Section 4.3 of this Agreement.

1.9 "Market Price" shall mean the price as defined in Section 4.3 of this Agreement.

1.10 "Monthly Price Adjustment" shall mean the value as calculated under Section 4.3 of this Agreement.

1.11 "Monthly "New York Independent System Operator" or "NYISO" shall mean the organization formed in accordance with orders of the Federal Energy Regulatory Commission to administer the operation of, to provide equal access to, and to maintain the reliability of the bulk-power transmission system in New York State, or any successor organization.

1.12 "Negative Price Adjustment Amount" shall mean the value as calculated under Section 4.4 of this Agreement.

1.13 "Net Electric Output" shall mean the Energy production generated by NMP-2 less (a) the Energy used to operate NMP-2, but excluding Off-site Power Service used to operate NMP-2 as defined in the NMP-2 ICA, and (b) the Energy used in the transformation and transmission of electric power to the Delivery Point, provided that for purposes of this Agreement, such Net Electric Output shall not be less than zero.

1.14 "Positive Price Adjustment Amount" shall mean the value as calculated under Section 4.5(i) of this Agreement.

1.15 "Price Adjustment" shall mean the value as calculated under Section 4.3 of this Agreement.

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2. CONDITION PRECEDENT. It is a condition precedent to the obligations of PRODUCER and CUSTOMER under this Agreement that the Closing shall have occurred.
3. TERM. The term ("Term") of this Agreement shall begin on the Effective Date and shall expire at 12:00, midnight, prevailing Eastern Time as applicable on the day that is exactly ten (10) years after the Effective Date.
4. PURCHASE PRICE ADJUSTMENT.

4.1 As adjustments to the purchase price for NMP-2, PRODUCER shall pay to CUSTOMER the Price Adjustments as calculated in this Section 4. An example of the calculation and application of the Price Adjustment described in this Section 4 is set forth in Appendix A hereto.

4.2 A Price Adjustment shall be calculated for each Contract Quarter starting with the Effective Date through the Term of this Agreement.

4.3 The Price Adjustment for each Contract Quarter shall be equal to the sum of the Monthly Price Adjustments for each Contract Month in the Contract Quarter. The Monthly Price- Adjustment for each Contract Month shall be calculated as follows:

Monthly Price Adjustment = [Market Price - (Floor Price x Monthly Base Price Factor)] x forty-one percent (41%) x (the sum of the Net Electric Output during each hour of the Contract Month up to a maximum total amount of Energy in each such hour of 1,148 MWh).

where:

Market Price = Market Energy Price + Market Capacity Price for the respective Contract Month.

Market Energy Price = The average over all hours of the respective Contract Month of the day-ahead locational based market price ("LBMP") paid to producers for energy at the NMP-2 Delivery Point (defined in the NMP-2 Interconnection Agreement) specified and published by the NYISO or, if the NYISO does not specify or publish an LBMP for the NMP-2 Delivery Point, S-DCLAN01:128295 3

the LBMP specified and published by the NYISO for the region in which the NMP-2 Delivery Point is located. In the event the NYISO ceases to provide such prices, the Parties shall in good faith undertake commercially reasonable efforts to agree on a substitute indices to reflect the value of Energy located at the NMP-2 Delivery Point. Failure of the parties to agree to such alternative indices shall constitute a dispute to be resolved in accordance with the provisions of Section 5.4.

Market Capacity Price = The market value of the installed capacity of NMP-2, expressed in $/MWh. The measure will reflect the weighted average of the market prices paid to producers for installed capacity at the NMP-2 Delivery Point as published by the NYISO in its installed capacity auctions.

Where Market Capacity Prices are posted in units of $/kW-month, such conversion to units of $/MWh shall be the result of the posted price in $/kW-month, multiplied by 41.66666, divided-by-the -number of days in the month.

(For example, if the posted price was $1.50

/kW-month for a month which is 30 days long, the $/MWh would be $2.0833/MWh [($1.50 x 41.6666)+30]. Note 41.6666 = 10OOkW/MWh

-24 hours per day). In the event NYISO ceases to provide such prices, the Parties shall in good faith undertake commercially reasonable efforts to agree on a substitute indices to reflect the value of installed capacity located at the NMP-2 Delivery Point. Failure of the parties to agree to such alternative indices shall constitute a dispute to be resolved in accordance with the provisions of Section 5.4.

Floor Price = Set forth in Schedule 1.

Monthly Base Price Factor = Set forth in Schedule 2.

4.4 If the Price Adjustment for a Contract Quarter is negative, PRODUCER shall accrue eighty percent (80%) of that negative DCLAN01:128295 4

Price Adjustment (that 80% defined herein as the "Negative Price Adjustment Amount") to be credited against Positive Price Adjustment Amounts, if any, for subsequent Contract Quarters, thereby reducing such Positive Price Adjustment Amounts until the full amount of such Negative Price Adjustment Amounts has been so credited.

4.5 If the Price Adjustment for a Contract Quarter is positive, PRODUCER shall:

(i) take 80% of that positive Price Adjustment (the 80% defined hlerein as the "Positive Price Adjustment Amount"); then (ii) credit against and reduce the Positive Price Adjustment Amount by the sum of any Negative Price Adjustment Amounts for prior Contract Quarters, to the extent that any such Negative Price Adjustment Amounts have not been credited against Positive Price Adjustment Amounts; then (iii) make payment of the Purchase Price Adjustment in an amount equal to any Positive Price Adjustment Amount remaining after crediting any Negative Price Adjustment Amounts as described in (ii) above.

4.6 Negative Price Adjustment Amounts calculated with respect to a Contract Quarter shall only be credited against Positive Price Adjustment Amounts, if any, for subsequent Contract Quarters.

CUSTOMER shall have no obligation to make any payment to PRODUCER in respect of any Negative Price Adjustment Amount, whether by way of refund of payments made by PRODUCER in respect of Positive Price Adjustment Amounts for prior Contract Quarters, payment for Negative Price Adjustment Amounts which are not followed by Positive Price Adjustment Amounts against which such Negative Price Adjustment Amounts may be credited, or otherwise.

4.7 Extraordinary Inflation: On each anniversary of the date hereof, if the United States Gross Domestic Product Implicit Price Deflator (as reported quarterly by the United States Department of Commerce; the "GDP Deflator") for the most recently reported quarterly period has increased by more than 5% from the same quarterly period in the prior year, the Floor Price for each subsequent Contract Year set forth in Schedule 1 hereof, shall be increased by the percentage amount such increase is greater than 5%. For example, if on the first anniversary date hereof the GDP DCLAN01:128295 5

Deflator for the most recent quarter equals 112, and the GDP Deflator for the same quarter reported in the previous year was 105, each Contract Year in Schedule 1 hereof shall be increased by 1.66%.

5. PAYMENT AND DISPUTES.

5.1 Statements and Payments. PRODUCER shall prepare a statement ("Statement") for each Contract Quarter showing the Price Adjustment Payment due to CUSTOMER, if any, for such Contract Quarter and the calculation of the Price Adjustment Amount for such Contract Quarter (whether positive or negative).

PRODUCER will provide to CUSTOMER such Statement on or before the tenth (10th) Business Day after the final Contract Month of each Contract Quarter. PRODUCER shall pay the amount due, if any, by wire transfer of immediately available funds to an account specified by CUSTOMER not later than the fifth (5 th) Business Day after the date on which PRODUCER provides the Statement.

5.2 Overdue Payments. Overdue payments shall accrue interest at the Interest Rate from, and including the due date to, but excluding, the date of payment.

5.3 Billing Disputes. If CUSTOMER, in good faith, disputes any Statement or part thereof, CUSTOMER shall notify PRODUCER in writing of the basis for the dispute within ten (10) business days of receipt of the Statement. If it is subsequently determined by arbitration or agreed that an adjustment to the Statement is appropriate, PRODUCER will prepare and issue a revised Statement not later than ten (10) Business Days after it is determined that an adjustment is appropriate. Any Price Adjustment Payment due to CUSTOMER pursuant to the revised Statement shall be paid by wire transfer of immediately available funds to the account specified by CUSTOMER not later than three (3) Business Days from the date the revised Statement is issued and shall include interest accrued at the Interest Rate until the date paid.

5.4 Dispute Resolution.

5.4.1 All claims, disputes, and other matters concerning the interpretation and enforcement of this Agreement, shall be submitted to binding arbitration in New York, NY and shall be heard by three neutral arbitrators under the Commercial Arbitration Rules of the American Arbitration Association.

DCLAN01:128295 6

5.4.2 Only the Parties hereto and their designated representatives shall be permitted to participate in any arbitration initiated pursuant to this Agreement. The arbitration process shall be concluded not later than six (6) months after the date that it is initiated. The award of the arbitrators shall be accompanied by a reasoned opinion if requested by either Party. The award rendered in such a proceeding shall be final. The Parties shall keep the award, and any opinion issued by the arbitrators, confidential unless the Parties agree otherwise. Any award of amounts due shall include interest accrued at the Interest Rate until the date paid.

-Judgment may-be entered upon the arbitration opinion and award in any court having jurisdiction.

5.4.3 The procedures for the resolution of disputes set forth herein shall be the sole and exclusive procedures for the resolution of disputes. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of a dispute. All negotiations pursuant to these procedures for the resolution of disputes will be confidential, and shall be treated as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and State Rules of Evidence and similarly applicable rules or regulations of any state or federal regulatory agency with jurisdiction over a Party.

6. CONTRACT ADMINISTRATION AND OPERATION.

6.1 Company Representative. PRODUCER and CUSTOMER shall each appoint a representative (collectively, the "Company Representatives"), who will be duly authorized to act on behalf of the Party that appoints him/her, and with whom the other Party may consult at all reasonable times, and whose instructions, requests, and decisions shall be binding on the appointing Party as to all matters pertaining to the administration of this Agreement.

6.2 Record Retention and Access. PRODUCER and CUSTOMER shall each keep complete and accurate records and all other data required by either of them for the purpose of proper administration of this Agreement, including such records as may be required by state or federal regulatory authorities. All such records shall be maintained for a minimum of five (5) years after the creation of the record or data and for any additional length of time required by state or federal regulatory agencies with jurisdiction over PRODUCER or CUSTOMER. PRODUCER and CUSTOMER, on a DCLAN01:128295 7

confidential basis, will provide reasonable access to records kept pursuant to this Section of this Agreement. The Party seeking access to such records shall pay 100% of any out-of-pocket costs the other Party incurs to provide such access.

6.3 Notices. All notices pertaining to this Agreement not explicitly permitted to be in a form other than writing shall be in writing and shall be given by same day or overnight delivery, electronic transmission, certified mail, or first class mail. Any notice shall be given to the other Party as follows:

If-to- PRODUCER:

Constellation Nuclear, LLC 39 West Lexington Street 18 th Floor Baltimore, MD 21201 Attn: Robert E. Denton Title: President Phone: (410) 234-6149 Facsimile: (410) 234-5323 If to CUSTOMER:

Niagara Mohawk Power Corporation 300 Erie Boulevard West Attn: Clement E. Nadeau Title: Vice President Phone: (315) 428-6492 Facsimile: (315) 428-5722 If given by electronic transmission (including telex, facsimile or telecopy), notice shall be deemed given on the date received and shall be confirmed by a written copy sent by first class mail. If sent in writing by certified mail, notice shall be deemed given on the second business day following deposit in the United States mails, properly addressed, with postage prepaid. If sent by same-day or overnight delivery service, notice shall be deemed given on the day of delivery. PRODUCER and CUSTOMER may, by written notice to the other, change its representative(s) including its Company representative and the address to which notices are to be sent.

DCLAN01:128295 8

7. CONFIDENTIALITY. Except as otherwise required by law, the Parties shall keep confidential the terms and conditions of this Agreement and the transactions undertaken pursuant hereto. If a Party is required to file this Agreement with any regulatory body or court, it shall seek trade secret or similar protection from such authority and promptly notify the other Party.
8. GOVERNMENT REGULATION. This Agreement and all rights and obligations the Parties hereunder are subject to all applicable federal, state and local of laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Agreement.

Further, if at any time following receipt of any regulatory approvals required for the initial effectiveness of the NMP-2-Sale, the New York Public Service Commission, any legislature, any agency, or any court takes any action relating to or affecting this Agreement, the payments required to be made hereunder, or CUSTOMER's reflection in rates thereof, neither CUSTOMER or PRODUCER shall have any right to seek damages from the other, to discontinue performance under this Agreement, or to modify or seek to modify any of the terms and conditions in any way as a consequence of such action.

9. GOVERNING LAW/CONTRACT CONSTRUCTION. This Agreement

.shall be interpreted, construed, and governed by the law of the State of New York. For purposes of contract construction, or otherwise, this Agreement is the product of negotiation and neither Party to it shall be deemed to be the drafter of this Agreement or any part hereof. The Section and Subsection headings of this Agreement are for convenience only and shall not be construed as defining or limiting in any way the scope or intent of the provisions hereof.

10. WAIVER AND AMENDMENT. Any waiver by either Party of any of the provisions of this Agreement must be made in writing, and shall apply only to the instance referred to in the writing, and shall not, on any other occasion, be construed as a bar to, or a waiver of, any right either Party has under this Agreement. The Parties may not modify, amend, or supplement this Agreement except by a writing signed by the Parties.
11. BINDING EFFECT; NO THIRD-PARTY RIGHTS OR BENEFITS. This Agreement is entered into solely for the benefit of PRODUCER and CUSTOMER, and their respective successors and permitted assigns, and therefore is not intended and shall not be construed to confer any rights or benefits on any third-party.
12. ENTIRE AGREEMENT. This Agreement contains the complete and exclusive agreement and understanding between the Parties as to its subject matter.
13. ASSIGNMENT. CUSTOMER shall have right to assign the Agreement in whole or in part without consent of PRODUCER. Partial assignments are subject to a 50-MW minimum. PRODUCER shall not have the right to assign this Agreement DCLAN01:128295 9

DEC-12-00 TUE 22:41 AM ECONO LODGE FAX NO. 3153431222 P. 09/13 C,:-i -Oa 06:390m Fr-D-ILLVAN 6 CIW.LL 7-484 P.005/007 F-408 withoUt CUSTOMER'S pn" w,. ..... ..... vide mt PRODUCER or ,is permitted assignee. without CUSTOMER's coPsent. may essign. trarwfer. piedge or otherwiSe dispose of (aDso~utety or as security) its rights and Interests hereunder to an Afliate (an "Assignee Entity") of PRODUCER at least 68% of the equity socurites of which are owned by PRODUCER* r vo...de4, , (I) any rTinority owner of the Assignee Entity shall be that entity contemplaetd to become an equ/ty owner of PRODUCERs affiliated merchant energy group as set formt in that certain press release issued by Constellation Energy Group on October 23. 2000. (ii) no minority owner of the Assignee or oper-bonal rights or role with respect to Entity may have any oontrol or management shall relieve or dIscdarge the Assignee Entity , and (ili no such assignmntt or shall be made if It would PRODUCER from any of its obligations hereunder impde. interfere with er delay the reasonably be expected to prevent or materially Increas the costs of the transactions contemplated by this Agreement or materially transactions contemplated by this Agreement.

certify

14. SIGNATORS' AUTHORTTYICOUNTERPARTS- The undersigned of their respecive Parttes.

that they are authorized to execLte tis Agreement on behalf elch of which shall be This Agreement may be executed in two or more counterparts.

ini making proof of the cornents of this Agreement an origiraL, It snal'itiL vv ,,.,

to produce or account for more than one such counterpart.

or

15. NO DEDICATION OF FACLITIlES. No underaking by PRODUCER

-- - 6-reement shell be deemed

- -..'

to constitute ije

,CUSTOMER '::^ -

dedication of any portion of NMP-2 to trie public, to CUSTOMER. or to any other eralty.

the Parties have IN wrr4NES WHEREOF, and intending to be legally bound, authoriZed representatives- as of the executed this Agreement by the und;ersigned duly date flrsV stated above.

CUSTOMER Name:

Name:

Title-Ti*tle:-

DCLANOI:128295 10 Th 6r,,f

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I1:00 003'ZcI/Z.

O£2926ZZOZTB *-SI1!70d ID3108 61:00 ooBe-/Z-.:-

P.2P.05/38 DEC-11-00 MON 21:40 MCC 1 , 'PO  % i'j.W:* 9 .r t& HINGTO.

DMW that PRODUCER Or Its otherwise prmitte without CUSTOMERSt prior wrfttn conmrnt, may assign, tran.er, pledge of assignee, without CUSTOMER's. conser.t rights and tinterests hereunder to an Affiliate (an dispose of (absolutely or as security) Itsleast "Assignee Entit'*) of PRODUCER at 68% of the equity securities of which are "owned by PRODUCER; . !Md, however (I) any minority owner of the Assignee Entity shall be that entity conteplate to become anoertaln equIty owner or PRODUCER'S press release issued by afflhlated merchant energy group as set forth In thut owner of the Assignee Constellation Energy Group on October 23, 2000, 01) no minority.ghts or role with reapecd to Entity may have any control or management or operational shall relierve or discGhrge the Assignee Entity , and (111)no such assignment shall be made If it would PRODUCER from any of its obligations hereunder or with or delay the reasonably be expected to prevent or materially impede. interfere the Gost of the transactions contemplated by this Agreement or materially Increase transactions contemplated by this Agreement certify

14. SIGNATORS' AUTHORITYICOUNTERPART,. The undersigned on behalf of their respective Parties.

thaT they are authorized to cxewWut this Agreement each of which shall be This Agreement may be executed in two or more counterparts, of this Aome0 *nt an original. It ahall not be ncoooory in maling proof of the contents to produce or account for more than one such cnunterparL NO DEDICATION OF FACILITIES. No undertaking by to PRODUCER or

15. constitute the be deemed CUSTOMER under any provision of this Agreement shall or to any other entity.

dedication of any portion of NMP-2 to the public, to CUSTOMER, IN Wf*NE*S HEREOF, a-nd-inteding-to be legally bound, the Parties ofhave as the oxoouted this Agreement by the underionArl drily withoriz*d representativeS date first stated above.

PRODUCER CUSTOMER Name_ Name: L4&LIAM F. ED1WA1PS Title: .Title: 9._. pAoMi CFO DCLAN01:128295 10

SCHEDULE 1 Floor Price Contract Year 1 2 3 4 5 6 7 8 9 10 Floor Price 4 0.75 41.57 42.40 43.25 44.11 44.99 4 5.89 46.81 47.75 48.70

($/MWh)

SCHEDULE 2 Monthly Base Price Factor For every year of the Term:

BASE PRICE MONTH FACTOR January 0.9176 February 0.9192 March 0.7729 April 0.7707 May 1.0461 June 1.1687 July 1.3861 August 1.4450 September 1.1275 October 0.7801 November 0.7707 December 0.8954 DCLAN01:128295 11

Exhibit 10A [PROPRIETARY]

FORM OF MASTER DEMAND NOTE Dated:

Effective:

Each of the undersigned (each a "Party", collectively the "Parties") anticipate entering into one or more loans with each other from time to time as either a borrower or a lender. Any such loans between any of the Parties will be governed by this Master Demand Note, and the grid attached hereto and made a part hereof (the "Grid"). At any time that a Party desires to lend money to, or borrow money from, another Party the Chief Financial Officer of Constellation Energy Group, Inc. and his staff is authorized to endorse on the Grid the date of each loan, the principal amount thereof, the interest rate and the identity of the Party that is the borrower and the Party that is the lender. All notations on the Grid shall be binding on the Parties, absent manifest error.

For value received, each Party that is a borrower promises to pay to the order of each Party that is a lender the principal borrowed as evidenced on the Grid in accordance with the terms hereof, together with accrued interest on any and all principal amounts remaining unpaid hereunder from the date of such loan until payment in full, at a rate per annum noted on the Grid until such principal amount shall have become due and payable; and at the rate of 2% over the grid rate on any overdue principal and (to the extent permitted by applicable law) on any overdue interest, from the date on which payment is due until the obligation of the borrower with respect to the payment thereof shall be discharged. Interest hereunder shall be calculated on the basis of a three hundred sixty (360) day year counting the actual number of days elapsed.

The borrower promises to pay the lender the outstanding principal amount of this Note together with all accrued but unpaid interest in one installment within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of lender's demand. All of the principal may be prepaid by borrower at any time, together with all accrued interest thereon to the date of payment, without penalty with five (5) days prior written notice.

All principal and interest hereunder are payable in lawful money of the United States of America at the address of the lender shown beneath its signature.

No delay or omission on the part of the Lender in exercising any rights hereunder shall operate as a waiver of such right or any other right of such lender, nor shall any delay, omission or waiver on any one occasion be deemed a bar to or waiver of the same or any other right on any future occasion.

The borrower for itself and its respective legal representatives, successors and assigns, hereby expressly waives presentment, demand, protest, notice of protest, presentment for the purpose of accelerating maturity and diligence in collection.

This Note and all transactions hereunder and/or evidenced herein shall be governed by, construed, and enforced in accordance with the laws of the State of Maryland (without giving effect to its choice of law rules) and shall have the effect of a sealed instrument.

IN WITNESS WHEREOF, each Party has caused this Note to be executed by its duly authorized officer, under seal, as of the date first above written.

CONSTELLATION ENERGY GROUP, INC.

By:

Name: Thomas E. Ruszin, Jr.

Title: Treasurer Address: 250 West Pratt Street Baltimore, MD 21201 State of Incorporation: Maryland (CONSTELLATION ENERGY GROUP, INC.

SUBSIDIARY NAME)

By:

Name:

Title:

Address:

State of Incorporation:

Exhibit 11A [PROPRIETARY]

FORM OF INTER-COMPANY CREDIT AGREEMENT This Inter-Company Credit Agreement (the "Agreement"), dated [ 1, effective as of[ 1, by and between Constellation Energy Group, Inc. (Parent) and its affiliate, Nine Mile Point Nuclear Station, LLC (NMP LLC).

RECITALS A. Nuclear Regulatory Commission ("NRC") regulations require the licensee of Nine Mile Point nuclear power reactors (collectively, the "Facilities")

to provide financial assurance of its ability to protect public health and safety.

B. NMP LLC participates in a cash pool Parent operates for the benefit of all of its subsidiaries. The cash pool is intended to provide NMP LLC with the cash necessary to meet its day-to-day cash needs, including its obligation to protect public health and safety. However, if the cash pool, at any time, cannot meet those needs, then Parent has agreed to provide credit to NMP LLC to allow it to meet its obligation to protect public health and safety.

The parties, for adequate consideration and intending to be legally bound, hereby agree as follows:

ARTICLE I THE ADVANCES Section 1.01. Advances. During the period from the date of this Agreement to and including the Maturity Date (as defined in Section 1.03), Parent agrees, on the terms and conditions set forth herein, from time-to-time, to extend credit to NMP LLC; provided, however, that the aggregate principal amount of all advances outstanding at any time shall [not exceed $100 million]. During the term of this Agreement, NMP LLC, at its option and without penalty or premium, may from time to time repay all or any part of the principal amount outstanding as provided in Section 1.06, and may reborrow any amount that has been repaid. Each advance of funds under this Agreement shall be in a minimum amount of [$5 million] and, if greater, shall be in an [integral multiple of $1 million].

Section 1.02. Request for an Advance. Each request for an advance of funds under this Agreement shall be made not later than noon on the second business day prior to the proposed drawdown by notice from NMP LLC to Parent (pursuant to procedures that may be changed from time to time by mutual agreement) specifying the amount of the advance and a certification that such advance is for the purpose specified in Section 1.07.

Section 1.03. The Note. At the time of the first advance, NMP LLC will execute a note in substantially the form attached hereto as Exhibit B-2.1 (the "Note") and deliver it to Parent. Any advance provided by Parent to NMP LLC, and any payments of principal and interest by NMP LLC, shall be noted by Parent on the grid attached to the Note.

Such notations shall be conclusive absent manifest error. The Note is payable to the order of Parent at its principal office in Baltimore, Maryland, and matures on the Maturity Date (subject to the terms of Article II hereof). The "Maturity Date" shall mean: (i) the 5th year anniversary date of the date of this Agreement; (ii) such earlier termination date as may occur pursuant to Sections 2.01, or 2.02, or 2.03; (iii) such later date as may be mutually agreed by the parties hereto pursuant to Section 1.09; or (iv) at the date of closing on any transaction in which: (a) the assets (except asset sales in the ordinary course of business) or stock of NMP LLC are sold to an unrelated third party of Parent, or (b) NMP LLC is merged or consolidated into an unrelated third party of Parent whether by operation of law or otherwise. If the Maturity Date is not a business day in Baltimore, Maryland, the next succeeding business day shall be deemed to be the Maturity Date.

Section 1.04. Interest. Interest on any principal amount outstanding shall accrue daily at such rate, and shall be payable at such times, as established by Parent at the time of an advance. The interest rate applicable to any advance and the time of payment shall be noted on the grid attached to the Note by Parent. Such notations shall be conclusive absent manifest error.

Section 1.05. Funding and Repayment. Each advance of funds under this Agreement shall be made in U.S. Dollars in immediately available funds on each drawdown date, at such place as Parent and NMP LLC may agree. All repayments and prepayments by NMP LLC of principal and interest, and of all other sums due under the Note or this Agreement shall be made without deduction, setoff, abatement, suspension, deferment, defense or counterclaim, on or before the due date of repayment or payment, and shall be made in U.S. dollars in immediately available funds at the principal office of Parent.

Section 1.06. Optional Prepayments. NMP LLC, at its option, may prepay all or any part of the principal amount outstanding from time to time without penalty or premium, upon at least 2 business days' prior notice (which, if oral, shall be confirmed promptly in writing) to Parent; provided, however, that if the interest rate is LIBOR based, a prepayment penalty may be assessed against NMP LLC. Any prepayment penalty would be established at the time of an advance. Parent, at its option, may waive such notice requirements as to any prepayment.

Section 1.07. Use of Proceeds. In order to provide financial assurance, any advance may be used by NMP LLC only to meet its expenses and obligations to safely operate and maintain the Facilities, including payments for nuclear property damage insurance and a retrospective premium pursuant to Title 10, Part 140, Section 21 of the Code of Federal Regulations (10 CFR 140.21).

Section 1.08. Commitment Fee. At the time of any advance, Parent will notify NMP LLC of any commitment fee and the method and time of payment. Such commitment fee will only be in an amount necessary to offset Parent's operating expenses regarding the advance.

Section 1.09. Extension of Maturity Date. This Agreement and the Maturity Date hereunder may be extended for successive periods of two years each upon the mutual agreement of the parties.

ARTICLE II TERMINATION Section 2.01. Termination upon Unenforceability. Parent, at its option, shall have the right to cease making advances under this Agreement, to terminate this Agreement and/or to make the outstanding principal amount and interest thereon and any other sums due under the Note and this Agreement immediately due and payable upon written or oral notice to NMP LLC, but without the requirement of any further or other notice, demand or presentment of the Note for payment, if this Agreement or the Note shall at any time for any reason cease to be in full force and effect or shall be null and void while the Note is outstanding, or the validity or enforceability of this Agreement or the Note shall be contested by any person, or NMP LLC shall deny that it has any further liability or obligation under this Agreement or the Note.

Section 2.02. Termination Upon Permanent Cessation of Operations or NRC Approval. Notwithstanding any other provisions in this Agreement or the Note to the contrary, except as provided in Sections 2.01 and 2.03 herein, Parent agrees that it will provide the credit to NMP LLC for the purposes defined in Section 1.07, and in no event shall this Agreement be terminated, nor shall Parent cease to make advances under this Agreement, until the earlier of: (i) such time that NMP LLC has permanently ceased operations at the Facilities; or (ii) the NRC has given written approval for the discontinuance or termination of this Agreement; or (iii) upon the date of closing on any transaction in which (a) the assets (except asset sales in the ordinary course of business) or stock of NMP LLC are sold to an unrelated third party of Parent, or (b) NMP LLC is merged or consolidated into an unrelated third party of Parent whether by operation of law or otherwise.

Section 2.03. Substitution of Financial Assurance. Parent can terminate this Agreement upon 45 days written notice to NMP LLC if Parent has procured a substitute loan facility and/or letter of credit for NMP LLC that meets the financial assurance requirements of the NRC to protect the public health and safety. Such substitute loan facility and/or letter of credit shall remain in effect until the earlier of (i) such time that NMP LLC has permanently ceased operations at the Facilities; (ii) the NRC has given written approval of the discontinuance or termination of the substitute loan facility and/or letter of credit; or (iii) if Parent has procured another substitute loan facility and/or letter of credit for NMP LLC that meets the financial assurance requirements of the NRC to protect the public health and safety.

ARTICLE III MISCELLANEOUS Section 3.01. Notices. Any communications between the parties hereto, and notice provided herein to be given, may be given by mailing or otherwise by delivering the same to the Treasurer of Parent and the Treasurer of NMP LLC, at the principal offices of Parent and NMP LLC, respectively, or to such other officers or addresses as either party may in writing hereafter specify.

Section 3.02. Remedies. No delay or omission to exercise any right, power or remedy accruing to Parent under this Agreement shall impair any such right, power or remedy, nor shall it be construed to be a waiver of any such right, power or remedy. Any waiver, permit, consent or approval of any kind or character on the part of Parent of any breach or default under this Agreement, must be in writing and shall be effective only to the extent specifically set forth in such writing. All remedies, either under this Agreement or by law or otherwise afforded to Parent, shall be cumulative and not alternative.

Section 3.03. Miscellaneous. This Agreement may not be amended unless in writing signed by both parties. This Agreement is governed by Maryland law. This Agreement may not be assigned by either party without the prior written consent of the other party.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement by their duly authorized officers, as of the date first above written.

CONSTELLATION ENERGY GROUP, INC.

By:

Name:

Title:

NINE MILE POINT NUCLEAR STATION, LLC By:

Name:

Title:

ATTACHMENT FORM OF INTER-COMPANY CREDIT NOTE 1$100 million] (Available Credit) ,2001 Baltimore, Maryland NINE MILE POINT NUCLEAR STATION, LLC, a Delaware limited liability company ("NMP LLC"), for value received and in consideration of the execution and delivery by Constellation Energy Group, Inc., a Maryland corporation ("Parent") of that certain Inter-Company Credit Agreement, effective as of [ ] (the "Agreement"),

hereby promises to pay to the order of Parent on the Maturity Date, the principal sum of

[$100 million], or so much thereof as may be outstanding hereunder, together with any accrued but unpaid interest. Prior to maturity, interest shall be due and payable by NMP LLC periodically as noted by Parent at the time of any advance and as set forth on the grid attached hereto and made a part hereof.

This Note is issued by NMP LLC pursuant to the Agreement, to which reference is made for certain terms and conditions applicable hereto. Capitalized terms used in this Note shall, unless the context otherwise requires, have the same meanings assigned to them in the Agreement.

Both the principal of this Note and interest hereon are payable in lawful money of the Untied States of America, which will be immediately available on the day when payment shall become due, at the principal office of Parent. Interest shall be paid on overdue principal hereof and to the extent legally enforceable, on overdue interest, at a rate of 11% over] the then current prime lending rate per annum.

The outstanding principal amount of this Note shall be increased or decreased upon any increase or decrease in the outstanding aggregate principal amount as provided under the terms of Sections 1.02 and 1.06 of the Agreement; provided, however, that at no time shall the outstanding principal amount of this Note exceed the Available Credit. Upon any such increase or decrease in the principal amount of this Note, Parent shall cause to be shown upon the grid portion of this Note the date and amount of such increase or decrease, as the case may be. All notations by Parent on the grid shall be conclusive absent manifest error.

Upon payment in full of the principal of and interest on this Note and all other sums due from NMP LLC to Parent under the terms of this Note and the Agreement at the Maturity Date, this Note shall be canceled and returned to NMP LLC and shall be of no further operation or effect. The obligation of NMP LLC to make the payments required to be made on this Note and under the Agreement and to perform and observe the other agreements on its part contained herein and therein shall be absolute and

unconditional and shall not be subject to diminution by setoff, counterclaim, abatement or otherwise.

Upon the occurrence of an event giving rise to a right on the part of Parent to terminate the Agreement as set forth in sections 2.01, 2.02, and 2.03 of the Agreement, the maturity of this Note may be accelerated and the principal of and interest on and any other sums due from NMP LLC to Parent under the terms of this Note may be declared immediately due and payable as provided for in the Agreement.

This Note is issued with the intent that it shall be governed by, and construed in accordance with, the laws of the State of Maryland.

IN WITNESS WHEREOF, Nine Mile Point NMP LLC Station, LLC has caused this Note to be duly executed in its name, and its corporate seal to be hereunto affixed and attested, by its duly authorized officer as of , 2001.

NINE MILE POINT NUCLEAR STATION, LLC By:

Title:

INCREASES AND DECREASES IN OUTSTANDING PRINCIPAL AMOUNT OF THIS NOTE INTEREST UNPAID DATE AMOUNT OF RATE AND AMOUNT OF PRINCIPAL ADVANCE TIME OF REPAYMENT BALANCE PAYMENT BALANCE Ii I i i +

4 4 1 +

4 4 i +

Exhibit 12 Constellation Energy Group, Inc.'s 1999 Annual Report and 100 Filine for 3 rd Ouarter 2000

0 Constellation Energy Group at a Glance Constellation Energy Group (NYSE:CEG) is a holding company whose subsidiaries include a group of energy businesses focused mostly on power marketing and merchant generation in North America and the Baltimore Gas and Electric Company (BGE). In 1999, combined revenues totaled $3.8 billion.

Here are the Constellation Stars:

Constellation Power Source Our integrated domestic merchant energy company provides wholesale customers with solutions to their energy needs. Combining expertise in marketing and risk management with the development, ownership and operation of power plants, Constellation Power Source actively markets power and risk management services throughout North America.

Constellation Nuclear Group Our nuclear generation and consulting business brings together our experience and expertise in the nuclear industry. Under the Constellation Nuclear umbrella is our newly formed Constellation Nuclear Services, Inc., which provides nuclear consulting services specializing in nuclear power plant license renewal and life-cycle management. In July 2000, upon receipt of all regulatory approvals, the Calvert Cliffs Nuclear Power Plant will be moved under that umbrella as well.

Baltimore Gas and Electric Company Our regulated, electric and gas utility serves more than 1.1 million electric customers and more than 584,000 gas customers in Central Maryland. Up until deregulation of the generation part of the business on July 1, 2000, BGE will provide services to these customers as a fully integrated utility with operations as listed below:

Generation: Owns and operates 10 Maryland-based power stations, including the Calvert Cliffs Nuclear Power Plant; shares ownership of three power plants in Pennsylvania; total generating capacity exceeds 6,200 megawatts.

Electricity Delivery: Provides electricity throughout a 2,300-square-mile service territory through its transmission and distribution system and is a member of the PJM (Pennsylvania-New Jersey-Maryland)

Interconnection, a regional power pool of wholesale market participants and other utility companies.

Natural Gas Delivery: Delivers natural gas through nearly 5,600 miles of gas main in a 600-square mile service territory.

On July 1, 2000, BGE's generating assets will be transferred to our nonregulated subsidiaries, pending full regulatory approval. BGE will then continue to operate as our electric and natural gas delivery business, serving its Central Maryland customers.

BGE Home Products & Services Our local home products, commercial buildings, and gas retail marketing business offers a wide range of home energy products and services and commercial building systems in Maryland, Virginia, and Washington, D.C. After July 2000, BGE HOME will begin marketing electricity, as well as gas, to residential and small M commercial customers in Maryland.

Constellation Energy Source Our energy products and services business provides customized energy solutions exclusively to commercial and industrial customers, primarily in the mid-Atlantic region.

Committed to Equal Opportunity. As an Equal Opportunity Employer, Constellation Energy Group does not discriminate on the basis of age, color, disability, marital status, national origin, race, religion, sex, sexual orientation, or veteran status. I

4.,

CM) 1999 1998 %Change (In millions, except per share amo*unts) {

Common Stock Data Earnings per share Earnings per share before nonrecurring C charges included in operations Utility business $ 2.03 $ 1.93 5.2%

Diversified businesses .45 .27 66.7 Total earnings per share before nonrecurring charges included in operations 2.48 2.20 12.7 Nonrecurring charges included in operations

  • Hurricane Floyd (.03)
  • Write-downs of power projects (.12)
  • Write-down of financial investment (.11)
  • Write-downs of real estate and senior-living investments (.04) (.10)
  • Write-off of energy services investment - (.04)

Total earnings per share before extraordinary item 2.18 2.06 5.8 Extraordinary loss (.44)

Total earnings per share $ 1.74 $ 2.06 (15.5)

Dividends declared per share $ 1.68 $ 1.67 0.6 Average shares outstanding 149.6 148.5 0.7 Return on average common equity Reported 8.6% 10.5% (18.1)

Excluding nonrecurring charges to earnings 12.3% 11.2% 9.8 Book value per share-year-end $ 20.01 $ 19.98 0.2 Market price per share-year-end $29.000 $30.875 (6.1)

Financial Data Revenues Electric $ 2,259 $ 2,219 1.8 Gas 476 449 6.0 Diversified businesses 1,051 690 52.3 Total revenues $ 3,786 $ 3,358 12.7 Income before extraordinary item $ 326 $ 306 6.5 Extraordinary loss, net of income taxes (66)

Net income $ 260 $ 306 (15.0)

Total assets $ 9,684 $ 9,275 4.4 Utility construction expenditures (excluding AFC) $ 376 $ 329 14.3 Investment in utility business $ 2,349 $ 2,467 (4.8)

Investment in diversified businesses $ 643 $ 515 24.9 Utility System Data Electric system sales-megawatt-hours 29.3 28.8 1.7 Gas system sales-dekatherms 105.2 100.1 5.1

  • Nonrecurringchargesto earningsdiscussed in Note 2 to the Conso'lidatedFinancialStatements on pa ge 55.

Certainprior-yearamounts have been reclassifiedto conforn Ij LtYVV C )C'u

. r J C- 1 .

Table of Contents 2 Letter to Our Shareholders 7 Strategy: Merchant Energy 12 Strategy: UtiLity Services 16 Powerful Partnerships 17 Financial Review 39 Forward Looking Statements 74 Directors and Officers 76 Five-Year Statistical Summary 77 Shareholder Information

I 0 In creatingthe ConstellationEnergy Group holding company/&,

Now we areputting in place the majorpieces of the competitive 0J

.4

-J A New Company Is Born The action began in February 1999, when the Maryland General Assembly passed legislation allowing BGE to form

Dear Investor,

a holding company. Following your approval at the annual Nineteen ninety-nine was arguably the most pivotal year in our shareholders' meeting, the Constellation Energy Group started company's history. The events of last year have forever changed trading on the New York Stock Exchange on May 3.

the energy landscape in Maryland and have set in motion a fundamental transformation of our corporation. Throughout the legislative session, we worked closely with key stakeholders and state lawmakers to develop the legal In our 1998 annual report, I said we were determined to win framework that would shape Maryland's electric market. In in the new energy market and outlined the primary strategies April, Governor Parris Glendening signed comprehensive we would pursue to ensure success. They included:

legislation that is the foundation for opening Maryland's Be a leader in wholesale power marketing electric generation business to competition.

and generation in North America.

With legislation in place, we moved quickly to negotiate an Providepremier utility services to Maryland while equitable settlement agreement with all but one of the key managing the transitionto competitive energy markets. parties to BGE's electric deregulation transition plan. On November 10, 1999, the Maryland Public Service Commission In this report, you will read about the overall progress we (PSC) approved that settlement, allowing all BGE electric have made in executing those strategies. The results of our customers to choose their electric suppliers beginning July 1, efforts point to the fact that your company is both determined 2000. (Forhighlights of the settlement order,see page 6.)

and winning in the competitive energy marketplace.

This historic decision resolves many critical details needed to Despite our progress, we are not satisfied with the recent ensure a smooth transition from a regulated to a competitive performance of our stock. The investment return on Constellation electric market. Most important, it enables Constellation Energy Group's stock, and the utility industry in general, has Energy Group to move forward on sound financial footing, lagged behind the overall market. Still, we were one of the while providing BGE's customers with important safeguards.

stronger performers among utilities in 1999, with total share holder return outpacing the Standard & Poor's Electric Utility Significantly for BGE residential customers, the settlement Index by more than 19%. In early February 2000, our market secures a 6.5% reduction in electric base rates for six years price reached a 52-week high. and financial protections for low-income customers. For Constellation Energy Group, it allows us to recover a significant The relative strength of our stock provides tangible evidence portion of our transition costs, as well as move our utility that investors are starting to reward some companies, like generation assets to our nonregulated subsidiaries. While the Constellation Energy Group, that are taking a focused approach settlement decision has been appealed in court, we believe that to grow in a deregulated environment. We are working hard electric deregulation in the state and our company's plans can on all fronts to ensure we continue to build shareholder value move forward.

as we navigate through deregulation. Here's a look at the progress made last year and how we plan to continue delivering value in 2000 and beyond.

Par,we launcheda new growth-orientedenergycompany.

business strategieswe believe will make us winners.

I W rowng Pains i.nancial Results of Change Reflect The move to a deregulated electric generation supply market Despite this initial earnings reduction, we feel the settlement comes with some growing pains. A part of our settlement order is a good agreement that positions the company to required that we recognize certain expenses related to the successfully pursue opportunities in a competitive deregulation of our utility generating assets before July 1, 2000. energy market.

Consequently, after accounting for one-time charges and the Utility earnings from operations, excluding the nonrecurring extraordinary loss related to deregulation, our reported earnings charges, increased about 5% in 1999 versus 1998. Diversified were $1.74 a share compared with $2.06 in 1998. Excluding these earnings from operations grew 67% over 1998, thanks to charges, our earnings per share in 1999 were $2.48 per share, a substantial contributions from Constellation Power Source, 12.7% increase over operating eamings of $2,20 in 1998. our power marketing business.

Earnings and Dividends Dectared Return on Average Common Stock Market Price Pe Shore of Common Stock Common Equity and Book Value Per Share

~ip~--- -------

H2%

1995 1996 1997 1998 1999 s 1995 19W6per1997 Earnings 1998 1999 Share-Reported I Market Price per Share J Earrirgsper Share-Before A Book Value per Share Nonrecurring Charges 11ividends per Share j

Operations Produce Results Our Constellation Power Source subsidiary emerged from 1999 as a leader in the power marketing business. With earnings four times higher than 1998. it continued to profitably expand operations throughout North America.

In less than three years, Constellation Power Source has become Advancing Our one of a handful of customer-focused merchant energy companies With deregulation legislation in place and our PSC able to deliver effective energy solutions in a competitive settlement approved, we took major steps toward wholesale marketplace. In fact, PHB Hagler Bailly, a leading management and economic consulting company in the energy advancing our competitive business strategy. As industry, named Constellation Power Source the top U.S. power deregulation unfolds and we move forward, we will marketer in its Energy Industiy Outlook 2000. experience vast changes in the way we do business.

In 1998, we were a founding investor, along with a Goldman, In the past, the majority of our earnings have come from Sachs & Co. affiliate, of Orion Power Holdings, Inc. Since BGE. That equation is changing. Under deregulation, the delivery of electricity and gas will remain regulated, then, Orion has steadily increased its generation portfolio.

When the acquisition of Duquesne Light Company's generation while both electric generation and gas supply will assets announced last year is completed, Orion's portfolio will be competitive.

total more than 5,200 megawatts of power.

Once again, BGE's power plants had an excellent year, with fossil plants generating an all-time record 19.4 million We'll Be Ready for Customer Choice megawatt-hours. This marks the tenth consecutive year they've Operationally, our first priority for the year 2000 is set a record for total output. Calvert Cliffs Nuclear Power Plant to have all systems ready to meet the July 1 deadline generated 13.3 million megawatts, nearly matching its all-time for opening the electric market in Maryland. The production level set in 1998. transition will require major internal changes from an organizational standpoint.

We are expecting a decision from the Nuclear Regulatory Commission sometime this year on our application to extend To accomplish this, we're reorganizing our the operating licenses for the Calvert Cliffs Nuclear Power operations into three main business units Plant. Commission approval will allow these two units to the regulated BGE utility, our Constellation Power operate for up to 20 years beyond the current licenses, Source merchant energy company, and our nuclear extending operation dates to 2034 and 2036. subsidiary. Our goal is to have these businesses operating smoothly to effect a seamless transition BGE's distribution and customer service employees faced to customer choice.

one of their most challenging years ever. The devastating On July 1, 2000, pending full regulatory approval, ice storm in January was followed by Hurricane Floyd in BGE's generating assets will be transferred to September, which caused the worst damage to our system in our nonregulated subsidiaries. Our fossil energy our history. Our employees responded heroically during the plants will become part of Constellation Power restoration efforts of both storms, and we learned a lot from Source, while the Calvert Cliffs Nuclear Plant will our efforts. Following an intense critique of that experience, move under Constellation Nuclear Group. BGE we are implementing ways to improve service restoration and will, as a result, become a "pipes and wires" utility, communications with customers during major outages. continuing its historic role of delivering natural gas and electricity through its networks to homes and businesses throughout Central Maryland.

I

Strategyin 2000 and Beyond In the future, Constellation Energy expects to derive almost two-thirds of its earnings from competitive markets that are not limited by franchise boundaries.

The focus of our strategy, therefore, has shifted to the growing national wholesale energy market, while also emphasizing the delivery of energy to our Central Maryland retail customers. The steps we're taking to accomplish this include preparing for customer choice and building a merchant energy company that serves the national wholesale market.

Investing Today to Gain Advantage To promote growth inour domestic merchant energy business, we're committed to significant We're Building a new capital investment over the next several years.

Merchant Energy Organization We have placed orders for 5,100 megawatts of Our growth strategy centers on the domestic wholesale turbines including 800 megawatts of peaking units energy market. This year, Constellation Power Source will generating plants that are used during high periods take the next steps in building a full-scale merchant energy of demand--to come on-line in2001. We now have business by bringing together our power marketing, plant 17 power project sites under active development.

development, and plant operations. And it will align our With our concentration on domestic projects, we 6,200 megawatts of existing utility generating assets in the will make a controlled exit from our Latin American mid-Atlantic region with our national power marketing and investments when market conditions warrant.

risk management capabilities.

Our approach to this business is different from that of Remaining a Regional Leader our competitors'. Some power marketers are pure We've been serving the energy needs of Central traders or speculators-they bet on whether it will be Maryland for nearly two centuries and have always hot next July in a particular area of the country. Like had a strong corporate presence inthe community.

any gamble, it can pay off for those who bet right. As Constellation Energy Group, we intend to remain But that is not the type of business we're building. a major local employer, continuing to serve our local customers while developing a Baltimore Using its marketing expertise, Constellation Power based business that serves wholesale customers Source identifies customer opportunities across the throughout the United States.

United States and determines how best to capitalize on them. We then use a portfolio approach to decide As we make this transition, BGE, our regulated the right mix of power plants to develop, own, and utility, will continue to deliver energy reliably and operate and how much generation to control under affordably to our local customers. At the same contract. This business model has worked well. It time, our other nonregulated affiliates will helps us maintain a balance between supply and continue to provide a variety of competitive demand in each region and optimizes our capital energy products and services to retail and investments in power plants. business customers throughout the region.

Thanks to Ed Crooke We're Determined and Winning!

During the last several years, we've learned a lot about our We said last year that we were "determined to win" in the \ _

competitive strengths and how we can use them to create new competitive energy market. That hasn't changed. During 1999, business opportunities. Through the process, we've developed our employees proved their determination every day as we a focus that will keep us positioned to take advantage of continued our aggressive evolution into the type of company that opportunities that leverage those strengths and avoid those can thrive and prosper in the deregulated merchant energy market.

markets or business sectors that don't. I want to express my sincere personal thanks to Ed Crooke for his tireless efforts I want to thank all of our employees who delivered day in and day out to help us get to this point. We still have a lot of work in helping us get to this point.

ahead. But by the end of 2000 we will have transformed Ed energized our strategic planning efforts, sharpening Constellation Energy Group into an entirely new energy our focus and building on our strengths. Ed retired as Vice company, streamlined in structure and focused on sustained Chairman at the end of 1999 after 31 years of service. His growth in total shareholder return.

counsel and guidance have helped to create a blueprint that will guide Constellation Energy Group and its employees as we become a major player in the domestic energy business.

I Christian H. Poindexter Chairmanof the Board,President and Chief Executive Officer February20,2000

/" \

Highlights of Maryland PSC's Settlement Order on BGE's Transition Plan Constellation Energy Group moved a step closer to implementing its competitive business strategy when the Maryland Public Service Commission approved BGE's Settlement Transition Plan on November 10, 1999.

The approval of the plan also supported two objectives of electric deregulation in Maryland: to develop a competitive retail electric market and to achieve a fair transition to competitive markets for all stakeholders.

Following are the major provisions of the PSC's Settlement Transition Order:

,u Beginning with the first meter reading on or after July 1, AD Starting on July 1, generation supply will be deregulated.

2000, most customers can choose their electric supplier. BGE, upon receiving all regulatory approvals, will BGE will continue to deliver the energy to all customers transfer its generation assets to Constellation Energy in areas it traditionally serves. Group's nonregulated affiliate companies.

0 Also on July 1, BGE will reduce annual residential will itemize rates and show separate components electric rates by about 6.5 percent, about $54 million, on its bill for delivery service, transition charges, and then freeze those rates for six years. For residential standard offer service, transmission, universal service, customers who do not choose another electricity and taxes.

supplier, BGE will provide their electricity supply at fixed 3= BGE will be the default supplier, providing service for rates for up to six years under its Standard Offer Service.

customers whose contracted electricity is not delivered M Electric distribution rates will be frozen for a four-year or who choose to return to BGE for supply.

period for industrial and commercial customers. Also,

  • M BGE will reduce its generation assets by $150 million industrial customers will be able to choose from four between July 1, 1999 and June 30, 2000.

payment options that will fix the electric energy rates and transition charges for a period of time. 7* Universal service will be provided for low-income customers without increasing their bills.

SAlready incorporated into these rates is a competitive transition charge, which will allow the company to recover $528 million (after tax) of investments that had been made to meet regulatory obligations.

i

LIAM eqImt-PI I UM

"The wholesale power market is a $200 billion market that's only going to grow larger.We're putting the pieces in place to be able to profit from that growth."

Charles W. Shivery President,Constellation Power Source G etting results in a new market requires new solutions, new directions, and new beginnings.

Building a Merchant Energy Company If results are beginnings, then the story of Constellation Energy's future starts with Constellation Power Source.

The Constellation Energy Group's move to the new In just over two years, Constellation Power Source has moved energy market took a big step in 1997 when we from a start-up energy marketing company to being named created our ConstellationPower Source subsidiary 1999's "Best Power Marketer" by PHB Hagler Bailly, an international energy consulting company.

From the outset, ConstellationPowerSource was In 2000, Constellation Power Source will go even further, built to buy, sell, and trade energy in the wholesale bringing together existing pieces from the Constellation power market. But that was only a start. Energy Group to form one of the nation's premier merchant energy companies. Constellation Power Source will no longer As we move into the competitive market, be simply an energy marketing company, but a merchant ConstellationPower Source is using the results energy company. We are combining the existing power marketing and trading functions under Constellation Power and experience it's gained to build a merchant Source with plant operations, development, and generation energy company that will be our power source functions under our Constellation Power and BGE subsidiaries.

for the future. Together these functions will form an integrated merchant energy company that will strategically develop, own, and operate power plants; market and trade power; and manage risk in the wholesale energy market.

I

I Getting There With Results Constellation Power Source

,*.*bo pursue a merchant energy strategy, we needed results to Quarterly Sales (Millions of MWh) prove we were going in the right direction, and Constellation Power Source delivered them. 25-20 In 1999, it more than quadrupled its contribution to our earnings from the previous year to $0.23 per share, increased its asset base by $235 million, and increased its market share 10 in high-energy growth areas such as Texas and the Midwest.

Constellation Power Source has also captured a significant 10 share of the standard offer electric supply service in New England. In the past year we doubled the size of our state-of 1Q 2Q 3Q 4Q 1Q 2Q 30 4Q 1Q 2Q 3Q 4Q 97 97 97 97 98 98 98 98 99 99 99 99 the-art power trading floor to pursue more opportunities in the wholesale energy market.

To achieve results, Constellation Power Source is building its business from its customer's perspective. Its success has been based on understanding precisely what a customer's energy needs are, then providing the best solution.

Ultimately that solution requires Constellation Power Source to provide electricity. To do that, it chooses from a number of options including purchasing power from regional power pools, developing bilateral agreements with third parties to provide energy, producing power in plants we own, or contracting for power directly from other suppliers.

The Power Behind Our Future--Generation As deregulation takes hold in states across the country, the wholesale energy market will expand rapidly. So, too, will opportunities to structure energy deals to meet the power requirements of wholesale customers such as municipalities, cooperatives, power plant owners, and other utilities.

-To ensure that we have affordable and reliable energy to meet customers' needs, we're moving our fossil fuel power plants under the Constellation SPower Source umbrella.

One of the many reasons we chose to pursue opportunities in the wholesale energy market is the operating strength of our fossil plants. Meeting the complex energy needs of large wholesale customers means, in many cases, ensuring we have cost-efficient and reliable power that's available when we need it. Over the past several years as they've prepared for the competitive market, our fossil fuel plants and employees have posted impressive productivity gains and I

proven they're ready to meet the challenge.

by our Constellation Power, Inc., subsidiary. Constellation Power, which has been operating in nonregulated power For the tenth consecutive year, our fossil fuel plants in 1999 markets since 1985, brings a wealth of competitive experience set a new generation record producing 19.4 million megawatt as well as direct ownership positions in 28 energy projects hours. Our employees did it safely, achieving one of the best located throughout the United States.

safety records in our region.

Together with Goldman Sachs, Tokyo Electric Power Company, In addition to incorporating BGE's existing fossil plants to Inc., and Mitsubishi Corporation, we continue our investment support power marketing and trading activities, Constellation interest in Orion Power Holdings, Inc., which buys existing Power Source is also looking to add generating assets in power plants. With acquisitions announced last year, Orion's strategic locations. Last year, Constellation Power Source portfolio will have more than 5,200 megawatts of generating committed capital to fund an additional 5,100 megawatts capacity throughout the Northeast and Upper Midwest regions of generating capacity in strategic growth areas. of the United States.

Constellation Power Source has already brought under its umbrella the domestic independent power plants developed Constellation Nuclear Group Powerful Experience in a New Market For more than 20 years, our Calvert Cliffs Nuclear Power Plant has provided a supply of cost-efficient energy for our customers. But that's only a beginning. Because it's a cost-efficient and clean energy source, nuclear power will continue to play a role in the deregulated power market.

  • (

Generating Results at Our Power Plants Our generating plants produced more than electricity After registering the lowest accident rate in the region in 1999-they produced competitive results. in 1998, our fossil fuel plants continued to improve on The power behind our merchant energy strategy safety, finishing the year with an OSHA rate of 1.32 comes, in part, from BGE's generating plants. accidents per 100 employees for the year-the best On July 1, 2000, BGE's fossil fuel power plants safety numbers in their history.

and the Calvert Cliffs Nuclear Power Plant are expected to become part of our nonregulated subsidiaries. From -For the first time ever our Calvert Cliffs Nuclear Power that time on, the power they produce will be managed Plant received the highest rating given by the Institute by our Constellation Power Source merchant energy of Nuclear Power Operations, which highlighted safety company for the wholesale power market. and teamwork as plant strengths.

On the way to that new market, our employees have -Calvert Cliffs' license renewal efforts took several major worked to ensure our plants continue to improve so they're steps forward, as the Nuclear Regulatory Commission ready to generate safe, efficient, and competitively priced concluded there are neither safety nor environmental power. Generation highlights from 1999 included: issues standing in the way of extending the plant's operating licenses an additional 20 years. The new Our fossil and nuclear plants combined set an all-time operating licenses are expected to be issued this year.

generation record for the second consecutive year, producing 32.7 million megawatt-hours-about a 1%

increase over last year's record production.

I "Nuclearpower has an importantrole to play as we carry out our overall merchant energy strategy.It is clean, reliable, cost effective, and adds to the diversity of our fuel mix-all competitive advantages in the new energy market."

Robert E. Denton President, Constellation NuclearGroup When electric deregulation takes effect in Maryland, the So far, Constellation Nuclear Services has signed 13 contracts Calvert Cliffs Nuclear Power Plant will be moved under the with six utilities and two energy industry groups for license unregulated umbrella of our new afiliate, the Constellation renewal and life-cycle related work.

Nuclear Group, LLC. Power produced by Calvert Cliffs will be managed by our Constellation Power Source subsidiary. Building A Bright Future In preparing itself for this new market, Calvert Cliffs also has With our experience and accomplishments in both generation produced impressive results. In 1999, the plant generated a and wholesale power marketing and trading, we're building near-record 13.3 million megawatt-hours. And, for the first on a solid foundation for success in the competitive market.

time ever, it received the highest rating given by the Institute Moving forward, we will be able to meet customers' complex of Nuclear Power Operations, which highlighted safety and energy needs through structured transactions, manage their teamwork as plant strengths. energy risks, and develop, own, and operate power plants that In addition to nuclear generating capacity, Constellation support our overall business.

Nuclear Group also includes our Constellation Nuclear That means we're not just building a premier merchant energy Services subsidiary. Formed in 1999, it provides nuclear company, we're building a bright future for our customers, consulting services specializing in nuclear power plant shareholders, and us.

license renewal and life-cycle management.

Calvert Cliffs was the first nuclear plant in the United States to apply to the Nuclear Regulatory Commission for renewal of

,.,-/its operating licenses. From this effort, we've gained critical I

experience other power companies can use.

0 I

"BGE is truly a public service company, delivering the electricity and naturalgas that are the lifeblood of Central Maryland'seconomy. Before, during, and after deregulation,our employees will continue to deliver the vital energy services our 1.1 million electric customers and 584,000 gas customers depend on."

Frank 0. Heintz President-Elect BGE Next Step in a 184-Year Evolution As of November 1, 1999, all BGE natural gas customers could

  • 4 both 1999 and Maryland o doubt, was BGE. Most important, a landmark year for choose their gas supplier. On July 1, 2000, the same will the fundamental rules for deregulatingMaryland's happen for all BGE electric customers. While customers energy industry were set. Last year's results are may choose another energy supplier, BGE will continue to deliver natural gas and electricity through its pipes and wires dramaticallychanging the role of the local gas to their homes and businesses in Central Maryland.

and electric utility. The changes ahead mark both While deregulation will change the role the utility has played an end and a beginning for BGE. over the past century, it won't change BGE's core mission delivering safe, economical, reliable, and profitable energy What ends is BGE's 90-year monopoly on to its customers-something it's been doing for 184 years.

both supplying and delivering energy to its Central Maryland customers. What begins is a Navigating the Challenges company completely dedicatedto the delivery of There is no question that given the challenges that deregulation energy. In adapting to the new role in Maryland's presents, BGE has its work cut out for it in the years ahead.

Within the context of a 6.5% residential electric delivery rate energy market, BGE is taking anotherstep in reduction, six-year rate freeze, and meeting its standard offer

(ýýs 184-year evolution. service obligations (see Settlement Order Highlights,page 6),

I BGE must achieve corporate profitability targets while maintaining and improving customer satisfaction, system safety, and reliability.

Yet, it enters its new era well prepared for successful operations. As active participants in the numerous Maryland Public It has spent years getting ready for operating in a deregulated Service Commission roundtables and technical groups, environment. Now that many of the rules have been set, our our employees have been working through the regulatory BGE team is more focused than ever. details to draw a blueprint for how customer choice will work.

At the same time, they have been designing and building the infrastructure necessary to support our new responsibilities Preparing for Customer Choice under customer choice.

Since 1997, our BGE employees have been working toward In the new era, our employees will be responsible for enrolling a deadline that was set just last year-July 1, 2000. That's when Marylanders can choose their electric supplier and customers who have chosen other suppliers. They will also have to support competitive billing and unbundling of the current electric BGE's primary role will be to deliver that supply over its wires. Ensuring our systems are ready and customers are bill as well as settle load and capacity obligations between educated about their energy choices remain our top priorities BGE, other suppliers, and the Pennsylvania-New Jersey Maryland Interconnection-the power grid we operate in.

and biggest challenges.

How Deregulation is Changing the Electric Utility Industry Maryland has now joined the growing number of states that are deregulating their electric generation industry and opening it to competition. That means, beginning in July 2000, BGE customers will, for the first time, be able to choose the company that supplies their electricity. BGE will remain the local distribution company, delivering that power reliably and safely to homes and businesses in Central Maryland.

Electric Customer Choice-The Basics There are two major activities in the electric utility industry: the generation of power supply and the delivery of that supply to customers.

Power Generation: Open to Competition Power Delivery: Still Regulated and Handled by BGE I

BGE Distribution Your Business Supplier A Power Plant II Your Home Supplier B Power Plant BGE 'll Power Plant Power Delivery and Restoration: Once electricity Power Supply: This is the portion of the electric reaches BGE's distribution system, it's delivered to business that will be open to competition. Electricity homes or businesses over our power lines. While is generated by power plants and transmitted over customers can choose another supplier, BGE will high-voltage lines to local distribution systems. With continue to be responsible for maintaining the lines that deregulation, customers can choose to buy electricity deliver the power. BGE will also continue to restore from a number of different suppliers including other power after service interruptions and provide utilities, energy marketers or retailers, or BGE. emergency services.

I To meet these requirements, the team is extending the taught us some valuable lessons in what we need to do to meet

,..apabilities of our Customer Information System, developing customers' expectations during major outages. As a result, we new e-commerce interfaces with electricity suppliers, and are implementing significant changes to our processes and implementing a new system to support load and capacity systems to shorten restoration time and provide customers settlement. Also we have designed a newly itemized bill with better information about our progress.

and are working with the state to educate consumers so they can make informed choices.

Meeting Demand for Natural Gas Delivery There has been tremendous growth in demand for natural Focused on Reliability, Power Quality and Costs gas hookups over the past few years, and we've expanded Today the standards for power quality and service reliability our system to respond to it. Since January 1997, our gas are higher than they've ever been. That's because in the digital employees have added more than 28,000 new homes and age, a split-second loss of power can shut down an entire collected increased access fees to production line. To provide customers the quality of service do that. In the last three they require, we have been improving our delivery systems. years, they've achieved Using new technology, we are increasing reliability and power a nearly 7% annual ,,

quality while reducing costs. growth in operating income. They have An example is our award-winning System Control Integration achieved this Program, which brings substation monitoring and control growth while systems into the 21st century. A team of employees designed and keeping gas rates built what has become the prototype for future BGE substations.

economical for The program automatically gives our system planners, operators, our customers.

nd analysts the real-time and historical data they need. It also

'\..-Aeasures the quality of the power supply, improving our ability to deliver the reliable, clean energy today's customers require. Measuring Success In addition to these benefits, this program reduces substation by Customer Satisfaction construction and maintenance costs because there are fewer The result of all of our efforts is ultimately measured by components and less to maintain once it's built.

customers' satisfaction with our service. That's why we keep a close eye on how our customers rate us and how we rank when compared with national benchmarks.

Focused on Preventing Outages and Improving Restoration after Storms Over the years BGE employees have met the high standards We continue to direct our focus from responding to outages set by customers, maintaining consistently high satisfaction to preventing them. Over the last five years, we have invested ratings from residential customers and performing well above about $285 million to improve overall electric system perform the national average when compared with other investor-owned ance. Notably, from 1994 to 1998, we reduced the average utilities. We have also seen marked improvement in how small number of service interruptions by 36%. business and large industrial customers view us, a record we continue to work to improve.

Even with these improvements, BGE's Utility Operations Group last year faced one of its most challenging years ever After deregulation of the supply side of the business, we will be for weather-related events. A devastating ice storm hit in an energy delivery company, serving marketers and suppliers as January. Then the wrath of Hurricane Floyd in September well as our traditional customer base. To reflect these changes, caused the worst damage to our system in company history. we are now expanding and modifying our customer satisfaction monitoring. Now, more than ever, we need to know how we are Our employees responded in heroic fashion to both of these measuring up in our customers' eyes.

events. Hurricane Floyd's "once-in-a-lifetime" damage to the

'ectric distribution system tested the limits of our people, our

"--storm management organization, and our customers. It also I

I Ultimately, a company is only as good as its employees. Likewise, a community is only as strong as its citizens and businesses.

GeneratingSuccess with Powerful Partnerships Throughout its long history, BGE and its employees have formed powerful partnershipsfor positive change with the communities we serve. We begin 2000 as ConstellationEnergy Group, a strong company committed to building on BGE's legacy of serving customers, supporting the community, and preserving the environment for future generations.

Here's a look at some of what we've done:

U* Constellation Energy Group and its employees led QU Always innovating, employees at our coal-fired power Maryland companies in both United Way and March of plants have developed a variety of ways to manage coal Dimes giving. We contributed more than $2.3 million to ash in an environmentally sound manner. Last year, our the United Way, and our $105,000 contribution to the Brandon Shores plant opened a unique ash processing March of Dimes was tops in the state. facility. Owned and operated by Separation Technologies, m Our corporate contributions program remained a leader, Inc., it produced more than 30,000 tons of low-carbon ash evaluating and responding to 1,650 requests for support, and that was then marketed to ready-mix concrete companies.

donating over $5 million to programs that provide for those Next year's goal is 120,000 tons.

less fortunate and enrich the quality of life in Maryland.

Our employees have always rolled up their sleeves to help where help is needed. In fact, over the past two years they donated more than 8,000 pints of blood to the Red Cross, provided more than 21,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of community service, and raised more than $300,000 for various nonprofit groups in Maryland.

M In 1994, to help children start school ready to learn, we established the Early Childhood Development grant program. As our program continues, we've donated more than $3 million to assist early childhood education programs in Maryland.

I=n To recognize our 1998 recycling efforts, the Environmental At our PowerFest '99 celebration,employees opened the Protection Agency in 1999 named BGE a WasteWise Prograrr gates and hosted a full day of fun and educationalevents Champion. During that period we recycled 562 tons of for more than 1,500 residents who live near our Brandon paper, 599 tons of aluminum, and 750 tons of utility poles. Shores/Wagnerpowerplant.

Financial Review 18 Selected Financial Data 19 Utility Operating Statistics 20 Management's Discussion and Analysis 39 Forward Looking Statements 40 Report of Management 40 Report of Independent Accountants 41 Consolidated Statements of Income 41 Consolidated Statements of Comprehensive Income 42 Consolidated Balance Sheets 44 ConsoLidated Statements of Cash Flows 45 Consolidated Statements of Common Shareholders' Equity 46 Consolidated Statements of Capitalization 48 Consolidated Statements of Income Taxes 49 Notes to Consolidated Financial Statements

I ( Selected Financial Data )

Compounded 1999 1998 1997 1996 1995 Growth (Dollaramounts in millions, except per share amounts) 5-Year 10-Year Summary of Operations Total Revenues $3,786.2 $3,358.1 $3,307.6 $3,153.2 $2,934.8 6.35% 6.42%

Operating Expenses 3,026.3 2,617.0 2,584.0 2,483.7 2,239.1 7.10 6.88 Income From Operations 759.9 741.1 723.6 669.5 695.7 3.65 4.78 Other Income (Expense) 7.9 5.7 (52.8) 6.1 8.8 (24.55) (12.75)

Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8 675.6 704.5 2.84 4.23 Fixed Charges 255.0 262.7 258.7 237.0 237.6 2.09 3.43 Income Before Income Taxes 512.8 484.1 412.1 438.6 466.9 3.22 4.65 Income Taxes 186.4 178.2 158.0 166.3 169.5 3.91 8.61 Income Before Extraordinary Item 326.4 305.9 254.1 272.3 297.4 2.84 2.96 Extraordinary Loss, Net of Income Taxes (66.3) - - -

Net Income $ 260.1 $ 305.9 $ 254.1 $ 272.3 $ 297.4 (1.72) 0.65 Earnings Per Share of Common Stock and Earnings Per Share of Common Stock- Assuming Dilution Before Extraordinary Item $ 2.18 $ 2.06 $ 1.72 $ 1.85 $ 2.02 2.47 0.72 Extraordinary Loss, Net of Income Taxes (.44) - - -

Earnings Per Share of Common Stock and Earnings Per Share of Common Stock Assuming Dilution $ 1.74 $ 2.06 $ 1.72 $ 1.85 $ 2.02 (2.05) (1.53)

Dividends Declared Per Share of Common Stock $ 1.68 $ 1.67 $ 1.63 $ 1.59 $ 1.55 2.16 1.99 Summary of Financial Condition Total Assets $9,683.8 $9,275.0 $8,900.0 $8,678.2 $8,419.1 4.25 5.30 Capitalization Long-term debt $2,575.4 $3,128.1 $2,988.9 $2,758.8 $2,598.2 (0.07) 2.18 Preferred stock .- - 59.2 Redeemable preference stock - - 90.0 134.5 242.0 Preference stock not subject to mandatory redemption 190.0 190.0 210.0 210.0 210.0 4.84 5.62 Common shareholders' equity 2,993.0 2,981.5 2,870.4 2,854.7 2,811.2 1.94 4.11 Total Capitalization $5,758.4 $6,299.6 $6,159.3 $5,958.0 $5,920.6 (0.12) 2.34 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.87 2.60 2.35 2.44 2.52 Book Value Per Share of Common Stock $ 20.01 $ 19.98 $ 19.44 $ 19.33 $ 19.06 Number of Common Shareholders (In Thousands) 66.1 69.9 73.7 77.6 79.8 Certainprior-yearamounts have been reclassified to conform with the currentyear'spresentation.

ConstellationEnergy Group Inc. and Subsidiaries

(Utility Operating Statistics )I Compounded 1999 1998 1997 1996 1995 Growth Electric Operating Statistics 5-Year 10-Year Revenues (In Millions)

Residential $ 975.2 $ 948.6 $ 932.5 $ 958.7 $ 955.2 0.92% 4.16%

Commercial 939.3 912.9 892.6 861.3 879.4 1.95 3.45 Industrial 204.3 211.5 211.9 207.6 208.5 (0.13) 0.63 System Sales 2,118.8 2,073.0 2,037.0 2,027.6 2,043.1 1.26 3.45 Interchange and Other Sales 112.1 120.8 132.7 155.9 167.0 (1.02) 20.20 Other 29.1 27.0 22.3 25.5 21.0 8.79 3.87 Total $2,260.0 $2,220.8 $2,192.0 $2,209.0 $2,231.1 1.22 3.86 Sales (In Thousands)-MWH Residential 11,349 10,965 10,806 11,243 10,966 1.24 1.85 Commercial 13,565 13,219 12,718 12,591 12,635 1.89 2.05 Industrial 4,350 4,583 4,575 4,596 4,591 (0.38) 0.21 System Sales 29,264 28,767 28,099 28,430 28,192 1.29 1.67 Interchange and Other Sales 4,785 5,454 6,224 7,580 8,149 (3.38) 23.18 Total 34,049 34,221 34,323 36,010 36,341 0.54 2.98 Customers (In Thousands)

Residential 1,021.4 1,009.1 1,001.0 995.2 988.2 0.86 1.12 Commercial 107.7 106.5 105.9 104.5 103.4 1.11 1.25 Industrial 4.7 4.6 4.5 4.3 4.1 3.28 4.25 Total 1,133.8 1,120.2 1,111.4 1,104.0 1,095.7 0.89 1.14 Average Use per Residential Customer-KWH 11,111 10,866 10,794 11,297 11,097 0.38 0.72 Average Rate per KWH (System Sales)-

Residential 8.59 8.65 8.63 8.53 8.71 (0.32) 2.26 Commercial 6.92 6.91 7.02 6.84 6.96 0.03 1.37 Industrial 4.70 4.62 4.63 4.52 4.54 0.26 0.44 Peak Load (One-Hour)-MW 6,383 6,045 5,980 5,955 5,947 1.12 1.87 Capability at Summer Peak-MW 6,522 6,422 6,741 6,800 6,731 (0.60) 0.57 System Load Factor 55.7% 57.4% 56.9% 57.5% 57.2% 0.36 (0.30)

Gas Operating Statistics Revenues (In Millions)

"-'- Residential -Excluding Delivery Service $ 298.1 $ 279.2 $ 321.7 $ 320.1 $ 248.3 2.56 2.09

-Delivery Service 11.5 4.9 0.5 -

Commercial-Excluding Delivery Service 79.3 75.6 113.5 125.1 109.9 (8.10) (3.45)

-Delivery Service 24.4 19.4 12.9 7.2 3.7 60.37 18.68 Industrial -Excluding Delivery Service 8.2 8.0 11.4 17.1 16.7 (16.50) (7.76)

-Delivery Service 16.1 16.0 17.2 14.6 16.3 10.89 (3.38)

System Sales 437.6 403.1 477.2 484.1 394.9 1.03 0.89 Off-System Sales 42.9 40.9 37.5 26.6 Other 7.7 7.2 6.9 6.6 5.6 7.35 (3.76)

Total $ 488.2 $451.2 $ 521.6 $ 517.3 $ 400.5 3.00 1.72 Sales (In Thousands)-DTH Residential -Excluding Delivery Service 34,272 33,595 39,958 43,784 40,211 (3.18) (1.49)

-Delivery Service 4,468 1,890 205 -

Commercial-Excluding Delivery Service 11,733 11,775 18,435 22,698 23,612 (13.13) (6.08)

-Delivery Service 20,288 16,633 12,964 8,755 6,982 25.60 13.38 Industrial -Excluding Delivery Service 1,367 1,412 2,016 2,887 4,102 (20.88) (9.47)

-Delivery Service 33,118 34,798 38,791 36,201 35,925 (0.43) (1.73)

System Sales 105,246 100,103 112,369 114,325 110,832 (0.65) (0.50)

Off-System Sales 15,543 16,724 14,759 9,968 Total 120.789 116.827 127.128 124.293 110.832 2.13 0.88 Customers (In Thousands)

Residential 543.5 532.5 524.5 516.5 506.8 1.76 1.20 Commercial 39.9 39.6 39.3 38.9 38.4 1.03 1.09 Industrial 1.3 1.3 1.3 1.3 1.3 - (0.74)

Total 584.7 573.4 565.1 556.7 546.5 1.70 1.19 Average Use per Residential Customer (Excluding Delivery Service)--Therms 631 631 762 848 794 (4.85) (2.65)

Average Rate per Therm-$

Residential (Excluding Delivery Service) .87 .83 .81 .73 .62 6.00 3.61 Commercial (Excluding Delivery Service) .68 .64 .62 .55 .47 5.92 2.92 Industrial (Excluding Delivery Service) .60 .57 .57 .59 .41 5.46 1.84 Peak Day Sendout (In Thousands)-DTH 727.8 658.4 765.0 709.0 706.3 (0.91) 0.93 Peak Day Capability (In Thousands)-DTH 836.6 833.0 870.0 870.0 847.0 (0.25) 0.95 Utility operatingstatisticsdo not reflect the eliminationof intercompany transactions.

ConstellationEnergy Group Inc. and Subsidiaries

I SManagement's Discussion and AnaLysis) of Financial Condition and Results of Operations Introduction On April 30, 1999, Constellation Energy Group, Inc. In this discussion and analysis, we explain the general (Constellation Energy) became the holding company for financial condition and the results of operations for Baltimore Gas and Electric Company (BGE) and Constellation Constellation Energy including:

Enterprises, Inc. Constellation Enterprises was previously "*what factors affect our business, owned by BGE.

"*what our earnings and costs were in 1999 and 1998, Constellation Energy's subsidiaries primarily include "*why earnings and costs changed from the year before, BGE and a group of energy services businesses focused mostly on power marketing and merchant generation in "*where our earnings came from, North America. "*how all of this affects our overall financial condition, BGE is an electric and gas public utility company with a "*what our expenditures for capital projects were in 1997 service territory that covers the City of Baltimore and all through 1999, and what we expect them to be in 2000 or part of ten counties in Central Maryland. through 2002, and Our energy services businesses are: "*where we expect to get cash for future capital expenditures.

"*Constellation Power Source,TM Inc.-wholesale power As you read this discussion and analysis, refer to our marketing, Consolidated Statements of Income on page 41, which

"*Constellation PowerM Inc. and Subsidiaries-power present the results of our operations for 1999, 1998, and 1997.

projects, We analyze and explain the differences between periods by operating segment. Our analysis is important in making

"*Constellation Energy Source,TM Inc.--energy products decisions about your investments in Constellation Energy.

and services, Also, this discussion and analysis is based on the operation

"*Constellation Nuclear GroupM LLC-nuclear generation of the electric generation portion of our utility business under and consulting services, current rate regulation. The electric utility industry is under

"*BGE Home Products & Services,TM Inc. and going rapid and substantial change. On April 8, 1999, Subsidiaries-home products, commercial building Maryland enacted legislation authorizing customer choice and systems, and residential and small commercial gas retail competition among electric suppliers. On November 10, 1999, marketing, and the Maryland Public Service Commission (Maryland PSC)

"*District Chilled Water General Partnership issued Order No. 75757 (Restructuring Order) approving a (ComfortLink) -a general partnership, in which BGE is Stipulation and Settlement Agreement between BGE and a a partner, that provides cooling services for commercial majority of the active parties involved in the electric restruc customers in Baltimore. turing proceeding that resolves the major issues surrounding Our other businesses are: electric restructuring. See the "Electric Restructuring" section on page 24 and Note 4 on page 58 for a detailed discussion

  • Constellation Investments,TM Inc.-financial investments, and of the Restructuring Order.
  • Constellation Real Estate Group,TM Inc.-real estate and Our electric business will change significantly beginning senior-living facilities.

July 1, 2000 as we enter into retail customer choice for References in this report to "we" and "our" are to electric generation and our generation assets are transferred Constellation Energy and its subsidiaries, collectively. to nonregulated subsidiaries of Constellation Energy. Accordingly, References in this report to the "utility business" are to BGE. the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance.

ConstellationEnergy Group Inc. and Subsidiaries

I Strategy

" M change toward customer choice will significantly impact The We cannot predict whether any of the strategies described our business going forward. In response to this change, we above may actually occur, or what their effect on our financial regularly evaluate our strategies with two goals in mind: condition or competitive position might be. However, with the to improve our competitive position, and to anticipate and shift toward customer choice, competition, and the growth of adapt to regulatory change. We are realigning our organization our nonregulated subsidiaries, various factors Will affect our combining all of our domestic merchant energy businesses. financial results in the future. These factors include, but are We will continue to invest in the growth of these businesses, not limited to, operating our currently regulated generation with the objective of providing new sources of earnings in assets in a deregulated market beginning July 1, 2000 without anticipation of lower electric utility revenues. In addition, the benefit of a fuel rate adjustment clause, the loss of revenues we might consider one or more of the following strategies: due to customers choosing alternate suppliers, higher volatility

"*the complete or partial separation of our transmission of earnings and cash flows, and increased financial requirements of our nonregulated subsidiaries. Please refer to the "Forward and distribution functions, Looking Statements" section on page 39 for additional factors.

"*the construction, purchase or sale of generation assets,

"*mergers or acquisitions of utility or non-utility businesses,

"*spin-off or sale of one or more businesses, and

"*growth of earnings from other nonregulated businesses.

Current Issues Competition-Electric We expect BGE to transfer approximately $278 million of tax Electric utilities are facing competition on various fronts, exempt debt to our nonregulated subsidiaries related to the including: transferred assets and that BGE will receive approximately

"*construction of generating units to meet increased $1.1 billion in unsecured promissory notes. Repayments of demand for electricity, the notes by our nonregulated subsidiaries will be used exclusively to service certain long-term debt of BGE. BGE

"*sale of electricity in bulk power markets, will also transfer equity associated with the generating assets

"*competing with alternative energy suppliers, and to nonregulated subsidiaries of Constellation Energy.

"*electric sales to retail customers. Under the Restructuring Order, BGE will provide standard On April 8, 1999, Maryland enacted legislation authorizing offer service to customers at fixed rates over various time customer choice and competition among electric suppliers. periods during the transition period for those customers that In addition, on November 10, 1999, the Maryland PSC do not choose an alternate supplier once customer choice issued a Restructuring Order that resolved the major issues begins July 1, 2000. In addition, the electric fuel rate will be surrounding electric restructuring. These matters are discontinued effective July 1, 2000. Nonregulated subsidiaries discussed further in the "Electric Restructuring" section of Constellation Energy will provide BGE with the energy and on page 24 and Note 4 on page 58. capacity required to meet its standard offer service obligations for the first three years of the transition period. Standard offer As a result of the deregulation of BGE's electric generation, service will be competitively bid thereafter.

no earlier than July 1, 2000, and upon receipt of all regulatory approvals, we expect that BGE will transfer, at book value, its Nonregulated subsidiaries of Constellation Energy will obtain nuclear generating assets and its nuclear decommissioning the energy and capacity to supply BGE's standard offer service trust fund to a subsidiary of Constellation Nuclear Group, obligations from the Calvert Cliffs Nuclear Power Plant (Calvert LLC. In addition, we expect that BGE will transfer, at book Cliffs) and BGE's former fossil plants, supplemented with energy value, its fossil generating assets and its partial ownership purchased from the wholesale energy market as necessary. Our interest in two coal plants and a hydroelectric plant located earnings will be exposed to the risks of the competitive whole in Pennsylvania to a nonregulated subsidiary of Constellation sale electricity market to the extent that our nonregulated Energy. In total, these generating assets represent about subsidiaries have to purchase energy and/or capacity or generate 6,240 megawatts of generation capacity with a total projected energy to meet obligations to supply power to BGE at market net book value at June 30, 2000 of approximately $2.4 billion. prices or costs, respectively, which may approach or exceed ConstellationEnergy Group Inc. and Subsidiaries I

I BGE's standard offer service rates. We will also be affected by Calvert Cliffs License Extension operational risk, that is, the risk that a generating plant is not In 1998, we filed an application with the Nuclear Regulatory .

available to produce energy when the energy is required. Commission (NRC) for a 20-year license extension for Until July 1, 2000, we will continue to recover our cost of Calvert Cliffs to extend its license beyond 2014 for electric fuel as long as the Maryland PSC finds that, among Unit 1 and 2016 for Unit 2. License renewal evaluations other things, we have kept the productive capacity of our focus on age-related issues in long-lived passive components generating plants at a reasonable level. After July 1, 2000, (passive components include buildings, the reactor vessel, any energy purchased to meet BGE's load commitments will piping, ventilation ducts, electric cables, etc.). We must become a cost of doing business in the newly competitive demonstrate that we can ensure that these passive components marketplace. Therefore, if BGE provides standard offer service will continue to perform their intended functions through the at fixed rates to its customers that do not select an alternative renewal period. The NRC will also consider the impact provider as required under the terms of the Restructuring Order, of the 20-year license extension on the environment.

and the load demand exceeds our capacity to supply energy due According to the NRC's timetable, approval of BGE's to a plant outage, we would be required to purchase additional application is expected in April 2000. However, we cannot power in the wholesale energy market. If the price of obtaining predict the actual timing of the NRC's decision, or the impact, energy in the wholesale market exceeds the fixed standard if any, on our financial results. If we do not receive the license offer service price, our earnings would be adversely affected. extension, we may not be able to operate the Calvert Cliffs Imbalances in demand and supply can occur not only because units beyond 2014 and 2016.

of plant outages, but also because of transmission constraints BGE is currently involved in a lawsuit titled National or due to extreme temperatures (hot or cold) causing demand Whistleblower Center v. Nuclear Regulatory Commission and to exceed available supply. Baltimore Gas and Electric Company regarding its license We will use appropriate risk management techniques consistent extension process. The matter involves an appeal of the with our business plan and policies to address these issues. NRC's dismissal of Whistleblower's petition to intervene We cannot estimate the impact of the increased financial in the license renewal proceeding. At issue was the NRC's risks associated with this transition. However, these financial adoption of a streamlined procedure for the proceeding, risks could have a material impact on our, and BGE's, including the requirement that any requests for extensions financial results. of time be justified by a showing of "unavoidable and extreme circumstances" rather than the "good cause" standard previously applied. Applying the new standard, the NRC Competition-Gas ultimately dismissed Whistleblower's petition to intervene.

Currently, no regulation exists for the wholesale price of This matter is pending before the court.

natural gas as a commodity, and the regulation of interstate transmission at the federal level has been reduced. All BGE industrial and commercial gas customers, and effective Environmental and Legal Matters November 1, 1999, all BGE residential customers have You will find details of our environmental matters in Note 10 the option to purchase gas from other suppliers. on page 69 and in our most recent Annual Report on Form 10-K under Item 1. Business-Environmental Matters. You will find details of our legal matters in our most recent Annual Early Retirement Program Report on Form 10-K under Item 3. Legal Proceedings. Some In recognition of the changing business environment, in 1999, of the information is about costs that may be material to our our Board of Directors approved a Targeted Voluntary Special financial results.

Early Retirement Program (TVSERP) to provide enhanced early retirement benefits to certain eligible participants in targeted jobs that elect to retire on June 1, 2000. The financial Year 2000 impacts of the TVSERP will be reflected in the second We did not experience any significant problems associated quarter of 2000. with the year 2000 issue.

Accounting Standards Issued We discuss recently issued accounting standards in Note 1 on page 54.

I ConstellationEnergy Group Inc. and Subsidiaries

I Results of Operations In 1999, we had higher utility earnings before the extraordinary

"*..An this section, we discuss our earnings and the factors charge compared to 1998 mostly because we sold more affecting them. We begin with a general overview, then electricity and gas this year, and we settled a capacity contract separately discuss earnings for our operating segments. with PECO Energy Company in 1998 that had a negative impact on earnings in that year. This increase was partially offset by storm restoration activities related to Hurricane Floyd and Overview higher depreciation and amortization expense mostly due to Total EarningsPerShare of Common Stock the $75.0 million, or $48.8 million after-tax, amortization of 1999 1998 1997 the regulatory asset recorded in 1999 for the reduction of our generation plant under the Restructuring Order.

Utility business $2.03 $1.93 $1.94 Diversified businesses .45 .27 .34 We discuss our utility earnings and the Restructuring Order Total earnings per share in more detail in the "Utility Business" section on page 24.

before nonrecurring charges included in operations 2.48 2.20 2.2 In 1999, increased charges diversifiedcompared business toearnings beforebecause 1998 mostly nonrecurring of higher Nonrecurring charges included earnings from our power marketing business.

in operations:

Hurricane Floyd We discuss our diversified business earnings, including the (see Note 2 on page 55) (.03) - write-downs, further in the "Diversified Businesses" section Write-off of merger costs (see Note 2 on page 55) (.25) beginning on page 31.

Write-downs of power projects (see Note 3 on page 56) (.12)

Write-off of energy services 1998 investment (see Note 2 on page 55) (.04) Our 1998 total earnings increased $51.8 million, or $.34 per Write-down of financial S(.1l) share, compared to 1997. Our total earnings increased mostly investment (see Note 3 on page 57) - because 1997 results reflect our write-off of costs associated Write-downs of real estate with the terminated merger with Potomac Electric Power and senior-living investments (see Note 2 on page 55 and Company, and our real estate and senior-living facilities Note 3 on page 56) (.04) (m0) (.31) business' write-down of its investments in two real estate Total earnings per share before projects. This increase was partially offset by:

extraordinary item 2.18 2.06 1.72 - our real estate and senior-living facilities business' Extraordinary loss write-down of its investment in a real estate project (see Note 4 on page 59) (.44) - - in 1998, and Total e-arnings per share $1.74 $2.06 $1.72 - the write-off of an energy services investment in 1998.

In 1998, utility earnings were about the same compared to 1997.

1999 In 1998, diversified business earnings before nonrecurring Our 1999 total earnings decreased $45.8 million, or $.32 per charges decreased compared to 1997 mostly because of lower share, compared to 1998. Our total earnings decreased mostly earnings from our real estate and senior-living facilities and because we recorded an extraordinary charge of $66.3 million, financial investments businesses. This decrease was partially or $.44 per share, associated with the deregulation of the offset by higher earnings from our power projects and power electric generation portion of our business. Our 1999 total marketing businesses.

earnings also include nonrecurring write-downs recorded in our power projects, financial investments, and real estate and senior-living businesses. These decreases were partially offset by higher earnings from utility and diversified business operations excluding nonrecurring charges. We discuss the extraordinary charge in Note 4 on page 59.

ConstellationEnergy Group Inc. and Subsidiaries

I Utility Business "*BGE will be allowed to recover $528 million after-tax of .

Before we go into the details of our electric and gas its potentially stranded investments and utility restructuring, r operations, we believe it is important to discuss factors that costs through a competitive transition charge on customers' have a strong influence on our utility business performance: bills. Residential customers will pay this charge for six electric restructuring, regulation by the Maryland PSC, the years. Commercial and industrial customers will pay in weather, and other factors, including the condition of the a lump sum or over the four to six-year period, depending economy in our service territory. on the service option selected by each customer.

"*Generation-related regulatory assets and nuclear decommissioning costs will be included in delivery service Electric Restructuring rates effective July 1, 2000 and will be recovered on a On April 8, 1999, Maryland enacted the Electric Customer basis approximating their existing amortization schedules.

Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that will significantly restructure "*Starting July 1, 2000, BGE will unbundle rates to show Maryland's electric utility industry and modify the industry's separate components for delivery service, transition tax structure. charges, standard offer service (generation), transmission, universal service, and taxes.

In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The accompanying

"*On July 1, 2000, BGE will transfer, at book value, its ten Maryland-based fossil and nuclear power plants and tax legislation is discussed in detail in Note 4 on page 58.

its partial ownership interest in two coal plants and a On November 10, 1999, the Maryland PSC issued a hydroelectric plant in Pennsylvania to nonregulated Restructuring Order that resolves the major issues surrounding subsidiaries of Constellation Energy.

electric restructuring, accelerates the timetable for customer "*BGE will reduce its generation assets, as discussed in choice, and addresses the major provisions of the Act. The Note 4 on page 59, by $150 million pre-tax during the Restructuring Order also resolves the electric restructuring period July 1, 1999 - June 30, 2000 to mitigate a portion proceeding (transition costs, customer price protections, and of its potentially stranded investments.

unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC)

"*Universal service will be provided for low-income customers without increasing their bills. BGE will provide to lower our electric base rates. The major provisions of the its share of a statewide fund totaling $34 million annually.

Restructuring Order are:

" All customers, except a few commercial and industrial We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's companies that have signed contracts with BGE, will be electric generation business to require BGE to discontinue the able to choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service application of Statement of Financial Accounting Standards for customers that do not select an alternative supplier. (SFAS) No. 71, Accountingfor the Effects of Certain Types of Regulation for that portion of its business. Accordingly, In either case, BGE will continue to deliver electricity in the fourth quarter of 1999, we adopted the provisions of to all customers in areas traditionally served by BGE.

SFAS No. 101, Regulated Enterprises-Accountingfor the

"*BGE's current electric base rates are frozen at their Discontinuationof FASB Statement No. 71 and Emerging current levels until July 1, 2000. Issues Task Force Consensus (EITF) No. 97-4, Deregulation

"*BGE will reduce residential base rates by approximately of the Pricing of Electricity-IssuesRelated to the Application 6.5% on average, about $54 million a year, beginning of FASB Statements No. 71 and 101 for BGE's electric gener July 1, 2000. These rates will not change before July 2006. ation business. BGE's transmission and distribution business

"*Commercial and industrial customers will have up to continues to meet the requirements of SFAS No. 71 as that four service options that will fix electric energy rates and business remains regulated. We describe the effect of applying transition charges for a period that generally ranges from these accounting requirements in Note 4 on page 59.

four to six years. In early December, the Mid-Atlantic Power Supply

"*Electric delivery service rates will be frozen for a four Association (MAPSA), Trigen-Baltimore Energy Corporation, year period for commercial and industrial customers. and Sweetheart Cup Company, Inc. filed appeals of the The generation and transmission components of rates Restructuring Order. MAPSA also filed a motion seeking to will be frozen for different time periods depending on delay the implementation of the Restructuring Order pending the service options selected by those customers.

Constellation Energy Group Inc. and Subsidiaries

I a decision on the merits by the court. While we believe that Fuel Rate

,,_,the appeals are without merit, no assurances can be given as Currently, we charge our electric customers separately for the to the timing or outcome of these cases, and whether the fuel we use to generate electricity (nuclear fuel, coal, gas, or outcome will have a material adverse effect on our and oil) and for the net cost of purchases and sales of electricity.

BGE's financial results. We charge the actual cost of these items to the customer with no profit to us. If these costs go up, the Maryland PSC permits us to increase the fuel rate. If these costs go down, our Regulation by the Maryland PSC customers benefit from a reduction in the fuel rate. The fuel Under traditional rate regulation that will continue for all BGE's rate is mostly impacted by the amount of electricity generated businesses except electric generation beginning July 1, 2000, at Calvert Cliffs because the cost of nuclear fuel is cheaper the Maryland PSC determines the rate we can charge our than coal, gas, or oil.

customers. Our rates consist of a "base rate," a "conservation surcharge," and a "fuel rate." Under the Restructuring Order, BGE's electric fuel rate is frozen at its current level until July 1, 2000, at which time the fuel rate clause will be discontinued. We will continue Base Rate to defer the difference between our actual costs of fuel and The base rate is the rate the Maryland PSC allows us to energy and what we collect from customers under the fuel charge our customers for the cost of providing them service, rate through June 30, 2000. After that date, earnings will be plus a profit. We have both an electric base rate and a gas affected by the changes in the cost of fuel and energy. We base rate. Higher electric base rates apply during the summer discuss our exposure to market risk further in the "Current when the demand for electricity is higher. Gas base rates are Issues" section on page 21. In addition, any accumulated not affected by seasonal changes. difference between our actual costs of fuel and energy and the Except as provided under the terms of the electric Restructuring amounts collected from customers under the electric fuel rate Order discussed on page 24, BGE may ask the Maryland PSC clause will be collected from our customers over a period to to increase base rates from time to time. The Maryland PSC be determined by the Maryland PSC. At December 31, 1999, the amount to be collected from customers was $60.0 million.

historically has allowed BGE to increase base rates to recover increased utility plant asset costs, plus a profit, beginning at We charge our gas customers separately for the natural gas

'--/the time of replacement. Generally, rate increases improve our they purchase from us. The price we charge for the natural utility earnings because they allow us to collect more revenue. gas is based on a market based rates incentive mechanism However, rate increases are normally granted based on histor approved by the Maryland PSC. We discuss market based ical data and those increases may not always keep pace with rates in more detail in the "Gas Cost Adjustments" section increasing costs. Other parties may petition the Maryland PSC on page 29 and in Note 1 on page 51.

to decrease base rates.

On November 17, 1999, BGE filed an application with the Weather Maryland PSC to increase its gas base rates. We discuss this Weather affects the demand for electricity and gas. Very hot filing in the gas "Base Rates" section on page 29. summers and very cold winters increase demand. Mild weather reduces demand. Weather impacts residential Conservation Surcharge sales more than commercial and industrial sales, which are The Maryland PSC allows us to include in electric and gas rates mostly affected by business needs for electricity and gas.

a component to recover money spent on conservation programs. We measure the weather's effect using "degree days."

This component is called a "conservation surcharge." However, A degree day is the difference between the average daily under this surcharge the Maryland PSC limits what our profit actual temperature and a baseline temperature of 65 degrees.

can be. If at the end of the year we have exceeded our allowed Cooling degree days result when the average daily actual profit, we defer (include as a liability on our Consolidated temperature exceeds the 65 degree baseline. Heating degree Balance Sheets and exclude from our Consolidated Statements days result when the average daily actual temperature is less of Income) the excess in that year and we lower the amount of than the baseline.

future surcharges to our customers to correct the amount of overage, plus interest. As a result of the Restructuring Order, the electric conservation surcharge was frozen at its current level and the associated profit limitation is no longer applicable.

ConstellationEnergy Group Inc. and Subsidiaries I

r During the cooling season, hotter weather is measured by Usage per customer refers to all other items impacting /

more cooling degree days and results in greater demand for customer sales that cannot be measured separately. These electricity to operate cooling systems. During the heating factors include the strength of the economy in our service season, colder weather is measured by more heating degree territory. When the economy is healthy and expanding, days and results in greater demand for electricity and gas customers tend to consume more electricity and gas.

to operate heating systems. Conversely, during an economic downtrend, our customers Effective March 1, 1998, the Maryland PSC allowed us to tend to consume less electricity and gas.

implement a monthly adjustment to our gas business revenues to eliminate the effect of abnormal weather patterns. We discuss Utility Business Earnings this further in the "Weather Normalization" section on page 29.

Per Share of Common Stock We show the number of cooling and heating degree days in 1999 and 1998, the percentage change in the number of degree days from the prior year, and the number of degree 1999 1998 1997 days in a "normal" year as represented by the 30-year Electric business $1.81 $1.75 $1.77 average in the following table. Gas business .22 .18 .17 30-year Total utility earnings per share 1999 1998 average before nonrecurring charge Cooling degree days 845 915 843 included in operations 2.03 1.93 1.94 Percentage change from prior year (7.7)% 22.7% Nonrecurring charge included Heating degree days in operations:

4,585 4,119 4,755 Hurricane Floyd Percentage change from prior year 11.3% (14.6)%

(see Note 2 on page 55) (.03) -

Write-off of merger costs Other Factors (see Note 2 on page 55) - - (.25)

Other factors, aside from weather, impact the demand for lotal utility earnings per share electricity and gas. These factors include the "number of before extraordinary item 2.00 1.93 1.69 3/4 customers" and "usage per customer" during a given period. Extraordinary loss We use these terms later in our discussions of electric and gas (see Note 4 on page 59) (.44) -

operations. In those sections, we discuss how these and other Total utility earnings per share $1.56 $1.93 $1.69 factors affected electric and gas sales during 1999 and 1998.

The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory. When customer choice for Our 1999 total utility earnings decreased $53.9 million, or

$.37 per share, compared to 1998. Our 1998 total utility earnings electric generation begins on July 1, 2000, a portion of BGE's increased $36.1 million, or $.24 per share, compared to 1997.

electric customers will become delivery service customers We discuss the factors affecting utility earnings below.

only and will purchase their electricity from other sources.

Other electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Electric Operations Order. To the extent our electricity generation exceeds or is The discussion below reflects the operations of the electric less than the electricity demanded by customers utilizing our generation portion of our utility business under current rate standard offer service, the incremental electricity will be sold regulation by the Maryland PSC. Our electric business will or purchased in the wholesale market at prevailing market change significantly beginning July 1, 2000 as we enter into prices. We discuss our exposure to market risk further in the retail customer choice for electric generation. Also, no earlier "Current Issues" section on page 21. than July 1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation assets will be transferred, at book value, to nonregulated subsidiaries of Constellation Energy.

These assets represent about 6,240 megawatts of generation capacity with a total projected net book value at June 30, 2000 of approximately $2.4 billion.

ConstellationEnergy Group Inc. and Subsidiaries

I Ve estimate that the electric generation portion of our In 1999, we sold more electricity to residential customers due

  • ..,usiness currently represents about one-half of BGE's to higher usage per customer, colder winter weather, and an operating income. increased number of customers. This increase was partially We expect BGE to transfer approximately $278 million of tax offset by milder spring and early summer weather. We sold more electricity to commercial customers mostly due to higher exempt debt to our nonregulated subsidiaries related to the usage per customer, an increased number of customers, and transferred assets and that BGE will receive approximately

$1.1 billion in unsecured promissory notes. Repayments colder winter weather. We sold less electricity to industrial customers mostly because usage by Bethlehem Steel and other of the notes by our nonregulated subsidiaries will be used industrial customers decreased. Usage decreased at Bethlehem exclusively to service certain long-term debt of BGE. BGE will also transfer equity associated with the generating assets Steel as a result of a shut-down from June to August for an upgrade to their facilities that temporarily reduced their to nonregulated subsidiaries of Constellation Energy.

electricity consumption. This decrease was partially offset Given the uncertainties surrounding electric deregulation as by an increase in the number of industrial customers.

discussed in the "Strategy" and "Current Issues" sections In 1998, we sold more electricity to residential customers on page 21, the results discussed in this section may not mostly because of an increased number of customers, hotter be indicative of the future performance of our generation summer weather, and higher usage per customer. The increase business. Also, these results will not be indicative of the in sales to residential customers was partially offset by milder future performance of BGE once BGE transfers all of its winter weather. We sold more electricity to commercial generation assets to nonregulated subsidiaries of Constellation customers mostly because of higher usage per customer.

Energy. The impact of this transfer on BGE's financial results We sold about the same amount of electricity to industrial will be material. The total assets, liabilities, and common share customers as we did in 1997.

holders' equity of Constellation Energy will not change as a result of the transfer.

Base Rates Electric Revenues In 1999, base rate revenues were about the same compared "Thechanges in electric revenues in 1999 and 1998 compared to 1998.

the respective prior year were caused by: In 1998, base rate revenues decreased compared to 1997.

1999 1998 Although we sold more electricity in 1998, our base rate revenues decreased because of lower conservation surcharge revenues.

(In millions)

Electric system sales volumes $41.2 $50.8 Base rates 0.8 (6.6) Fuel Rates Fuel rates 3.7 (8.1) In 1999, fuel rate revenues increased compared to 1998 Total change in electric revenues mostly because we sold more electricity.

from electric system sales 45.7 36.1 In 1998, fuel rate revenues decreased compared to 1997.

Interchange and other sales (8.2) (13.2) Although we sold more electricity, the fuel rate was lower Other 2.1 4.6 mostly because we were able to use a less-costly mix of Total change in electric revenues $39.6 $27.5 generating plants and electricity purchases.

Electric System Sales Volumes Interchange and Other Sales "Electric system sales volumes" are sales to customers in our "Interchange and other sales" are sales in the PJM service territory at rates set by the Maryland PSC. These sales (Pennsylvania-New Jersey-Maryland) Interconnection energy do not include interchange sales and sales to others. market and to others. The PJM is a regional power pool with The percentage changes in our electric system sales volumes, members that include many wholesale market participants, as by type of customer, in 1999 and 1998 compared to the well as BGE and other utility companies. We sell energy to respective prior year were: PJM members and to others after we have satisfied the 1999 1998 demand for electricity in our own system.

Residential 3.5% 1.5%

Commercial 2.6 3.9 Industrial (5.1) 0.2 ConstellationEnergy Group Inc. and Subsidiaries

F In 1999 and 1998, interchange and other sales revenues Electric Operations and Maintenance Expenses decreased compared to the respective prior year mostly In 1999, electric operations and maintenance expenses were because higher demand for system sales reduced the amount about the same compared to 1998. In 1999, operations and of energy we had available for off-system sales. maintenance expenses include the costs for system restoration activities related to Hurricane Floyd of $7.5 million and a major winter ice storm. This was offset by lower employee Electric Fuel and Purchased Energy Expenses benefit costs in 1999 and a 1998 $6.0 million write-off of 1999 1998 1997 contributions to a third party for a low-level radiation waste (In millions) facility that was never completed.

Actual costs $538.0 $514.7 $504.5 In 1998, electric operations and maintenance expenses Net (deferral) recovery of costs increased $28.7 million compared to 1997 mostly because of:

under electric fuel rate clause (see Note 1 "*higher nuclear costs, on page 50) (70.3) (9.0) 15.2 "*higher employee benefit costs, and Total electric fuel and "*the $6.0 million write-off for the low-level radiation waste purchased energy expenses $467.7 $505.7 $519.7 facility discussed above.

Actual Costs Electric Depreciation and Amortization Expense In 1999, our actual costs of fuel to generate electricity In 1999, electric depreciation and amortization expense (nuclear fuel, coal, gas, or oil) and electricity we bought from increased $63.4 million compared to 1998 mostly because of others were higher compared to 1998 mostly because the price the $75.0 million amortization of the regulatory asset for the of electricity we bought from others was higher. The price of reduction in generation plant provided for in the Restructuring electricity changes based on market conditions and contract Order. This increase was partially offset by lower amortization terms. This increase was partially offset by our settlement of of deferred electric conservation expenditures due to the a capacity contract with PECO in 1998. write-off of a portion of these expenditures that will not be In 1998, our actual costs increased compared to 1997 mostly recovered under the Restructuring Order. We discuss the because we settled a capacity contract with PECO. accounting implications of the Restructuring Order further in Note 4 on page 59.

In 1998, electric depreciation and amortization expense Electric Fuel Rate Clause increased $26.5 million compared to 1997 mostly because:

Under the electric fuel rate clause, we defer (include as an asset or liability in our Consolidated Balance Sheets and "*in October 1998, the Maryland PSC authorized us to exclude from our Consolidated Statements of Income) the implement new electric depreciation rates retroactive to difference between our actual costs of fuel and energy and January 1, 1998, which increased depreciation expense what we collect from customers under the fuel rate in a given by approximately $13.9 million, period. We either bill or refund our customers that difference "*we had more electric plant in service (as our level of plant in the future. We discuss the calculation of the fuel rate and in service changes, the amount of our depreciation and its future discontinuance in Note I on page 50. amortization expense changes), and In 1999 and 1998, our actual costs of fuel and energy were "*we reduced the amortization period for certain computer higher than the fuel rate revenues we collected from our software beginning in the first quarter of 1998 from five customers. The increase in the 1999 deferral reflects higher years to three years.

purchased power costs, especially during record-setting summer peak loads.

ConstellationEnergy Group Inc. and Subsidiaries

I 4as Operations Base Rates

,ll BGE industrial and commercial gas customers, and In 1999, base rate revenues increased compared to 1998 mostly N'-effective November 1, 1999, all BGE residential customers due to the increase in our base rates effective March 1, 1998 as have the option to purchase gas from other suppliers. We do discussed below.

not expect the impact of customer choice to have a material In 1998, base rate revenues increased compared to 1997.

effect on our, and BGE's, financial results. Although we sold less gas during 1998, our base rate revenues increased mostly because the Maryland PSC authorized an Gas Revenues increase in our base rates effective March 1, 1998. The The changes in gas revenues in 1999 and 1998 compared to change in rates increased our base rate revenues over the the respective prior year were caused by: twelve-month period from March 1998 through February 1999 1999 1998 by approximately $16 million.

(In millions)

On November 17, 1999, we applied for a $36.3 million annual Gas system sales volumes $ 8.0 $(10.8) increase in our gas base rates. The Maryland PSC is currently Base rates 2.2 14.2 reviewing our application and is expected to issue an order by Weather normalization 4.5 10.1 June 2000.

Gas cost adjustments 19.8 (87.6)

Total change in gas revenues Weather Normalization from gas system sales 34.5 (74.1) Effective March 1, 1998, the Maryland PSC allowed us to Off-system sales (7.9) 1.8 implement a monthly adjustment to our gas revenues to elimi Other 0.5 0.1 nate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues will be Total change in gas revenues $27.1 $(72.2) based on weather that is considered "normal" for the month and, therefore, will not be affected by actual weather conditions.

Gas System Sales Volumes The percentage changes in our gas system sales volumes, Gas Cost Adjustments v type of customer, in 1999 and 1998 compared to the We charge our gas customers for the natural gas they purchase

,'_.espective prior year were: from us using gas cost adjustment clauses set by the Maryland 1999 1998 PSC. These clauses operate similarly to the electric fuel rate clause described in the "Electric Fuel Rate Clause" section on Residential 9.2% (11.6)% page 28. However, under market based rates, our actual cost Commercial 12.7 (9.5) of gas is compared to a market index (a measure of the market Industrial (4.8) (11.3) price of gas in a given period). The difference between our In 1999, we sold more gas to residential customers mostly for actual cost and the market index is shared equally between two reasons: colder winter weather and an increased number shareholders and customers, and does not significantly impact of customers. This was partially offset by lower usage per earnings. We also discuss this in Note 1 on page 51.

customer. We sold more gas to commercial customers mostly Delivery service customers, including Bethlehem Steel, are because of higher usage per customer, colder winter weather, not subject to the gas cost adjustment clauses because we are and an increased number of customers. We sold less gas to not selling gas to them. We charge these customers fees to industrial customers mostly because of lower usage by recover the fixed costs for the transportation service we Bethlehem Steel and other industrial customers. Usage by provide. These fees are the same as the base rate charged Bethlehem Steel decreased due to a shut-down from June for gas sales and are included in gas system sales volumes.

to August for an upgrade to their facilities.

In 1999, gas cost adjustment revenues increased compared In 1998, we sold less gas to residential and commercial to the same period of 1998 mostly because we sold more gas customers mostly for two reasons: milder weather and lower at a higher price.

usage per customer. This was partially offset by the increase in the number of customers. We sold less gas to industrial In 1998, gas cost adjustment revenues decreased compared to customers mostly because of lower usage by Bethlehem 1997 mostly because we sold less gas.

Steel and other industrial customers.

ConstellationEnergy Group Inc. and Subsidiaries

I Off-System Sales Gas Adjustment Clauses Off-system gas sales are low-margin direct sales of gas to We charge customers for the cost of gas sold through gas wholesale suppliers of natural gas outside our service territory. adjustment clauses (determined by the Maryland PSC), as Off-system gas sales, which occur after we have satisfied our discussed under "Gas Cost Adjustments" earlier in this section.

customers' demand, are not subject to gas cost adjustments. In 1999, actual gas costs were lower than the fuel rate The Maryland PSC approved an arrangement for part of the revenues we collected from our customers.

margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE In 1998, actual gas costs were higher than the fuel rate (which benefits shareholders). Changes in off-system sales revenues we collected from our customers.

do not significantly impact earnings.

In 1999, revenues from off-system gas sales decreased compared Gas Operations and Maintenance Expenses to 1998 mostly because we sold less gas off-system. In 1999, gas operations and maintenance expenses were about the same compared to 1998.

In 1998, revenues from off-system gas sales increased compared to 1997 mostly because we sold more gas off-system. In 1998, gas operations and maintenance expenses increased

$3.9 million compared to 1997 mostly because of higher Gas Purchased For Resale Expenses employee benefit costs.

1999 1998 1997 Gas Depreciation and Amortization Expense (In millions) In 1999, gas depreciation and amortization expense was about Actual costs $221.8 $212.2 $291.6 the same compared to 1998.

Net recovery (deferral) of In 1998, gas depreciation and amortization expense increased costs under gas adjustment $6.1 million compared to 1997 mostly because:

clauses (see Note 1 on page 51) 8.8 (3.6) 0.5

"*we had more gas plant in service, and Total gas purchased for resale expenses $230.6 $208.6 $292.1 "*we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years.

Actual Costs Actual costs include the cost of gas purchased for resale to our customers and for off-system sales. Actual costs do not include the cost of gas purchased by delivery service customers.

In 1999, actual gas costs increased compared to 1998 mostly because we sold more gas.

In 1998, actual gas costs decreased compared to 1997 mostly because we sold less gas.

ConstellationEnergy Group Inc. and Subsidiaries

I Diversified Businesses Energy Services

)ur diversified businesses engage primarily in energy services. Power Marketing

"*'/We list each of our diversified businesses in the "Introduction" In 1999, earnings from our power marketing business increased section on page 20. We describe our diversified businesses in compared to 1998 because of increased transaction margins more detail in our most recent Annual Report on Form 10-K and volume.

under "Item 1. Business - Diversified Businesses." In 1998, earnings from our power marketing business increased compared to 1997 because of increased power marketing activi Diversified Business Earnings ties in 1998, which was Constellation Power Source's first full Per Share of Common Stock year of operations.

1999 1998 1997 Constellation Power Source uses the mark-to-market method Energy services of accounting. We discuss the mark-to-market method of Power marketing $ .23 $ .05 $ accounting and Constellation Power Source's activities in Power projects .26 .30 .25 Note 1 on page 51.

Other (.05) (.01) (.05) As a result of the nature of its business activities, Constellation Total energy services earnings Power Source's revenue and earnings will fluctuate. We cannot per share before nonrecurrng predict these fluctuations, but the effect on our revenues and charges included in operations .44 .34 .20 earnings could be material. The primary factors that cause Other diversified businesses these fluctuations are:

earnings (losses) per share before "*the number and size of new transactions, nonrecurring charges included in operations .01 (.07) .14 "*the magnitude and volatility of changes in commodity Total diversified business earnings prices and interest rates, and per share before nonrecurring Sthe number and size of open commodity and derivative charges included in operations .45 .27 .34 positions Constellation Power Source holds or sells.

Nonrecurring charges included in Constellation Power Source's management uses its best operations: estimates to determine the fair value of commodity and s'Write-downs of power projects derivative positions it holds and sells. These estimates (see Note 3 on page 56) consider various factors including closing exchange and over Write-off of energy services the-counter price quotations, time value, volatility factors, and investment (see Note 2 0 credit exposure. However, it is possible that future market on page 55) - ((~ prices could vary from those used in recording assets and Write-down of financial liabilities from power marketing and trading activities, investment (see Note 3 on and such variations could be material. In 1999, assets and page 57) (lI) -liabilities from energy trading activities (as shown in our Write-downs of real estate and Consolidated Balance Sheets beginning on page 42) increased senior-living investments (see because of greater business activity during the period.

Note 2 on page 55 and Note 3 on page 56) (.04) (.10) (.31) In March 1998, we formed Orion Power Holdings, Inc. (Orion)

Total earnings per share .18 $.13 $.03 with Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., to acquire electric generating plants in the United States and Canada. Our energy services businesses own a minority interest in Orion. To date, our energy services Our 1999 diversified business earnings increased $8.1 million, businesses have funded $104 million in equity and have a or $.05 per share, compared to 1998. 0 ur 1998 diversified commitment to contribute an additional $121 million to Orion.

business earnings increased $15.7 milli on, or $.10 per share, compared to 1997.

We discuss factors affecting the earnings of our diversified businesses below.

ConstellationEnergy Group Inc. and Subsidiaries II

I Power Projects As of December 31, 1999, ten projects had already transitioned, In 1999, earnings from our power projects business decreased to variable rates. The remaining four projects will transition compared to 1998 mostly because of three factors: between February and December 2000. The projects which

" In 1999, our power projects business recorded a $14.2 million transitioned in 1999 contributed $6.2 million, or $.04 per share after-tax, or $.09 per share, write-off of two geothermal to 1999 earnings. Those changing over in 2000 contributed power projects. These write-offs occurred because the $28.0 million, or $.19 per share to 1999 earnings. We expect expected future cash flows from the projects are less than earnings from the projects changing over in 2000 to contribute the investment in the projects. For the first project, this $17.4 million, or $.12 per share to 2000 earnings.

resulted from the inability to restructure certain project Our power projects business continues to pursue alternatives for agreements. For the second project, we experienced a some of these projects including:

declining water temperature of the geothermal resource "*repowering the projects to reduce operating costs, used by one of the plants for production.

"*changing fuels to reduce operating costs,

"*In 1999, our power projects business recorded a $4.5 million after-tax, or $.03 per share, write-down to reflect the fair "*renegotiating the power purchase agreements to improve value of our investment in a power project as a result of the terms, our international exit strategy discussed on page 33. "*restructuring financing to improve existing terms, and

"*In 1998, our power projects business recorded a $10.4 million "*selling its ownership interests in the projects.

after-tax, or $.07 per share, gain for its share of earnings in a We evaluate the carrying amount of our investment in these partnership. The partnership recognized a gain on the sale of projects for impairment using the methodology discussed in its ownership interest in a power purchase agreement. Note 1 on page 52. Constellation Power's management uses In 1998, earnings from our power projects business increased its best estimates to determine if there has been an impairment compared to 1997 mostly because Constellation Power recorded of these investments and considers various factors including a $10.4 million after-tax gain for its share of earnings in a forward price curves for energy, fuel costs, and operating costs.

partnership as discussed above. However, it is possible that future estimates of market prices and project costs could vary from those used in evaluating these CaliforniaPowerPurchaseAgreements assets, and the impact of such variations could be material.

Constellation Power and subsidiaries and Constellation We also describe these projects and the transition process in Investments have $301.8 million invested in 14 projects that Note 10 on page 71.

sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. In 1999, InternationalProjects earnings from these projects, excluding any write-offs, were At December 31, 1999, Constellation Power had invested

$34.4 million, or $.23 per share, compared to $41.3 million, about $254.1 million in 10 power projects in Latin America or $.28 per share in 1998. compared to $269.7 million invested in Latin America in 1998.

Under these agreements, the electricity rates change from fixed These investments include:

rates to variable rates beginning in 1996 and continuing through "°the purchase of a 51% interest in a Panamanian electric 2000. The projects which already have had rate changes have distribution company for approximately $90 million in lower revenues under variable rates than they did under fixed 1998 by an investment group in which subsidiaries of rates. When the remaining projects transition to variable rates, Constellation Power hold an 80% interest, and we expect their revenues also to be lower than they are under fixed rates. "*approximately $98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala.

ConstellationEnergy Group Inc. and Subsidiaries

I Tn December 1999, we decided to exit the international portion In 1999, our senior-living facilities business entered into an

)f our power projects business as part of our strategy to improve agreement to sell all but one of its senior-living facilities to our competitive position. As a result, we recorded a $4.5 million Sunrise Assisted Living, Inc. Under the terms of the agreement, after-tax write-down of our investment in a generating company Sunrise was to acquire 12 of our existing senior-living facilities, in Bolivia to reflect the current fair value of this investment. We three facilities under construction, and several sites under expect to complete our exit strategy by the end of 2000. We development for $72.2 million in cash and $16.0 million in discuss our strategy further in the "Strategy" section on page 21. debt assumption. We could not reach an agreement on financing issues that subsequently arose, and the agreement was terninated Other Energy Services in November 1999. As a result, our senior-living facilities In 1999, earnings from our other energy services businesses business engaged a third-party management company to decreased compared to 1998 mostly because of lower gross manage its senior-living facilities portfolio including the three margins at our energy products and services business. facilities now under construction, scheduled to be completed In 1998, earnings from our other energy services businesses in the first half of 2000.

increased compared to 1997 due to improved results from our In 1999, Constellation Real Estate Group, Inc. (CREG) sold energy products and services business. Earnings would have Church Street Station, for $11.5 million, the approximate book been higher except we recorded a $5.5 million after-tax, or value of the complex.

$.04 per share, write-off of our investment in, and certain of In 1999, our financial investments business announced that our product inventory from, an automated electric distribution it would exchange its shares of common stock in Capital Re, an equipment company. We recorded this write-off because of insurance company, for common stock of ACE Limited (ACE),

that company's inability to raise capital and sell its products. another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock Other Diversified Businesses of Capital Re. Through September 30, 1999, our financial In 1999, earnings from our other diversified businesses increased investments business wrote down its $94.2 million investment compared to 1998 mostly because of higher earnings from our in Capital Re stock by $20.9 million after-tax, or $.14 per share, real estate and senior-living facilities business. This increase was to reflect the market value of this investment. The agreement artially offset by lower earnings from our financial investments between ACE and Capital Re was subsequently revised on a

"--business. In 1999, earnings from our real estate and senior-living more favorable basis for Capital Re to include both cash and facilities business increased compared to 1998 mostly because of: ACE stock. In December 1999, the transaction was finalized and our financial investments business recorded a $4.9 million

"*a $15.4 million after-tax write-down of its investment in after-tax, or $.03 per share, gain on this investment to reflect Church Street Station, an entertainment, dining, and retail the closing price of the business combination. This net write complex in Orlando, Florida in 1998, and down of Capital Re was partially offset by better market

"*an increase in earnings from its investment in Corporate performance of other financial investments in 1999 compared Office Properties Trust (COPT) in 1999. We discuss the to 1998.

investment in COPT below. In 1998, earnings from our other diversified businesses This increase was partially offset by a $5.8 million after-tax, decreased compared to 1997 mostly due to lower earnings or $.04 per share, write-down of certain senior-living facilities from our real estate and senior-living facilities and financial related to the proposed sale of these facilities in 1999 as investments businesses. Earnings from our real estate and discussed below. senior-living facilities business decreased mostly due to:

"*a $15.4 million after-tax write-down of its investment in Church Street Station,

"*lower earnings from various real estate and senior-living facilities projects, and

"*a $4.0 million after-tax gain on the sale of two senior living facilities projects reflected in 1997 results.

ConstellationEnergy Group Inc. and Subsidiaries

I In addition, in 1998, our real estate and senior-living facilities Under accounting rules, we are required to write down the /

business exchanged certain assets and liabilities in return for a value of a real estate project to market value in either of two 41.9% equity interest in COPT, a real estate investment trust. cases. The first is if we change our intent about a project from' In 1998, earnings from our financial investments business an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected decreased compared to 1997 mostly because of:

future cash flow from the project is less than the investment in

"*better market performance for its investments in 1997, and the project.

"*a $6.0 million after-tax gain on the sale of stock held by a financial limited parmership reflected in 1997 results.

Consolidated Nonoperating Income We discuss our real estate projects, the write-downs of our and Expenses real estate projects, the COPT transaction, and our financial Other Income and Expenses investments further in Note 3 beginning on page 56. In September. 1995, we signed an agreement to merge Most of CREG's remaining real estate projects are in the with Potomac Electric Power Company after all necessary Baltimore-Washington corridor. The area has had a surplus regulatory approvals were received. In December 1997, of available land in recent years and as a result these projects both companies mutually terminated the merger agreement.

have been economically hurt. Accordingly, in 1997, we wrote off $57.9 million of costs related to the merger. This write-off reduced after-tax Constellation Real Estate's projects have continued to incur earnings by $37.5 million, or $.25 per share.

carrying costs and depreciation over the years. Additionally, this business has been charging interest payments to expense rather than capitalizing them for some undeveloped land Fixed Charges where development activities have stopped. These carrying In 1999, fixed charges decreased $7.7 million compared costs, depreciation, and interest expenses have decreased to 1998 mostly because we had less BGE preference earnings and are expected to continue to do so. stock outstanding.

Cash flow from real estate operations has not been enough to In 1998, fixed charges increased $4.0 million compared to make the monthly loan payments on some of these projects. 1997 mostly because we had more debt outstanding. Our Cash shortfalls have been covered by cash obtained from the fixed charges would have been higher except we had less cash flows of other diversified subsidiaries. BGE preference stock outstanding and lower interest rates We consider market demand, interest rates, the availability of in 1998 compared to 1997.

financing, and the strength of the economy in general when making decisions about our real estate projects. If we were to Income Taxes decide to sell our real estate projects, we could have write In 1999, income taxes increased $8.2 million compared to downs. In addition, if we were to sell our real estate projects 1998 because we had higher taxable income from both our in the current market, we would have losses which could be utility operations and our diversified businesses.

material, although the amount of the losses is hard to predict.

Depending on market conditions, we could also have material In 1998, income taxes increased $20.2 million compared to losses on any future sales. 1997 because we had higher taxable income from both our utility operations and our diversified businesses.

Our current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. We Please refer to Note 4 on page 58 for a discussion of tax law evaluate strategies for all our businesses, including real estate, changes. These changes are designed, in part, to tax Maryland electric generating facilities on a more comparable basis with on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry electric generation in other states.

will cause us to evaluate thoroughly all business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial.

Constellation Energy Group Inc. and Subsidiaries

I

'Financial Condition In 1999, we used more cash for financing activities compared

,,ash Flows to 1998 mostly because we repaid more long-term debt and 1999 1998 1997 issued less long-term debt and common stock. This was (In millions) partially offset by a decrease in the redemption of BGE Cash provided by (used in): preference stock and higher net short-term borrowings in Operating Activities $679.0 $799.8 $696.3 1999 compared to 1998.

Investing Activities (615.1) (711.3) (520.8) In 1998, cash used in financing activities was about the same Financing Activities (144.9) (77.4) (79.6) compared to 1997. In 1998, we issued more long-term debt and common stock, and had contributions from minority In 1999 and 1998, cash provided by operations changed interests of approximately $86 million related to the acquisition compared to the respective prior year mostly because of of a distribution company in Panama. This was offset by the changes in working capital requirements. repayment of short-term borrowings that matured, sinking fund requirements, and early redemption of higher cost securities.

In 1999, we used less cash for investing activities compared to 1998 mostly due to lower investments in international power projects and in the real estate and senior-living Security Ratings facilities business. This was partially offset by: Independent credit-rating agencies rate Constellation Energy

"*our energy services businesses increased the investment and BGE's fixed-income securities. The ratings indicate the in Orion Power Holdings, Inc. by $97.7 million, agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these

"*our power projects business increased its investment securities. These ratings affect how much it will cost each in domestic power projects, primarily related to the company to sell these securities. The better the rating, the 800 megawatts of peaking capacity as discussed in the lower the cost of the securities to each company when they "Capital Requirements of our Diversified Businesses" sell them. Constellation Energy and BGE's securities ratings section on page 37, and at the date of this report are:

"*BGE increased its construction expenditures by Standard Moody's Duff & Phelps'

$46.5 million.

& Poors Investors Credit

" In 1998, net cash used in investing activities increased Rating Group Service Rating Co.

compared to 1997 mostly because of the additional investments Constellation Energy in international power projects. This was partially offset by a Unsecured Debt A- A3 A

$33.8 million decrease in utility construction expenditures.

BGE Total utility construction expenditures, including the allowance Mortgage Bonds AA Al AA for funds used during construction, were $385.9 million in 1999 Unsecured Debt A A2 A+

as compared to $339.4 million in 1998 and $373.2 million Trust Originated in 1997.

Preferred Securities and Preference Stock A Constellation Energy Group Inc. and Subsidiaries I

I Capital Resources "*regulation, legislation, and competition, Our business requires a great deal of capital. Our actual "*BGE load requirements, consolidated capital requirements for the years 1997 through "*environmental protection standards, 1999, along with estimated annual amounts for the years 2000 "*the type and number of projects selected for development, through 2002, are shown in the table below. For the year "*the effect of market conditions on those projects, ended December 31, 1999, the ratio of earnings to fixed "*the cost and availability of capital, and charges for Constellation Energy was 2.87. "*the availability of cash from operations.

Investment requirements for 2000 through 2002 include Our estimates are also subject to additional factors. Please see estimates of funding for existing and anticipated projects. the "Forward Looking Statements" section on page 39.

We continuously review and modify those estimates. Actual No earlier than July 1, 2000, and upon receipt of all regulatory investment requirements may vary from the estimates included approvals, all of BGE's generation assets will be transferred to in the table below because of a number of factors including: nonregulated subsidiaries of Constellation Energy. The discus sion and table for capital requirements below include these generation assets as part of the utility business.

1997 1998 1999 2000 2001 2002 (In millions)

Utility Business Capital Requirements:

Construction expenditures (excluding AFC)

Electric $ 238 $ 239 $ 283 $ 329 $ 332 $ 312 Gas 89 55 59 63 61 61 Common 38 35 34 25 23 23 Total construction expenditures 365 329 376 417 416 396 AFC 8 10 10 4 4 4 Nuclear fuel (uranium purchases and processing charges) 44 50 49 50 48 48 Deferred conservation expenditures 27 16 1 Retirement of long-term debt and redemption of preference stock 243 222 342 401 281 151 Total utility business capital requirements 687 627 778 872 749 599 Diversified Business Capital Requirements:

Investment requirements 156 325 278 764 1,001 755 Retirement of long-term debt 188 232 189 284 367 2 Total diversified business capital requirements 344 557 467 1,048 1,368 757 Total capital requirements $1,031 $1,184 $1,245 $1,920 $2,117 $1,356 Capital Requirements of Our Utility Business beyond 2014 and 2016. We expect the steam generator replace Our estimates of future electric construction expenditures do ments to occur during the 2002 refueling outage for Unit 1 and not include costs to build more generating units to meet load during the 2003 refueling outage for Unit 2. We discuss the requirements for BGE customers. Electric construction expen license extension process further in the "Current Issues" section ditures include improvements to generating plants and to our on page 22. We estimate these Calvert Cliffs costs to be:

transmission and distribution facilities, and costs for replacing * $40 million in 2000, the steam generators and renewing the operating licenses at * $66 million in 2001, Calvert Cliffs. The operating licenses expire in 2014 for Unit 1 * $88 million in 2002, and and in 2016 for Unit 2. If we do not replace the steam genera * $60 million in 2003.

tors, we may not be able to operate the Calvert Cliffs units ConstellationEnergy Group Inc. and Subsidiaries

I kdditionally, our estimates of future electric construction Capital Requirements of Our Diversified Businesses

Maryland nitrogen oxides emissions (NOx) reduction "*growing its power marketing business, regulations as follows: "*developing and acquiring power projects, and

  • $63 million in 2000, "*constructing cooling system projects.
  • $52 million in 2001, and Our energy services businesses' investment requirements
  • $4 million in 2002. include the planned construction of 800 megawatts of peaking We discuss the NOx regulations and timing of expenses capacity in the Mid-Atlantic/Mid-West region by the summer further in Note 10 on page 69. of 2001 and an additional 4,300 megawatts of peaking and combined cycle production facilities scheduled for completion Our utility operations provided about 99% in 1999, 108% in in 2002 and beyond.

1998, and 105% in 1997 of the cash needed to meet its capital requirements, excluding cash needed to retire debt and redeem Our investment requirements also include our energy services preference stock. businesses' commitment to contribute up to an additional

$121 million in equity to Orion. To date, our energy services During the three years from 2000 through 2002, we expect businesses have funded $104 million in equity to Orion.

our existing utility business to provide about 115% of the cash needed to meet the capital requirements for these operations, Our energy services businesses have met their capital excluding cash needed to retire debt. The table for capital requirements in the past through borrowing, cash from requirements on page 36 includes the requirements for BGE their operations, and from time to time equity contributions fossil and nuclear generation under "Utility Business Capital from BGE.

Requirements-Electric" through 2002 even though these Future funding for the expansion of our energy services assets are to be transferred to nonregulated subsidiaries on businesses is expected from internally generated funds, or about July 1, 2000. commercial paper issuances and long-term debt financing We will continue to have cash requirements for: by Constellation Energy, and from time to time equity contributions from Constellation Energy. BGE Home Products

"*working capital needs including the payments of interest, & Services may also meet capital requirements through sales

"*'* distributions, and dividends, of receivables.

"*capital expenditures, and

"*the retirement of debt and redemption of preference stock. At December 31, 1999, Constellation Energy has a commercial paper program where it can issue up to $500 million in short When BGE cannot meet utility capital requirements internally, term notes to fund its diversified businesses. To support its BGE sells debt and preference stock. BGE also sells securities commercial paper program, Constellation Energy maintains when market conditions permit it to refinance existing debt or

$35 million in annual committed bank lines of credit and has preference stock at a lower cost. The amount of cash BGE a $135 million revolving credit agreement, under which it can needs and market conditions determine when and how much also issue letters of credit. In addition, Constellation Energy BGE sells.

has access to interim lines of credit as required from time to Future funding for capital expenditures, the retirement of time to support its outstanding commercial paper. ComfortLink debt, and payments of interest and dividends is expected has a revolving credit agreement totaling $50 million to from internally generated funds, commercial paper issuances, provide liquidity for short-term financial needs.

available capacity under credit facilities, and/or the issuance If we can get a reasonable value for our real estate projects, of long-term debt, trust securities, or preference stock.

additional cash may be obtained by selling them. Our ability At December 31, 1999, the Federal Energy Regulatory to sell or liquidate assets will depend on market conditions, Commission has authorized BGE to issue up to $700 million and we cannot give assurances that these sales or liquidations of short-term borrowings, including commercial paper. In could be made. We discuss the real estate business and market addition, BGE maintains $123 million in annual committed in the "Other Diversified Businesses" section on page 33.

bank lines of credit and has $60 million in bank revolving We discuss our short-term borrowings in Note 7 on page 65 credit agreements to support the commercial paper program as and long-term debt in Note 8 on page 65.

discussed in Note'7 on page 65. In addition, BGE has access to interim lines of credit as required from time to time to support its outstanding commercial paper.

ConstellationEnergy Group Inc. andSubsidiaries I

Market Risk We are exposed to market risk, including changes in interest Interest Rate Risk rates, certain commodity prices, equity prices, and foreign We are exposed to changes in interest rates as a result of currency. To manage our market risk, we may enter into various financing through our issuance of variable-rate and fixed-rate derivative instruments including swaps, forward contracts, debt. The following table provides information about our futures contracts, and options. Effective July 1, 2000, we will obligations that are sensitive to interest rate changes:

be subject to additional market risk associated with the purchase and sale of energy as discussed in the "Current Issues" section on page 21. In this section, we discuss our current market risk and the related use of derivative instruments.

Principal Payments and Interest Rate Detail by Contractual Maturity Date Fair value at 2000 2001 2002 2003 2004 Thereafter Total Dec. 31, 1999 (In millions)

Long-term debt Variable-rate debt $201.9 $166.0 $ 0.9 $ 7.8 $ 5.4 $ 272.8 $ 654.8 $ 654.8 Average interest rate 6.68% 6.39% 8.32% 7.42% 7.41% 4.80% 5.84%

Fixed-rate debt $484.4 $482.8 $154.6 $289.4 $154.6 $1,173.7 $2,739.5 $2,637.3 Average interest rate 7.16% 7.08% 7.31% 6.52% 5.78% 6.83% 6.87%

Commodity Price Risk These factors include:

We are exposed to the impact of market fluctuations in the

"*seasonal changes in the demand for electricity, price and transportation costs of natural gas, electricity, and "*hourly fluctuations in demand due to weather conditions, other trading commodities. Currently, our gas business and "*available generation resources, energy services businesses use derivative instruments to

"*transmission availability and reliability within and between >

manage changes in their respective commodity prices. regions, and

"*procedures used to maintain the integrity of the physical Gas Business electricity system during extreme conditions.

Our gas business may enter into gas futures, options, and swaps These factors can affect energy commodity and derivative to hedge its price risk under our market based rate incentive prices in different ways and to different degrees. These effects mechanism and our off-system gas sales program. We discuss may vary throughout the country and result from regional this further in Note 1 on page 51. At December 31, 1999 and differences in:

1998, our exposure to commodity price risk for our gas business was not material. "*weather conditions,

"*market liquidity,

"*capability and reliability of the physical electricity Energy Services Businesses system, and With respect to our energy services businesses, Constellation "*the nature and extent of electricity deregulation.

Power Source manages its commodity price risk inherent Constellation Power Source uses various methods, including in its power marketing activities on a portfolio basis, subject a value at risk model, to measure its exposure to market risk.

to established trading and risk management policies. Commodity Value at risk is a statistical model that attempts to predict risk price risk arises from the potential for changes in the value of of loss based on historical market price and volatility data.

energy commodities and related derivatives due to: changes in Constellation Power Source calculates value at risk using a commodity prices, volatility of commodity prices, and fluctua variance/covariance technique that models option positions tions in interest rates. A number of factors associated with the using a linear approximation of their value. Additionally, structure and operation of the electricity market significantly Constellation Power Source estimates variances and influence the level and volatility of prices for electricity and correlation using historical market movements over the related derivative products. most recent rolling three-month period.

ConstellationEnergy Group Inc. and Subsidiaries

I The value at risk amount represents the potential loss in the We discuss Constellation Power Source's business in the

,jair value of assets and liabilities from trading activities over "Power Marketing" section on page 31 and in Note 1 on a one-day holding period with a 99.6% confidence level. page 51.

Using this confidence level, Constellation Power Source The commodity price risk for our remaining energy services would expect a one-day change in fair value greater than businesses was not material at December 31, 1999 and 1998.

or equal to the daily value at risk at least once per year.

Constellation Power Source's value at risk was $7.2 million Equity Price Risk as of December 31, 1999 compared to $6.0 million as of We are exposed to price fluctuations in equity markets primarily December 31, 1998. The average, high, and low value at risk through our financial investments business and our nuclear for the year ended December 31, 1999 was $4.8 million, decommissioning trust fund. We are required by the NRC to

$7.2 million and $1.8 million, respectively.

maintain a trust to fund the costs of decommissioning Calvert Constellation Power Source's calculation includes all assets Cliffs. At December 31, 1999 and 1998, equity price risk was and liabilities from its power marketing and trading activities, not material. We discuss our nuclear decommissioning trust including energy commodities and derivatives that do not fund in more detail in Note 1 on page 53. We also describe require cash settlements. We believe that this represents a our financial investments in more detail in Note 3 on page 57.

more complete calculation of our value at risk.

Due to the inherent limitations of statistical measures such Foreign Currency Risk as value at risk, the relative immaturity of the competitive We are exposed to foreign currency risk primarily through market for electricity and related derivatives, and the season our power projects business. Our power projects business has ality of changes in market prices, the value at risk calculation

$254.1 million invested in 10 international power generation may not reflect the full extent of our commodity price risk and distribution projects as of December 31, 1999. To manage exposure. Additionally, actual changes in the value of options our exposure to foreign currency risk, the majority of our may differ from the value at risk calculated using a linear contracts are denominated in or indexed to the U.S. dollar.

approximation inherent in our calculation method. As a result, At December 31, 1999 and 1998, foreign currency risk was actual changes in the fair value of assets and liabilities from not material. We discuss our international projects in the 9ower marketing and trading activities could differ from the "Power Projects" section on page 32.

,%..--calculated value at risk and such changes could have a material impact on our financial results. Please refer to the "Forward Looking Statements" section below.

( Forward Looking Statements We make statements in this report that are considered forward "*commodity price risk, looking statements within the meaning of the Securities "*operating our currently regulated generating assets in a Exchange Act of 1934. Sometimes these statements will deregulated market beginning July 1, 2000 without the contain words such as "believes," "expects," "intends," benefit of a fuel rate adjustment clause, "plans," and other similar words. These statements are not "*loss of revenues due to customers choosing alternative guarantees of our future performance and are subject to risks, suppliers, uncertainties, and other important factors that could cause our "*higher volatility of earnings and cash flows, and actual performance or achievements to be materially different "*increased financial requirements of our nonregulated from those we project. These risks, uncertainties, and factors subsidiaries.

include, but are not limited to:

Given these uncertainties, you should not place undue reliance

"*general economic, business, and regulatory conditions, on these forward looking statements. Please see the other

"*energy supply and demand, sections of this report and our other periodic reports filed

"*competition, with the SEC for more information on these factors. These

"*federal and state regulations, forward looking statements represent our estimates and

"*availability, terms, and use of capital, assumptions only as of the date of this report.

'

  • nuclear and environmental issues,

"*weather, I

implications of the Restructuring Order issued by the

""

Maryland PSC, ConstellationEnergy Group Inc. andSubsidiaries

S Report of Management The management of the Company is responsible for the The Audit Committee of the Board of Directors, which consists, information and representations in the Company's financial of four outside Directors, meets periodically with management, statements. The Company prepares the financial statements internal auditors, and PricewaterhouseCoopers LLP to review in accordance with generally accepted accounting principles the activities of each in discharging their responsibilities. The based upon available facts and circumstances and manage internal audit staff and PricewaterhouseCoopers LLP have ment's best estimates and judgments of known conditions. free access to the Audit Committee.

The Company maintains an accounting system and related system of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Company's assets are protected. The Company's staff of internal auditors, which reports directly to the Chairman of the Board, conducts periodic reviews to maintain Christian H. Poindexter David A. Brune the effectiveness of internal control procedures. Chairmanof the Board Chief FinancialOfficer PricewaterhouseCoopers LLP, independent accountants, and Chief Executive Officer audit the financial statements and express their opinion on them. They perform their audit in accordance with generally accepted auditing standards.

SReport of Independent Accountants To the Shareholdersof ConstellationEnergy Group, Inc.

In our opinion, the accompanying consolidated balance sheets obtain reasonable assurance about whether the financial state and the related consolidated statements of income, compre ments are free of material misstatement. An audit includes hensive income, cash flows, common shareholders' equity, examining, on a test basis, evidence supporting the amounts capitalization and income taxes present fairly, in all material and disclosures in the financial statements, assessing the respects, the financial position of Constellation Energy Group, accounting principles used and significant estimates made by Inc. and Subsidiaries at December 31, 1999 and 1998, and the management, and evaluating the overall financial statement results of their operations and their cash flows for each of the presentation. We believe that our audits provide a reasonable three years in the period ended December 31, 1999 in confor basis for the opinion expressed above.

mity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of these statements in accordance PricewaterhouseCoopers LLP with auditing standards generally accepted in the United Baltimore, Maryland States, which require that we plan and perform the audit to January 19, 2000 ConstellationEnergy Group Inc. and Subsidiaries

ConsoLidated Statements of Income )-I Year Ended December 31, 1999 1998 1997 (In millions, except per share amounts)

"ý'JRevenues Electric $2,258.8 $2,219.2 $2,191.7 Gas 476.5 449.4 521.6 Diversified businesses 1,050.9 689.5 594.3 Total revenues 3,786.2 3,358.1 3,307.6 Operating Expenses Electric fuel and purchased energy 467.7 505.7 519.7 Gas purchased for resale 230.6 208.6 292.1 Operations 546.0 554.1 518.3 Maintenance 186.2 177.5 178.5 Diversified businesses-selling, general, and administrative 918.7 574.6 515.7 Depreciation and amortization 449.8 377.1 342.9 Taxes other than income taxes 227.3 219.4 216.8 Total oneratinL exnenses 3,026.3 2,617.0 2,584.0 Income from Operations 759.9 741.1 723.6 Other Income (Expense)

Write-off of merger costs (see Note 2) - - (57.9)

Other 7.9 5.7 5.1 Total other income (expense) 7.9 5.7 (52.8)

Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8 Fixed Charges Interest expense (net) 241.5 240.9 230.0 BGE preference stock dividends 13.5 21.8 28.7 Total fixed charees 255.0 262.7 258.7 Income Before Income Taxes 512.8 484.1 412.1 Income Taxes 186.4 178.2 158.0 Income Before Extraordinary Item 326.4 305.9 254.1 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) (66.3) -

Net Income $ 260.1 $ 305.9 $ 254.1 Earnings Applicable to Common Stock $ 260.1 $ 305.9 $ 254.1 Average Shares of Common Stock Outstanding 149.6 148.5 147.7 Earnings Per Common Share and Earnings Per Common Share

-Assuming Dilution Before Extraordinary Item $ 2.18 $ 2.06 $ 1.72 Extraordinary Loss (.44)

Earnings Per Common Share and Earnings Per Common Share

-- Assuming Dilution $ 1.74 $ 2.06 $ 1.72 (Consolidated Statements of Comprehensive Income)

Year EndedDecember 31, 1999 1998 1997 (In millions)

Net Income $ 260.1 $ 305.9 $ 254.1 Other comprehensive income/(loss), net of taxes (6.2) 1.2 (0.8)

Comprehensive Income $ 253.9 $ 307.1 $ 253.3

"--'SeeNotes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the currentyear's presentation.

ConstellationEnergy Group Inc. and Subsidiaries

I Consolidated Balance Sheets At December 31. 1999 1998 1999 (In millions)

Assets Current Assets Cash and cash equivalents $ 92.7 $ 173.7 Accounts receivable (net of allowance for uncollectibles of $34.8 and $35.4 respectively) 578.5 422.7 Trading securities 136.5 119.7 Assets from energy trading activities 312.1 133.0 Fuel stocks 94.9 85.4 Materials and supplies 149.1 145.1 Prepaid taxes other than income taxes 72.4 68.8 Other 54.0 21.4 Total current assets 1,490.2 1,169.8 Investments and Other Assets Real estate projects and investments 310.1 353.9 Power projects 785.4 743.1 Financial investments 145.4 198.0 Nuclear decommissioning trust fund 217.9 181.4 Net pension asset 99.5 108.0 Other 422.9 243.3 Total investments and other assets 1,981.2 1,827.7 Utility Plant Plant in service Electric 7,088.6 6,890.3 Gas 962.0 921.3 Common 569.5 552.8 Total plant in service 8,620.1 8,364.4 Accumulated depreciation (3,466.1) (3,087.5)

Net plant in service 5,154.0 5,276.9 Construction work in progress 222.3 223.0 Nuclear fuel (net of amortization) 133.8 132.5 Plant held for future use 13.0 24.3 Net utility plant 5,523.1 5,656.7 Deferred Charges Regulatory assets (net) 637.4 565.7 Other 51.9 55.1 Total deferred charges 689.3 620.8 Total Assets $9,683.8 $9,275.0 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the current year'spresentation.

Constellation Energy Group Inc. and Subsidiaries

( Consolidated BaLance Sheets 4t December 31. 1999 1998 (In millions)

Liabilities and Capitalization Current Liabilities Short-term borrowings $ 371.5 $

Current portions of long-term debt and preference stock 808.3 541.7 Accounts payable 365.1 270.5.

Customer deposits 40.6 35.5 Liabilities from energy trading activities 163.8 99.0 Dividends declared 66.1 66.1 Accrued taxes 19.2 6.5 Accrued interest 55.3 58.6 Accrued vacation costs 35.3 34.7 Other 78.2 45.3 Total current liabilities 2,003.4 1,157.9 Deferred Credits and Other Liabilities Deferred income taxes 1,288.8 1,309.1 Postretirement and postemployment benefits 269.8 217.0 Deferred investment tax credits 109.6 118.0 Decommissioning of federal uranium enrichment facilities 27.2 30.8 Other 226.6 142.6 Total deferred credits and other liabilities 1,922.0 1,817.5 Capitalization Long-term debt 2,575.4 3,128.1 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' eauitv 2,993.0 2,981.5 Total capitalization 5,758.4 6,299.6 Commitments, Guarantees, and Contingencies (see Note 10)

Total Liabilities and Capitalization $9,683.8 $9,275.0 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the current year'spresentation.

ConstellationEnergy Group Inc. and Subsidiaries I

F ( Consolidated Statements of Cash FLows Year Ended December31, 1999 1998 1997 (In millions)

Cash Flows From Operating Activities Net income $ 260.1 $ 305.9 $ 254.1 Adjustments to reconcile to net cash provided by operating activities Extraordinary loss 66.3 -

Depreciation and amortization 505.9 429.4 396.8 Deferred income taxes 13.0 17.5 7.4 Investment tax credit adjustments (8.6) (8.8) (7.5)

Deferred fuel costs (61.1) (8.3) 18.3 Accrued pension and postemployment benefits 36.1 41.6 (18.0)

Write-off of merger costs - - 57.9 Write-downs of real estate investments 8.3 23.7 70.8 Write-down of financial investment 26.2 -

Write-downs of power projects 28.5 -

Equity in earnings of affiliates and joint ventures (net) (7.6) (54.5) (42.5)

Changes in assets from energy trading activities (179.1) (123.6) (9.4)

Changes in liabilities from energy trading activities 64.8 90.4 8.6 Changes in other current assets (216.4) 18.3 (54.7)

Changes in other current liabilities 121.0 77.0 42.6 Other 21.6 (8.8) (28.1)

Net cash provided by operating activities 679.0 799.8 696.3 Cash Flows From Investing Activities Utility construction and other capital expenditures (436.2) (406.1) (443.9)

Contributions to nuclear decommissioning trust fund (17.6) (17.6) (17.6)

Merger costs - (20.9)

Purchases of marketable equity securities (27.3) (33.3) (23.0)

Sales of marketable equity securities 34.9 32.8 46.5 Other financial investments 13.7 14.6 (0.4)

Real estate projects and investments 49.3 21.5 24.2 Power projects (171.1) (252.5) (44.3)

Other (60.8) (70.7) (41.4)

Net cash used in investing activities (615.1) (711.3) (520.8)

Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 2,801.9 1,962.2 2,719.0 Long-term debt 302.8 831.3 622.0 Common stock 9.6 51.8 Repayment of short-term borrowings (2,430.4) (2,278.3) (2,736.1)

Reacquisition of long-term debt (584.4) (355.2) (343.3)

Redemption of preference stock (7.0) (127.9) (104.5)

Common stock dividends paid (251.1) (246.0) (239.2)

Other 13.7 84.7 2.5 Net cash used in financing activities (144.9) (77.4) (79.6)

Net (Decrease) Increase in Cash and Cash Equivalents (81.0) 11.1 95.9 Cash and Cash Equivalents at Beginning of Year 173.7 162.6 66.7 Cash and Cash Equivalents at End of Year $ 92.7 $ 173.7 $ 162.6 Other Cash Flow Information Cash paid during the year for:

Interest (net of amounts capitalized) $ 245.3 $ 236.7 $ 224.2 Income taxes $165.6 $ 164.3 $ 171.2 Noncash Investing and Financing Activities:

In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62 million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0 million common shares and 985,000 convertible preferred shares. In exchange, COPT received 14 operating properties and two properties under development from CREG.

See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the current year's presentation.

ConstellationEnergy Group Inc. and Subsidiaries

SConsoLidated Statements of Common Shareholders' Equity Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 1999, 1998, and 1997 Shares Amount Earnings (Loss) Income Amount (Dollaramounts in millions, number of shares in thousands)

Balance at December 31, 1996 147,667 $1,429.9 $1,419.1 $5.7 $2,854.7 Net income 254.1 254.1 Common stock dividends declared ($1.63 per share) (240.7) (240.7)

Other 3.1 3.1 Net unrealized loss on securities (1.2) (1.2)

Deferred taxes on net unrealized loss on securities 0.4 0.4 Balance at December 31, 1997 147,667 1,433.0 1,432.5 4.9 2,870.4 Net income 305.9 305.9 Common stock dividend declared ($1.67 per share) (248.1) (248.1)

Common stock issued 1,579 51.8 51.8 Other 0.3 0.3 Net unrealized gain on securities 1.8 1.8 Deferred taxes on net unrealized gain on securities (0.6) (0.6)

Balance at December 31, 1998 149,246 1,485.1 1,490.3 6.1 2,981.5 Net income 260.1 260.1 Common stock dividend declared ($1.68 per share) (251.3) (251.3)

ýommon stock issued 310 9.6 9.6

"----Other (0.7) (0.7)

Net unrealized loss on securities (9.6) (9.6)

Deferred taxes on net unrealized loss on securities 3.4 3.4 Balance at December 31, 1999 149,556 $1,494.0 $1,499.1 $(0.1) $2,993.0 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the current year'spresentation.

ConstellationEnergy Group Inc. and Subsidiaries

Consolidated Statements of Capitalization At December 31, 1999 1998 (In millions)

Long-Term Debt First Refunding Mortgage Bonds of BGE Floating rate series, due April 15, 1999 $ - $ 125.0 8.40% Series, due October 15, 1999 - 91.1 5X% Series, due July 15, 2000 124.3 125.0 83A% Series, due August 15, 2001 122.3 122.3 7Y4% Series, due July 1, 2002 124.5 124.5 5%% Installment Series, due July 15, 2002 8.5 9.1 6X% Series, due February 15, 2003 124.8 124.8 6%% Series, due July 1, 2003 124.9 124.9 5!% Series, due April 15, 2004 125.0 125.0 Remarketed floating rate series, due September 1, 2006 125.0 125.0 7A% Series, due January 15, 2007 123.5 123.5 6%% Series, due March 15, 2008 124.9 124.9 7X% Series, due March 1, 2023 109.9 125.0 7X% Series, due April 15, 2023 84.1 84.1 Total First Refunding Mortgage Bonds of BGE 1,321.7 1,554.2 Other long-term debt of BGE Medium-term notes, Series B 60.0 60.0 Medium-term notes, Series C 101.0 116.0 Medium-term notes, Series D 128.0 215.0 Medium-term notes, Series E 200.0 200.0 Medium-term notes, Series G 200.0 140.0 Medium-term notes, Series H 177.0 Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Variable rate pollution control loan, due June 1, 2027 8.8 8.8 Total other long-term debt of BGE 1,135.8 1,000.8 BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0 Long-term debt of diversified businesses Loans under revolving credit agreements 33.0 74.0 Mortgage and construction loans 7.90% mortgage note, due September 12, 2000 8.0 8.3 8.00% mortgage note, due July 31, 2001 0.1 0.1 8.00% mortgage note, due October 30, 2003 1.9 1.8 Variable rate mortgage notes and construction loans, due through 2004 112.0 149.5 4.25% mortgage note, due March 15, 2009 4.6 5.1 9.65% mortgage note, due February 1, 2028 9.6 9.6 8.00% mortgage note, due November 1, 2033 6.6 5.8 Unsecured notes 511.0 616.0 Total long-term debt of diversified businesses 686.8 870.2 Unamortized discount and premium (10.6) (12.4)

Current portion of long-term debt (808.3) (534.7)

Total long-term debt $2,575.4 $3,128.1 continuedon page 4 See Notes to ConsolidatedFinancialStatements.

Constellation Energy Group Inc. and Subsidiaries

Consolidated Statements of Capitalization 4t December 31, 1999 1998 (In millions)

BGE Preference Stock Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.85%, 1991 Series $ - $ 7.0 Current portion of redeemable preference stock - (7.0)

Total redeemable preference stock -

Preference stock not subject to mandatory redemption 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 Total preference stock not subject to mandatory redemption 190.0 190.0 Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 149,556,416 and 149,245,641 shares issued and outstanding at December 31, 1999 and 1998, respectively. (At December 31, 1999 166,893 shares were reserved for the Employee Savings Plan and 12,061,756 shares were reserved for the Shareholder Investment Plan.) 1,494.0 1,485.1 Retained earnings 1,499.1 1,490.3 Accumulated other comprehensive (loss) income (0.1) 6.1 Total common shareholders' equity 2,993.0 2,981.5 Total Capitalization $5.758.4 $6.299.6

$6299.6 See Notes to ConsolidatedFinancialStatements.

ConstellationEnergy Group Inc. andSubsidiaries

FQ Consolidated Statements of Income Taxes )

Year Ended December31, 1999 1998 1997 (Dollaramounts in millions)

Income Taxes Current $182.0 $169.5 $158.1 Deferred Change in tax effect of temporary differences 9.6 14.2 (1.0)

Change in income taxes recoverable through future rates - 3.9 8.0 Deferred taxes credited (charged) to shareholders' equity 3.4 (0.6) 0.4 Deferred taxes charged to expense 13.0 17.5 7.4 Investment tax credit adjustments (8.6) (8.8) (7.5)

Income taxes per Consolidated Statements of Income $186.4 $178.2 $158.0 Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends) $526.3 $505.9 $440.8 Statutory federal income tax rate 35% 35% 35%

Income taxes computed at statutory federal rate 184.2 177.1 154.3 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 15.3 13.6 13.9 Allowance for equity funds used during construction (2.2) (2.2) (1.9)

Amortization of deferred investment tax credits (8.6) (8.8) (7.5)

Tax credits flowed through to income (3.2) (0.3) (0.5)

Amortization of deferred tax rate differential on regulated activities (3.0) (2.3) (2.3)

State income taxes 8.9 9.8 6.2 Other (5.0) (8.7) (4.2)

Total income taxes $186.4 $178.2 $158.0 Effective federal income tax rate 35.4% 35.2% 35.8%

At December31, 1999 1998 (Dollaramounts in millions)

Deferred Income Taxes Deferred tax liabilities Accelerated depreciation $ 962.7 $1,009.9 Allowance for funds used during construction 202.3 204.5 Income taxes recoverable through future rates 35.7 88.4 Deferred termination and postemployment costs 14.7 32.3 Deferred fuel costs 25.8 4.5 Leveraged leases 19.9 22.6 Percentage repair allowance 35.0 36.8 Conservation expenditures 4.7 18.9 Energy trading activities 71.4 33.4 Deferred electric generation-related regulatory assets 100.3 Other 187.9 182.6 Total deferred tax liabilities 1,660.4 1,633.9 Deferred tax assets Accrued pension and postemployment benefit costs 63.6 54.3 Deferred investment tax credits 38.3 41.3 Capitalized interest and overhead 48.3 46.6 Contributions in aid of construction 49.1 45.6 Nuclear decommissioning liability 25.4 22.8 Energy trading activities 15.1 20.3 Other 131.8 93.9 Total deferred tax assets 371.6 324.8 Deferred tax liability, net $1,288.8 $1,309.1 See Notes to ConsolidatedFinancialStatements.

Certainprior-yearamounts have been reclassifiedto conform with the current year's presentation.

ConstellationEnergy Group Inc. and Subsidiaries

Notes to Consolidated Financial Statements I

~Note 1. The only time we do not use this method is if we can exercise

,-- control over the operations and policies of the company. If we 4ignificant Accounting Policies have control, accounting rules require us to use consolidation.

Nature of Our Business BGE reports its investment in Safe Harbor Water Power On April 30, 1999, Constellation Energy Group, Inc. Corporation (Safe Harbor) under the equity method. Safe (Constellation Energy) became the holding company for Harbor is a producer of hydroelectric power. BGE owns Baltimore Gas and Electric Company (BGE) and BGE's two-thirds of Safe Harbor's total capital stock, including former subsidiary Constellation Enterprises, Inc. BGE's one-half of the voting stock, and a two-thirds interest in its outstanding common stock automatically became shares of retained earnings. This investment is included in "Investments common stock of Constellation Energy. BGE's debt securities, and Other Assets - Other" in our Consolidated Balance Sheets obligated mandatorily redeemable trust preferred securities, on page 42.

and preference stock remain securities of BGE.

Constellation Energy's subsidiaries primarily include BGE The Cost Method We usually use the cost method if we hold less than a 20%

and a group of energy services businesses mostly focused on voting interest in an investment. Under the cost method, we power marketing and merchant generation in North America.

report our investment at cost in our Consolidated Balance BGE is an electric and gas public utility company with a Sheets. The only time we do not use this method is when we service territory that covers the City of Baltimore and all can exercise significant influence over the operations and or part of ten counties in Central Maryland. We describe policies of the company. If we have significant influence, our operating segments in Note 2 on page 54. accounting rules require us to use the equity method.

References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. Regulation of Utility Business Reference in this report to the "utility business" is to BGE. The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the "onsolidation Policy

,-,,_Ve use three different accounting methods to report our same accounting policies and practices used by nonregulated investments in our subsidiaries or other companies: companies for financial reporting under generally accepted consolidation, the equity method, and the cost method. accounting principles. However, sometimes the Maryland PSC orders an accounting treatment different from that used by Consolidation nonregulated companies to determine the rates we charge our We use consolidation when we own a majority of the voting customers. When this happens, we must defer certain utility stock of the subsidiary. This means the accounts of our expenses and income in our Consolidated Balance Sheets as subsidiaries are combined with our accounts. We eliminate regulatory assets and liabilities. We have recorded these regula intercompany balances and transactions when we consolidate tory assets and liabilities in our Consolidated Balance Sheets in these accounts. Our consolidated financial statements include accordance with Statement of Financial Accounting Standards the accounts of: (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. We summarize and discuss our regulatory assets

"*Constellation Energy, and liabilities further in Note 5 on page 60.

"*BGE and its subsidiaries,

"*Constellation Enterprises, Inc. and its subsidiaries, and In 1997, the Financial Accounting Standards Board (FASB)

"*Constellation Nuclear Group, LLC and its subsidiaries. through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulationof the Pricing of Electricity-Issues The Equity Method Related to the Application of FASB Statements No. 71 and We usually use the equity method to report investments, 101. The EITF concluded that a company should cease to corporate joint ventures, partnerships, and affiliated companies apply SFAS No. 71 when either legislation is passed or a (including power projects) where we hold a 20% to 50% regulatory body issues an order that contains sufficient detail voting interest. Under the equity method, we report: to determine how the transition plan will affect the deregu lated portion of the business. Additionally, a company would our interest in the entity as an investment in our continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets beginning on page 42, and Consolidated Balance Sheets to the extent that the transition our percenitage share of the earnings from the entity in plan provides for their recovery.

our Consolidated Statements of Income on page 41.

ConstellationEnergy Group Inc. and Subsidiaries I

r On November 10, 1999, the Maryland PSC issued a We calculate the electric fuel rate using three factors:

Restructuring Order that we believe provided sufficient details "*the mix of generating plants we used over the last of the transition plan to competition for BGE's electric generation 24 months, business to require BGE to discontinue the application of "*the latest three-month average fuel cost for each SFAS No. 71 for that portion of its business. Accordingly, generating unit, and in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises- Accounting for the "*the net cost of purchases and sales of electricity over the Discontinuationof FASB Statement No. 71 and EITF No. 97-4 last 24 months.

for BGE's electric generation business. BGE's transmission Historically, we were able to change the fuel rate only if the and distribution business continues to meet the requirements calculated rate was more than 5% above or below the rate in of SFAS No. 71 as that business remains regulated. We effect. The fuel rate was affected most by the amount of discuss this further in Note 4 on page 58. electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than Utility Revenues coal, gas, or oil. As a result of the Restructuring Order, the fuel We record utility revenues in our Consolidated Statements of rate is frozen at its current level until July 1, 2000, at which Income when we provide service to customers. time it will be discontinued. We will continue to defer the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate through Fuel and Purchased Energy Costs June 30, 2000. After that date, earnings will be affected by We incur costs for: the changes in the cost of fuel and energy. In addition, any

"*the fuel we use to generate electricity, accumulated difference between our actual costs of fuel and

"*purchases of electricity from others, and energy and the amounts collected from customers under the

"*natural gas that we resell. electric fuel rate clause will be collected from our customers These costs are shown in our Consolidated Statements of Income over a period to be determined by the Maryland PSC.

as "Electric fuel and purchased energy" and "Gas purchased for Extended outages at Calvert Cliffs increase fuel costs.

resale." We discuss each of these separately below. Any increase in fuel costs, including extended outages at Fuel Used to Generate Electricity and Purchases Calvert Cliffs through June 30, 2000, may result in fuel rat,,,

of ElectricityFrom Others proceedings before the Maryland PSC. In these proceedings, Until July 1, 2000, we will continue to recover our costs of the Maryland PSC would consider whether any portion of electric fuel under the electric fuel rate clause set the extra fuel costs should be paid by BGE instead of by the Maryland PSC. Under the electric fuel rate clause, we passed on to customers.

charge our electric customers for: We also report two other items as "Electric fuel and purchased

"*the fuel we use to generate electricity (nuclear fuel, coal, energy" in our Consolidated Statements of Income:

gas, or oil), and "*amortization of nuclear fuel (described under "Utility Plant"

"*the net cost of purchases and sales of electricity. later in this note). We amortize nuclear fuel based on the energy produced over the life of the fuel. We pay quarterly We charge the actual costs of these items to customers with no fees to the Department of Energy for the future disposal of profit to us. To do this, we must keep track of what we spend spent nuclear fuel, and accrue these fees based on the and what we collect from customers under the fuel rate in a kilowatt-hours of electricity sold. We bill our customers given period. Usually these two amounts are not the same for nuclear fuel as described earlier in this note, and because there is a difference between the time we spend the money and the time we collect it from our customers. "*amortization of deferred costs of decommissioning and decontaminating the Department of Energy's uranium Under the electric fuel rate clause, we currently defer (include enrichment facilities. We discuss these costs further in as an asset or liability in our Consolidated Balance Sheets and Note 5 on page 61.

exclude from our Consolidated Statements of Income) the differ ence between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future.

We discuss this and the impact of the Restructuring Order on BGE's electric fuel rate clause further in Note 5 on page 61.

ConstellationEnergy Group Inc. and Subsidiaries

I NaturalGas DiversifiedBusinesses

,Ve charge our gas customers for the natural gas they purchase Our subsidiary, Constellation Power Source, engages in

"--from us using "gas cost adjustment clauses" set by the power marketing activities, which include trading electricity, Maryland PSC. These clauses operate similarly to the electric other energy commodities, and related derivatives (such as fuel rate clause described earlier in this Note. However, the futures, forwards, options, and swaps). Constellation Power Maryland PSC approved a modification of the gas cost Source uses the mark-to-market method of accounting for adjustment clauses to provide a market based rates incentive its trading activities.

mechanism. Under market based rates our actual cost of gas is compared to a market index (a measure of the market Under the mark-to-market method of accounting, we report:

price of gas in a given period). The difference between our "*commodity positions and derivatives at fair value as actual cost and the market index is shared equally between "Assets from energy trading activities" or "Liabilities shareholders and customers. from energy trading activities" in our Consolidated Balance Sheets, and Risk Management "*changes in fair value as components of "Diversified We engage in risk management activities in our gas business business revenues" in our Consolidated Statements and in our diversified businesses. We separately describe these of Income.

activities for each business below.

Taxes Gas Business We summarize our income taxes in our Consolidated We use basis swaps in the winter months (November through Statements of Income Taxes on page 48. As you read this March) to hedge our price risk associated with natural gas section, it may be helpful to refer to those statements.

purchases under our market based rates incentive mechanism.

We also use fixed-to-floating and floating-to-fixed swaps to Income Tax Expense hedge our price risk associated with our off-system gas sales. We have two categories of income taxes in our Consolidated The fixed portion represents a specific dollar amount that Statements of Income-current and deferred. We describe we will pay or receive and the floating portion represents a each of these below.

luctuating amount based on a published index that we will

"ýrýeceive or pay. Our gas business internal guidelines do not Our current income tax expense consists solely of regular permit the use of swap agreements for any purpose other than tax less applicable tax credits.

to hedge price risk. Our deferred income tax expense is equal to the changes BGE's off-system gas activities represent trading activities in the net deferred income tax liability, excluding amounts under EITF 98-10, Accounting for ContractsInvolved in charged or credited to common shareholders' equity. Our Energy Trading and Risk ManagementActivities. Accordingly, deferred income tax expense is increased or reduced for we use mark-to-market accounting to record these transactions. changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this Note)

We defer, as unrealized gains or losses, the changes in fair during the year.

value of the swap agreements under the market based rates incentive mechanism and the customers' portion of off-system Investment Tax Credits gas sales in our Consolidated Balance Sheets. When amounts We have deferred the investment tax credit associated with are paid under the agreements, we report the payments as gas our regulated utility business in our Consolidated Balance costs in our Consolidated Statements of Income. We report Sheets. The investment tax credit is amortized evenly to the changes in fair value for the shareholders' portion of off income over the life of each property. We reduce income system gas sales in earnings as a component of gas costs. tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated diversified businesses, other than leveraged leases.

Constellation Energy Group Inc. and Subsidiaries I

F DeferredIncome Tax Assets and Liabilities Financial Investments and Trading Securities We must report some of our revenues and expenses differently In Note 3 on page 57, we summarize the financial investment for our financial statements than we do for income tax purposes. that are in our Consolidated Balance Sheets.

The tax effects of the differences in these items are reported SFAS No. 115, Accounting for Certain Investments in Debt as deferred income tax assets or liabilities in our Consolidated and Equity Securities, applies particular requirements to Balance Sheets. We measure the assets and liabilities using some of our investments in debt and equity securities. We income tax rates that are currently in effect.

report those investments at fair value, and we use specific A portion of our total deferred income tax liability relates to identification to determine their cost for computing realized our utility business, but has not been reflected in the rates we gains or losses. We classify these investments as either charge our customers. We refer to this portion of the liability trading securities or available-for-sale securities, which as "Income taxes recoverable through future rates (net)." We we describe separately below. We report investments that have recorded that portion of the net liability as a regulatory are not covered by SFAS No. 115 at their cost.

asset in our Consolidated Balance Sheets. We discuss this further in Note 5 on page 60. Trading Securities Our diversified businesses classify some of their investments in marketable equity securities and financial limited partner State and Local Taxes ships as trading securities. We include any unrealized gains Through December 31, 1999, we paid Maryland public service company franchise tax instead of state income tax or losses on these securities in "Diversified business revenues" in our Consolidated Statements of Income.

on our utility revenue from sales in Maryland. We include the franchise tax in "Taxes other than income taxes" in our Available-for-Sale Securities Consolidated Statements of Income.

We classify our investments in the nuclear decommissioning As discussed in Note 4 on page 58, the tax legislation made trust fund as available-for-sale securities. We include any comprehensive changes to the state and local taxation of electric unrealized gains or losses on the trust assets as a change and gas utilities. in the decommissioning reserve. We describe the nuclear decommissioning trust and the reserve under the heading Inventory "Decommissioning Costs" later in this note on page 53.

We report the majority of our fuel stocks and materials and In addition, our diversified businesses classify some of their supplies at average cost.

investments in marketable equity securities as available-for sale securities. We include any unrealized gains or losses Real Estate Projects and Investments on these securities in "Accumulated other comprehensive In Note 3 on page 56, we summarize the real estate projects (loss) income" in our Consolidated Statements of Common and investments that are in our Consolidated Balance Sheets. Shareholders' Equity on page 45 and in the Consolidated The projects and investments consist of: Statements of Capitalization on page 47. We also include

"*land under development in the Baltimore-Washington our diversified businesses' portion of unrealized gains or corridor, losses on securities of equity-method (described earlier in

"*a mixed-use planned-unit development, and this note) investees in our Consolidated Statements of Common Shareholders' Equity.

"*an equity interest in Corporate Office Properties Trust, a real estate investment trust.

Evaluation of Assets for Impairment The costs incurred to acquire and develop properties are SFAS No. 121, Accounting for the Impairment ofLong-Lived included as part of the cost of the properties. Assets andfor Long-Lived Assets to Be Disposed Of, applies particular requirements to some of our assets that have long lives (some examples are utility property and equipment and real estate). We determine if those assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount in our accounting records. We recog nize an impairment loss if the undiscounted expected future cash flows are less than the carrying amount of the asset.

See Note 4 on page 59 for further discussion.

ConstellationEnergy Group Inc. and Subsidiaries

I

'Itility Plant, Depreciation, Amortization, expense based on a facility-specific cost estimate so we

)id Decommissioning can accumulate a decommissioning reserve of $521 million

"ý4JtilityPlant in 1993 dollars by the end of Calvert Cliffs' service life Utility plant is the term we use to describe our utility business in 2016, adjusted to reflect expected inflation. We have property and equipment that is in use, being held for future reported the decommissioning reserve in "Accumulated use, or under construction. We summarize utility plant in our depreciation" in our Consolidated Balance Sheets. The Consolidated Balance Sheets. We report our utility plant at total reserve was $287.5 million at December 31, 1999 its original cost, unless impaired under the provisions of and $244.0 million at December 31, 1998.

SFAS No. 121. Our original cost includes:

To fund the costs we expect to incur to decommission the

"*material and labor, plant, we established an external decommissioning trust in

"*contractor costs, accordance with Nuclear Regulatory Commission (NRC)

"*construction overhead costs (where applicable), and regulations. We report the assets in the trust in "Nuclear

"*an allowance for funds used during construction (described decommissioning trust fund" in our Consolidated Balance later in this note). Sheets. The NRC requires utilities to provide financial assur ance that they will accumulate sufficient funds to pay for the We charge retired or otherwise-disposed-of utility plant to cost of nuclear decommissioning based upon either a generic accumulated depreciation. NRC formula or a facility-specific decommissioning cost We own an undivided interest in the Keystone and Conemaugh estimate. We use the facility-specific cost estimate for funding electric generating plants in Western Pennsylvania, as well as these costs and providing the required financial assurance.

in the transmission line that transports the plants' output to the joint owners' service territories. Our ownership interests Allowance for Funds Used During Construction and in these plants are 20.99% in Keystone and 10.56% in Capitalized Interest Conemaugh. These ownership interests represented a net Allowance for Funds Used During Construction(AFC) investment of $156 million at December 31, 1999 and We finance utility construction projects with borrowed funds

$152 million at December 31, 1998. We report these and equity funds. We are allowed by the Maryland PSC to roperties in the same accounts we use for our other record the costs of these funds as part of the cost of construc

_._,tility plant (described above). tion projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized DepreciationExpense by the Maryland PSC. We bill our customers for the AFC Generally, we compute depreciation by applying composite, plus a return after the utility plant is placed in service.

straight-line rates (approved by the Maryland PSC) to the average investment in classes of depreciable property. We The AFC rates are 9.04% for gas plant, 9.35% for common depreciate vehicles based on their estimated useful lives. plant, and 9.40% for electric plant. We compound AFC annually.

Amortization Expense Amortization is an accounting process of reducing an amount CapitalizedInterest in our Consolidated Balance Sheets evenly over a period of With the issuance of the Restructuring Order, we ceased time. When we reduce amounts in our Consolidated Balance accruing AFC for electric generation-related construction Sheets, we increase amortization expense in our Consolidated projects and began using SFAS No. 34, Capitalizing Statements of Income. An amount is considered fully Interest Costs, to calculate the cost during construction of amortized when it has been reduced to zero. debt funds used to finance our electric generation-related construction projects.

DecommissioningCosts Our diversified businesses capitalize interest costs incurred We must accumulate a reserve for the costs that we expect to to finance real estate developed for internal use and certain incur in the future to decommission the radioactive portion of power projects.

Calvert Cliffs. We do this based on a sinking fund methodology.

The Maryland PSC authorized us to record decommissioning ConstellationEnergy Group Inc. and Subsidiaries

r Long-Term Debt "*our disclosure of contingent assets and liabilities at the We defer (include as an asset or liability in our Consolidated dates of the financial statements, and Balance Sheets and exclude from our Consolidated Statements "*our reported amounts of revenues and expenses in of Income) all costs related to the issuance of long-term debt. our Consolidated Statements of Income during the These costs include underwriters' commissions, discounts or reporting periods.

premiums, and other costs such as legal, accounting, and These estimates involve judgments with respect to, among regulatory fees, and printing costs. We amortize these costs other things, future economic factors that are difficult to over the life of the debt. predict and are beyond management's control. As a result, When we incur gains or losses on debt that we retire prior to actual amounts could differ from these estimates.

maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt. Reclassifications We have reclassified certain prior-year amounts for comparative Cash Flows purposes. These reclassifications did not affect consolidated For the purpose of reporting our cash flows, we define cash net income for the years presented.

equivalents as highly liquid investments that mature in three months or less. Accounting Standards Issued In July 1999, the FASB issued SFAS No. 137 that delays the Use of Accounting Estimates effective date for SFAS No. 133, Accounting for Derivative Management makes estimates and assumptions when Instruments and Hedging Activities, by one year. Therefore, preparing financial statements under generally accepted we must adopt the provisions of SFAS No. 133 in our accounting principles. These estimates and assumptions affect financial statements for the quarter ended March 31, 2001.

various matters, including: We have not determined the effects of SFAS No. 133 on our reported amounts of assets and liabilities in our our financial results.

Consolidated Balance Sheets at the dates of the financial statements, (Note 2.

Information by Operating Segment.

We have three reportable operating segments-Electric, Gas, Our remaining diversified businesses:

and Energy Services: "*engage in financial investments, and

"*Our Electric business generates, purchases, and sells "*develop, own, and manage real estate and senior-living electricity, facilities.

"*Our Gas business purchases, transports, and sells natural These reportable segments are strategic businesses based gas, and principally upon regulations, products, and services that

"*Our Energy Services businesses consist of certain require different technology and marketing strategies.

diversified businesses that: The segments have the same accounting policies as those

- develop, own, and operate power projects, described in the summary of significant accounting policies

- provide power marketing and risk management services, in Note 1. The Company evaluates the performance of these

- provide nuclear consulting services, segments based on net income. We account for intersegment revenues using market prices. A summary of information by

- sell natural gas through mass marketing efforts, operating segment is shown on page 55.

- sell and service electric and gas appliances, heating We are realigning our organization combining all of our and air conditioning systems, and engage in home domestic merchant energy businesses. We have not determined improvements, and the impact of this reorganization on our operating segments, but

- provide cooling services to commercial customers such changes will impact our operating segments in the future in Baltimore.

I Constellation Energy Group Inc. and Subsidiaries

I Energy Other Unallocated Electric Gas Services Diversified Corporate "Business Business Businesses Businesses Items (a) Eliminations Consolidated (In millions) 1999 Unaffiliated revenues $2,258.8 $476.5 $ 937.0 $113.9 $3,786.2 Intersegment revenues 1.2 11.6 30.4 (0.4} (42.8')

Total revenues 2,260.0 488.1 967.4 113.5 - (42.8) 3,786.2 Depreciation and amortization 376.4 44.9 23.1 5.2 0.2 - 449.8 Equity in income of equity method investees (b) 5.1 - - - - 5.1 Net interest expense 162.4 24.4 24.6 31.1 0.4 (1.4) 241.5 Income tax expense (benefit) 149.2 18.1 34.8 (12.1) (0.9) (2.7) 186.4 Extraordinary loss 66.3 - -.. 66.3 Net income (loss) (c) 198.8 33.0 50.6 (19.3) (1.7) (1.3) 260.1 Segment assets 6,312.6 915.3 1,681.2 743.2 129.2 (97.7) 9,683.8 Utility construction expenditures 322.1 63.8 - - - 385.9 1998 Unaffiliated revenues $2,219.2 $449.4 $ 524.1 $165.4 $- $ - $3,358.1 Intersegment revenues 1.6 1.7 12.0 0.5 - (15.8) -

Total revenues 2,220.8 451.1 536.1 165.9 - (15.8) 3,358.1 Depreciation and amortization 313.0 45.4 9.2 9.3 0.2 377.1 Equity in income of equity method investees (b) 5.0 5.0 Net interest expense 164.9 23.6 16.0 38.6 (1.9) (0.3) 240.9 Income tax expense (benefit) 146.6 13.4 34.1 (15.8) (0.1) 178.2 Net income (loss) (d) 259.6 26.1 43.4 (24.2) (0.1) 1.1 305.9 Segment assets 6,342.8 934.6 1,315.0 811.6 (14.0) (115.0) 9,275.0 Utility construction expenditures 279.0 60.4 339.4

.. 1997 Unaffiliated revenues $2,191.7 $521.6 $ 399.4 $194.9 $3,307.6 Intersegment revenues 0.3 0.6 9.7 (10.6)

Total revenues 2,192.0 521.6 400.0 204.6 (10.6) 3,307.6 Depreciation and amortization 286.5 39.3 6.9 9.9 0.3 342.9 Equity in income of equity method investees (b) 5.0 5.0 Net interest expense 160.7 20.3 10.1 32.5 6.4 230.0 Income tax expense (benefit) 135.7 13.9 23.8 (13.5) (1.9) 158.0 Net income (loss) (e) 224.0 25.6 27.5 (21.1) (3.6) 1.7 254.1 Segment assets 6,404.4 907.7 700.9 885.4 10.7 (9.1) 8,900.0 Utility construction expenditures 278.7 94.5 373.2 (a) We do not allocate certain items presented in the table for (d) Our Energy Services businesses recorded $10.4 million for Constellation Energy Group and a holding company for our its share of earnings in a partnership as discussed in Note 3 and a diversified businesses. $5.5 million write-off of an energy services investment as discussed (b) Our Energy Services and our Other Diversified businesses in the "Other Energy Services" section of Management's Discussion record their equity in the income of equity method investees in and Analysis on page 33. In addition, our Other Diversified businesses their unaffiliated revenues. recorded a $15.4 million write-down of a real estate project as discussed in Note 3.

(c) Our Electric business recorded costs of $4.9 million after-tax related to Hurricane Floyd as discussed in the "Electric Operations (e) Our Electric business recorded a $37.5 million write-off and Maintenance Expenses" section of Management's Discussion related to the terminated merger with Potomac Electric Power and Analysis on page 28. Our Other Diversified businesses recorded Company as discussed in the "Other Income and Expenses" section a $16.0 million write-down of its investment in Capital Re stock to of Management's Discussion and Analysis on page 34. In addition, reflect the market value of this investment as discussed in Note 3 our Other Diversified businesses recorded a $46.0 million write and a $5.8 million write-down of certain senior-living facilities as down of two real estate projects as discussed in Note 3.

discussed in the "Other Diversified Businesses" section of "Management'sDiscussion and Analysis on page 33. In addition, 3ur Energy Services businesses recorded $18.7 million in write-downs of certain power projects as discussed in Note 3.

ConstellationEnergy Group Inc. and Subsidiaries I

I (Note 3.

Investments Real Estate Projects and Investments In 1997, CREG recorded the following write-downs of real Real estate projects and investments held by Constellation estate projects:

Real Estate Group (CREG), consist of the following: "*a $14.1 million after-tax write-down of the investment in At December 31, 1999 1998 Church Street Station that occurred because CREG decided (In millions) to sell rather than keep the project, and Properties under development $197.8 $210.6 "*a $31.9 million after-tax write-down of the investment in Piney Orchard-a mixed-use, planned-unit development Rental and operating properties 9.2 38.9 that occurred because the expected future cash flow from (net of accumulated depreciation) the project was less than CREG's investment in the project.

Equity interest in real estate investment trust 103.1 104.0 Other real estate ventures - 0.4 Power Projects Total real estate projects Power projects held by our diversified businesses consist of and investments $310.1 $353.9 the following:

At December 31, 1999 1998 In 1999, CREG sold Church Street Station -an entertainment, (In millions) dining, and retail complex in Orlando, Florida -for $11.5 Domestic million, the approximate book value of the complex. East $ 55.7 $ 46.0 West 475.6 427.4 In 1998, CREG recorded a $15.4 million after-tax write-down International of the investment in Church Street Station that occurred South America 12.3 21.6 because the fair value of the project declined based upon competitive bids. Central America 241.8 248.1 Total power projects $785.4 $743.1 In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust Our Domestic-West power projects include investments of based in Philadelphia, under which COPT assumed approxi

$301.8 million in 1999 and $310.6 in 1998 that sell electricity mately $62 million of CREG's outstanding debt, paid CREG in California under power purchase agreements called approximately $22.8 million in cash, and issued to CREG "Interim Standard Offer No. 4" agreements. We discuss approximately 7.0 million common shares representing a these projects further in Note 10 on page 71.

41.9% equity interest in COPT and 985,000 convertible preferred shares. Each convertible preferred share yields In 1999, our power projects business recorded a $14.2 million 5.5% per year, and is convertible after two years from the after-tax write-off of two geothermal power projects. These date of the agreement into 1.8748 common shares. write-offs occurred because the expected future cash flows In exchange, COPT received 14 operating properties and from the projects are less than the investment in the projects.

two properties under development from CREG as well as For the first project, this resulted from the inability to restruc certain other assets, options, and first refusal rights. These ture certain project agreements. For the second project, we options and first refusal rights are related to approximately experienced a declining water temperature of the geothermal 91 acres of identified properties which are adjacent to resource used by one of the plants for production.

operating properties acquired by COPT. At December 31, 1999, In 1999, we recorded a $4.5 million after-tax write-down to 48 acres remain under these options and first refusal rights reflect the fair value of our investment in a generating company and have terms that range from 1 to 4 years. in Bolivia as a result of our international exit strategy.

In 1998, our power projects business recorded $10.4 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power sales contract.

ConstellationEnergy Group Inc. and Subsidiaries

I Financial Investments Amortized Unrealized Unrealized Fair inancial investments held by Constellation Investments, Inc. At December 31, 1999 Cost Basis Gains Losses Value consist of the following: (In millions)

Marketable equity securities $167.1 $42.8 $(2.1) $207.8 At December 31, 1999 1998 Corporate debt and (In millions)

U.S. Government Insurance company $ - $102.5 agency 14.4 - - 14.4 Marketable equity securities 84.2 25.3 State municipal bonds 74.2 - (0.8) 73.4 Financial limited partnerships 35.8 41.9 Totals $255.7 $42.8 $(2.9) $295.6 Leveraged leases 25.4 28.3 Total financial investments $145.4 $198.0 Amortized Unrealized Unrealized Fair At December 31, 1998 Cost Basis Gains Losses Value (In millions)

In 1999, our financial investments business announced that it Marketable equity would exchange its shares of common stock in Capital Re, an securities $ 82.9 $24.2 $(0.4) $106.7 insurance company, for common stock of ACE Limited (ACE),

Corporate debt and another insurance company, as part of a business combination U.S. Government whereby ACE would acquire all of the outstanding capital agency 12.7 0.4 - 13.1 stock of Capital Re. Through September 30, 1999, our State municipal bonds 64.8 2.7 - 67.5 financial investments business wrote-down its $94.2 million Totals $160.4 $27.3 $(0.4) $187.3 investment in Capital Re stock by $20.9 million after-tax to reflect the market value of this investment. The agreement The above tables include $40.5 million in 1999 and $23.9 million between ACE and Capital Re was subsequently revised on a in 1998 of unrealized net gains associated with the nuclear more favorable basis for Capital Re to include both cash and decommissioning trust fund which are reflected as a change in kCE stock. In December 1999, the transaction was finalized the nuclear decommissioning trust fund on the Consolidated our financial investments business recorded a $4.9 million Balance Sheets.

after-tax gain on this investment to reflect the closing price of the business combination. As a result of this business Gross and net realized gains and losses on available-for-sale combination, this investment no longer qualifies as an securities were as follows:

equity-method investment. Accordingly, in 1999, we have Year Ended December 31, 1999 1998 1997 included this investment in the marketable equity securities (In millions) amount above. Gross realized gains $11.7 $4.2 $9.3 Gross realized losses (38.8) (0.7) (0.6)

Investments Classifiedas Available-for-Sale Net realized (losses) gains $(27.1) $3.5 $8.7 We classify our investments in the nuclear decommissioning trust fund as available-for-sale. In addition, we classify some The Corporate debt securities, U.S. Government agency of our diversified businesses' marketable equity securities obligations, and state municipal bonds mature on the (shown above) as available-for-sale. This means we do not following schedule:

expect to hold them to maturity and we do not consider them trading securities. At December 31, 1999 Amount (In millions)

We show the fair values, gross unrealized gains and losses, Less than 1 year $ 1.0 and amortized cost bases for all of our available-for-sale 1-5 years 46.4 securities, exclusive of $6.2 million in 1998 of unrealized net 5-10 years 21.8 gains on securities held by Capital Re as an equity method More than 10 years 18.6 investee, in the following tables. Total maturities of debt securities $87.8 ConstellationEnergy Group Inc. and Subsidiaries I

V (Note 4.

Rate Matters and Accounting Impacts of Deregulation On April 8, 1999, Maryland enacted the Electric Customer "*BGE will reduce residential base rates by approximately Choice and Competition Act of 1999 (the "Act") and 6.5% on average, about $54 million a year, beginning accompanying tax legislation that will significantly restructure July 1, 2000. These rates will not change before July 2006.

Maryland's electric utility industry and modify the industry's "*Commercial and industrial customers will have up to tax structure. In the Restructuring Order discussed below, the four service options that will fix electric energy rates and Maryland PSC addressed the major provisions of the Act. transition charges for a period that generally ranges from The tax legislation made comprehensive changes to the state four to six years.

and local taxation of electric and gas utilities. Effective "*Electric delivery service rates will be frozen for a four January 1, 2000, the Maryland public service franchise tax year period for commercial and industrial customers. The will be altered to generally include a tax equal to .062 cents generation and transmission components of rates will be on each kilowatt-hour of electricity and .402 cents on each frozen for different time periods depending on the service therm of natural gas delivered for final consumption in options selected by those customers.

Maryland. The Maryland 2% franchise tax on electric and "*BGE will be allowed to recover $528 million after-tax of natural gas utilities will continue to apply to transmission and its potentially stranded investments and utility restructuring distribution revenue. Additionally, all electric and natural gas costs through a competitive transition charge on customers' utility results will become subject to the Maryland corporate bills. Residential customers will pay this charge for six income tax.

years. Commercial and industrial customers will pay in a Beginning July 1, 2000, the tax legislation also provides for a lump sum or over the four to six-year period, depending two-year phase-in of a 50% reduction in the local personal on the service option selected by each customer.

property taxes on machinery and equipment used to generate

"*Generation-related regulatory assets and nuclear decom electricity for resale and a 60% corporate income tax credit missioning costs will be included in delivery service rates for real property taxes paid on those facilities.

effective July 1, 2000 and will be recovered on a basis On November 10, 1999, the Maryland PSC issued a approximating their existing amortization schedules.

Restructuring Order that resolves the major issues surrounding

"*Starting July 1, 2000, BGE will unbundle rates to show electric restructuring, accelerates the timetable for customer separate components for delivery service, transition choice, and addresses the major provisions of the Act. The charges, standard offer services (generation), transmission, Restructuring Order also resolves the electric restructuring universal service, and taxes.

proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in "*On July 1, 2000, BGE will transfer, at book value, its September 1998 by the Office of People's Counsel (OPC) to ten Maryland-based fossil and nuclear power plants and lower our electric base rates. The major provisions of the its partial ownership interest in two coal plants and a Restructuring Order are: hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy.

" All customers, except a few commercial and industrial companies that have signed contracts with BGE, will be "*BGE will reduce its generation assets, as described later able to choose their electric energy supplier beginning in this section, by $150 million pre-tax during the period July 1, 2000. BGE will provide a standard offer service July 1, 1999 - June 30, 2000 to mitigate a portion of its for customers that do not select an altemative supplier. potentially stranded investments.

In either case, BGE will continue to deliver electricity "*Universal service will be provided for low-income customers to all customers in areas traditionally served by BGE. without increasing their bills. BGE will provide its share

" BGE's current electric base rates are frozen at their current of a statewide fund totaling $34 million annually.

levels until July 1, 2000.

ConstellationEnergy Group Inc. and Subsidiaries

I As discussed in Note 1 on page 49, EITF 97-4 requires that Under the Restructuring Order, BGE will recover $528 million

/ company should cease applying SFAS No. 71 when either after-tax of its potentially stranded investments and utility

"-legislation is passed or a regulatory body issues an order that restructuring costs through the competitive transition charge contains sufficient detail to determine how the transition plan component of its customer rates beginning July 1, 2000. This will affect the deregulated portion of the business. Additionally, recovery mostly relates to the stranded costs associated with a company would continue to recognize regulatory assets and Calvert Cliffs, whose book value is substantially higher than liabilities in the Consolidated Balance Sheets to the extent that its estimated fair value. However, Calvert Cliffs is not consid the transition plan provides for their recovery. ered impaired under the provisions of SFAS No. 121 since its We believe that the Restructuring Order provided sufficient estimated future undiscounted cash flows exceed its book details of the transition plan to competition for BGE's electric value. Accordingly, BGE did not record any impairment generation business to require BGE to discontinue the write-down related to Calvert Cliffs. However, we recognized application of SFAS No. 71 for that portion of its business. after-tax impairment losses totaling $115.8 million associated Accordingly, in the fourth quarter of 1999, we adopted the with certain of our fossil plants under the provisions of provisions of SFAS No. 101 and EITF 97-4 for BGE's SFAS No. 121.

electric generation business. BGE has contracts to purchase electric capacity and energy SFAS No. 101 requires the elimination of the effects of rate that are expected to be uneconomic upon the deregulation of regulation that have been recognized as regulatory assets and electric generation. Therefore, we recorded a $34.2 million liabilities pursuant to SFAS No. 71. However, EITF 97-4 after-tax charge based on the net present value of the excess requires that regulatory assets and liabilities that will be of estimated contract costs over the market-based revenues to recovered in the regulated portion of the business continue recover these costs over the remaining terms of the contracts.

to be classified as regulatory assets and liabilities. The In addition, BGE has deferred certain energy conservation Restructuring Order provides for the creation of a single, new expenditures that will not be recovered through its transmis generation-related regulatory asset to be recovered through sion and distribution business under the Restructuring Order.

BGE's regulated transmission and distribution business. We Accordingly, we recorded a $10.3 million after-tax charge to discuss this further in Note 5 on page 60. eliminate the regulatory asset previously established for these

`ursuant to SFAS No. 101, the book value of property, plant, deferred expenditures.

,,*.tnd equipment may not be adjusted unless those assets are At December 31, 1999, the total charge for BGE's electric impaired under the provisions of SFAS No. 121. The process generating plants that are impaired, losses on uneconomic of evaluating and measuring impairment under the provisions purchased capacity and energy contracts, and deferred of SFAS No. 121 involves two steps. First, we must compare energy conservation expenditures was approximately the net book value of each generating plant to the estimated $160.3 million after-tax.

undiscounted future net operating cash flows from that plant. BGE recorded approximately $94.0 million of the $160.3 million An electric generating plant is considered impaired when its on its balance sheet. This consisted of a $150.0 million undiscounted future net operating cash flows are less than its regulatory asset of its regulated transmission and distribution net book value. Second, we compute the fair value of each business, net of approximately $56.0 million of associated plant that is determined to be impaired based on the present deferred income taxes. The regulatory asset will be amortized value of that plant's estimated future net operating cash flows as it is recovered from ratepayers through June 30, 2000.

discounted using an interest rate that considers the risk of This will accomplish the $150 million reduction of its operating that facility in a competitive environment. To the generation plants required by the Restructuring Order.

extent that the net book value of each impaired electric genera tion plant exceeds its fair value, we must record a write-down. We recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that will not be recovered under the Restructuring Order.

ConstellationEnergy Group Inc. and Subsidiaries

F SNote 5.

ReguLatory Assets (net)

As discussed in Note 1 on page 49, the Maryland PSC Generation Plant Reduction provides the final determination of the rates we charge our Recoverable in Current Rates customers for our regulated businesses. Generally, we use the As a condition of the Maryland PSC's consolidation of the same accounting policies and practices used by nonregulated September 3, 1998 Office of People's Counsel petition to companies for financial reporting under generally accepted lower electric base rates with BGE's electric restructuring accounting principles. However, sometimes the Maryland transition proposal, we agreed to make our rates subject to PSC orders an accounting treatment different from that used refund effective July 1, 1999. Under the Restructuring Order, by nonregulated companies to determine the rates we charge BGE's rates are frozen through June 30, 2000. However, our customers. When this happens, we must defer certain BGE was required to record a reduction to its generation plant utility expenses and income in our Consolidated Balance of $150 million which it will recover through its current rates Sheets as regulatory assets and liabilities. We then record between July 1, 1999 and June 30, 2000. BGE recorded a them in our Consolidated Statements of Income (using $150 million regulatory asset for the required generation plant amortization) when we include them in the rates we charge reduction that will be amortized as it is recovered from our customers. ratepayers through June 30, 2000.

We summarize regulatory assets and liabilities in the following table, and we discuss each of them separately below. Electric Generation-Related Regulatory Asset With the issuance of the Restructuring Order, BGE no longer At At December December 31.31I 19'99 1998 met the requirements for the application of SFAS No. 71 for (In millions) the electric generation portion of its business. In accordance Generation plant reduction with SFAS No. 101 and EITF 97-4, all individual generation recoverable in current rates $75.0 $ related regulatory assets and liabilities must be eliminated from Electric generation-related our balance sheet unless these regulatory assets and liabilities regulatory asset 286.6 will be recovered in the regulated portion of the business.

Income taxes recoverable through Pursuant to the Restructuring Order, BGE wrote-off all of its \

future rates (net) 110.4 252.6 individual, generation-related regulatory assets and liabilities.

Deferred postretirement and A single, new generation-related regulatory asset was estab postemployment benefit costs 41.9 90.0 73.3 lished for amounts to be collected through BGE's regulated Deferred nuclear expenditures transmission and distribution business. The new regulatory Deferred conservation expenditures 12.9 53.4 asset will be amortized on a basis that approximates the pre Deferred costs of decommissioning existing individual regulatory asset amortization schedules.

federal uranium enrichment facilities 38.5 Deferred environmental costs 31.3 33.4 Deferred fuel costs (net) 73.8 12.7 Income Taxes Recoverable Through Future Rates (net)

Other (net) 5.5 11.8 As described in Note 1 on page 51, income taxes recoverable

$637.4 $565.7 through future rates is the portion of our net deferred income Total regulatory assets (net) tax liability that is applicable to our utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse.

In 1999, the electric generation-related portion of this regulatory asset is included in the electric generation-related regulatory asset discussed earlier in this note.

Constellation Energy Group Inc. and Subsidiaries

I Deferred Postretirement and Postemployment Deferred Costs of Decommissioning 3enefit Costs Federal Uranium Enrichment Facilities Deferred postretirement and postemployment benefit costs are Deferred costs of decommissioning federal uranium enrichment the costs we recorded under SFAS No. 106 (for postretirement facilities are the unamortized portion of our required contribu benefits) and No. 112 (for postemployment benefits) in excess tions to a fund for decommissioning and decontaminating the of the costs we included in the rates we charge our customers. Department of Energy's uranium enrichment facilities. We are We began amortizing these costs over a 15-year period in required, along with other domestic utilities, by the Energy 1998. We discuss these costs further in Note 6 on page 62. Policy Act of 1992 to make contributions to the fund. The In 1999, we reclassified the electric generation-related portion contributions are generally payable over 15 years with escala of this regulatory asset to the electric generation-related tion for inflation and are based upon the proportionate amount regulatory asset discussed earlier in this note. of uranium enriched by the Department of Energy for each utility. We are amortizing these costs over the contribution period as a cost of fuel. We also discuss this in Note 1 on page 50.

Deferred Nuclear Expenditures Deferred nuclear expenditures are the net unamortized balance In 1999, these expenditures were reclassified to the electric of certain operations and maintenance costs at Calvert Cliffs. generation-related regulatory asset discussed earlier in this note.

These expenditures consist of:

"*costs incurred from 1979 through 1982 for inspecting and Deferred Environmental Costs repairing seismic pipe supports, Deferred environmental costs are the estimated costs of

"*expenditures incurred from 1989 through 1994 associated investigating and cleaning up contaminated sites we own.

with nonrecurring phases of certain nuclear operations We discuss this further in Note 10 on page 69. We are projects, and amortizing $21.6 million of these costs (the amount we had

"*expenditures incurred during 1990 for investigating leaks incurred through October 1995) over a 10-year period in in the pressurizer heater sleeves. accordance with the Maryland PSC's November 1995 order.

In 1999, these expenditures were reclassified to the electric generation-related regulatory asset discussed earlier in this note. Deferred Fuel Costs As described in Note 1 on page 50, deferred fuel costs are the difference between our actual costs of electric fuel, net purchases Deferred Conservation Expenditures and sales of electricity, and natural gas and our fuel rate Deferred conservation expenditures include two components:

revenues collected from customers. We reduce deferred fuel

"*operations costs (labor, materials, and indirect costs) costs as we collect them from or refund them to our customers.

associated with conservation programs approved by the We show our deferred fuel costs in the following table.

Maryland PSC, which we are amortizing over periods of four to five years in accordance with the Maryland PSC's At December 31, 1999 1998 orders, and (In millions)

Electric $60.0 $(11.5)

"*revenues we collected from customers in 1996 in excess Gas 13.8 24.2 of our profit limit under the conservation surcharge.

Deferred fuel costs (net) $73.8 $12.7 In 1999, we wrote-off a portion of the unamortized electric conservation expenditures that will not be recovered under the Restructuring Order as discussed in Note 4 on page 59. Under the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC.

ConstellationEnergy Group Inc. and Subsidiaries

CNote 6. /

Pension, Postretirement, Other Postemployment, and EmpLoyee Savings Plan Benefits We offer pension, postretirement, other postemployment, and Postretirement Benefits employee savings plan benefits. We describe each of these We sponsor defined benefit postretirement health care and separately below. life insurance plans which cover nearly all Constellation Energy and BGE employees, and certain employees of our subsidiaries. Generally, we calculate the benefits under these Pension Benefits plans based on age, years of service, and pension benefit We sponsor several defined benefit pension plans for our levels. We do not fund these plans.

employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information For nearly all of the health care plans, retirees make contribu about the participant. Our employees do not contribute to tions to cover a portion of the plan costs. Contributions for these plans. Generally, we calculate the benefits under these employees who retire after June 30, 1992 are calculated based plans based on age, years of service, and pay. on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the Sometimes we amend the plans retroactively. These retroactive life insurance plan, retirees do not make contributions to cover plan amendments require us to recalculate benefits related to a portion of the plan costs.

participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over Effective January 1, 1993, we adopted SFAS No. 106, the average remaining service period of active employees. Employers' Accounting for PostretirementBenefits Other Than Pensions. The adoption of that statement caused:

In 1999, our Board of Directors approved the following amendments: "*a transition obligation, which we are amortizing over 20 years, and

" eligible participants will be allowed to choose between an enhanced version of the current benefit formula and a new "*an increase in annual postretirement benefit costs.

pension equity plan (PEP) formula. Pension benefits for For our diversified businesses, we expense all postretirement eligible employees hired after December 31, 1999 will be benefit costs. For our utility business, we accounted for the based on a PEP formula, and increase in annual postretirement benefit costs under two

" pension and survivor benefits were increased for participants Maryland PSC rate orders:

who retired prior to January 1, 1994 and for their surviving "*in an April 1993 rate order, the Maryland PSC allowed spouses. us to expense one-half and defer, as a regulatory asset The financial impacts of the amendments are included in the (see Note 5), the other half of the increase in annual tables on page 63. postretirement benefit costs related to our electric and gas businesses, and Also during 1999, our Board of Directors approved a Targeted Voluntary Special Early Retirement Program "*in a November 1995 rate order, the Maryland PSC allowed (TVSERP) to provide enhanced early retirement benefits us to expense all of the increase in annual postretirement to certain eligible participants in targeted jobs that elect to benefit costs related to our gas business.

retire on June 1, 2000. The financial impacts of the TVSERP Beginning in 1998, the Maryland PSC authorized us to:

will be reflected in the second quarter of 2000.

"*expense all of the increase in annual postretirement benefit We fund the plans by contributing at least the minimum costs related to our electric business, and amount required under Internal Revenue Service regulations.

"*amortize the regulatory asset for postretirement benefit We calculate the amount of funding using an actuarial method costs related to our electric and gas businesses over 15 years.

called the projected unit credit cost method. The assets in all of the plans at December 31, 1999 were mostly marketable equity and fixed income securities, and group annuity contracts.

Constellation Energy Group Inc. and Subsidiaries

I Obligations, Assets, and Funded Status Pension Postretirement Ze show the change in the benefit obligations, plan assets, Benefits Benefits and funded status of the pension and postretirement benefit 1999 1998 1999 1998 plans in the following table: (In millions)

Pens ion Postretirement Funded Status Bene-fits Benefits Funded status at 1999 1998 1999 1998 December 31 $ 68.2 $(45.8) $(358.7) $(383.1)

(In millions) Unrecognized net Change in benefit obligation actuarial (gain) loss (27.2) 137.6 23.6 59.7 Benefit obligation at Unrecognized prior January 1 $ 1,031.3 $ 902.0 $383.1 service cost 59.0 16.9 (0.1)

$320.3 Service cost 26.1 21.6 8.6 6.6 Unrecognized Interest cost 65.3 63.0 24.4 23.4 transition obligation - - 143.4 159.3 Plan participants' Unamortized net asset from contributions - - 2.0 2.0 adoption of SFAS No. 87 (0.5) (0.7) -

Actuarial (gain) loss (93.0) 102.9 (34.2) 48.9 Prepaid (accrued) benefit Plan amendments 44.6 - (5.0) cost $99.5 $108.0 $(191.8) $164.1)

Benefits paid (57.6) (58.2) (20.2) (18.1)

Benefit obligation at December 31 $ 1,016.7 $1,031.3 $358.7 $383.1 Net Periodic Benefit Cost We show the components of net periodic pension benefit cost in the following table:

Pension Postretirement Benefits Benefits Year Ended December 31, 1999 1998 1997 1999 1998 1999 1998 (In millions)

(In millions) Components of net periodic

-_, ,2hange in plan assets pension benefit cost Fair value of plan assets at Service cost $26.1 $21.6 $16.8 January 1 $ 985.5 $912.3 $- $ Interest cost 65.3 63.0 61.3 Actual return on Expected return on plan assets (76.6) (72.1) (66.9) plan assets 139.4 116.9 - Amortization of transition Employer contribution 17.6 14.5 18.2 16.1 obligation (0.2) (0.2) (0.2)

Plan participants' Amortization of prior service cost 2.5 2.5 2.5 contributions - - 2.0 2.0 Recognized net actuarial loss 10.1 5.6 4.6 Benefits paid (57.6) (58.2) (20.2) (18.1) Amount capitalized as Fair value of plan assets construction cost (4.2) (3.8) (2.5) at December 31 $1,084.9 $985.5 $ - $- Net periodic pension benefit cost $23.0 $16.6 $15.6 ConstellationEnergy Group Inc. and Subsidiaries

We show the components of net periodic postretirement Other Postemployment Benefits benefit cost in the following table: We provide the following postemployment benefits:

Year Ended December 31, 1999 1998 1997 "*health and life insurance benefits to our employees and (In millions) certain employees of our subsidiaries who are found to be Components of net periodic disabled under our Disability Insurance Plan, and postretirement benefit cost "*income replacement payments for employees found to be Service cost $ 8.6 $ 6.6 $ 5.4 disabled before November 1995 (payments for employees Interest cost 24.4 23.4 21.8 found to be disabled after that date are paid by an insur Amortization of transition ance company, and the cost is paid by employees).

obligation 11.0 11.4 11.4 The liability for these benefits totaled $46.5 million as of Recognized net actuarial loss 1.9 0.2 0.1 December 31, 1999 and $52.9 million as of December 31, 1998.

Amount capitalized as construction cost (9.4) (8.1) (7.6) Effective December 31, 1993, we adopted SFAS No. 112, Amount deferred - - (7.2) Employers' Accounting for Postemployment Benefits. We Net periodic postretirement deferred, as a regulatory asset (see Note 5 on page 61), the benefit cost $36.5 $33.5 $23.9 postemployment benefit liability attributable to our utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described Assumptions earlier in this note). We began to amortize the regulatory asset We made the assumptions below to calculate our pension and over 15 years beginning in 1998. The Maryland PSC authorized postretirement benefit obligations. us to reflect this change in our current electric and gas base Pension Postretirement rates to recover the higher costs in 1998.

Benefits Benefits We assumed the discount rate for other postemployment At December 31, 1999 1998 1999 1998 benefits to be 5.5% in 1999 and 4.5% in 1998.

Discount rate 7.25% 6.50% 7.25% 6.50%

Expected return on plan assets 9.00 9.00 N/A N/A Employee Savings Plan Benefits Rate of compensation We also sponsor a defined contribution savings plan that increase 4.00 4.00 4.00 4.00 is offered to all eligible Constellation Energy and BGE employees, and certain employees of our subsidiaries.

In a defined contribution plan, the benefits a participant We assumed the health care inflation rates to be: is to receive result from regular contributions to a participant

"*in 1999, 6.0% for both Medicare-eligible retirees and account. Under this plan, we make matching contributions retirees not covered by Medicare, and to participant accounts. We made matching contributions

"*in 2000, 7.0% for Medicare-eligible retirees and 8.5% for to this plan of:

retirees not covered by Medicare. * $10.4 million in 1999, After 2000, we assumed both inflation rates will decrease by * $10.1 million in 1998, and 0.5% annually to a rate of 5.5% in the years 2003 and 2006, * $8.5 million in 1997.

respectively. After these dates, the inflation rate will remain at 5.5%.

A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretire ment benefit obligation by approximately $46.7 million as of December 31, 1999 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.4 million annually.

A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretire ment benefit obligation by approximately $37.4 million as of December 31, 1999 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.2 million annually.

i.ConstellationEnergy Group Inc. and Subsidiaries

I Note 7.

  • -'Short-Term Borrowings Our short-term borrowings may include bank loans, commercial In addition, Constellation Energy had unused committed paper notes, and bank lines of credit. Short-term borrowings bank lines of credit totaling $35 million and interim lines mature within one year from the date of issuance. We pay totaling $125 million supporting its commercial paper notes commitment fees to banks for providing us lines of credit. at December 31, 1999.

When we borrow under the lines of credit, we pay market The weighted average effective interest rate for Constellation interest rates. Energy's commercial paper notes was 5.68% for the year ended December 31, 1999.

Constellation Energy At December 31, 1999, Constellation Energy had $242.5 million outstanding consisting entirely of commercial paper notes. BGE At December 31, 1999, BGE had $129.0 million At December 31, 1998, no short-term borrowings were outstanding consisting entirely of commercial paper notes.

outstanding since Constellation Energy was not established until April 30, 1999 as discussed in Note 1 on page 49. At December 31, 1998, BGE had no short-term borrowings outstanding.

In 1999, Constellation Energy arranged a $135 million revolving credit agreement for short-term financial needs, At December 31, 1999, BGE had unused committed bank lines including letters of credit. This agreement also supports of credit totaling $123 million supporting the commercial paper notes compared to $113 million at December 31, 1998.

Constellation Energy's commercial paper notes. This facility replaced a similar facility at one of Constellation Energy's These amounts do not include unused revolving credit agree diversified businesses. At December 31, 1999, letters of ments of $60 million at December 31, 1999 and $100 million credit totaling $23.1 million were issued under this facility. at December 31, 1998 that are discussed in Note 8 on page 66.

The weighted average effective interest rates for BGE's commercial paper notes were 5.25% for the year ended December 31, 1999 and 5.65% for 1998.

Note 8.

Long-Term Debt Long-term debt matures in one year or more from the date of bonds outstanding during the preceding 12 months. The trustee issuance. We summarize our long-term debt in the Consolidated uses these funds to retire bonds from any series through repur Statements of Capitalization. As you read this section, it may chases or calls for early redemption. However, the trustee be helpful to refer to those statements. cannot call the following bonds for early redemption:

BGE "*5MA% Installment Series, due 2002 - 6%% Series, due 2003 BGE's FirstRefunding Mortgage Bonds "*5M% Series, due 2000 - 5%% Series, due 2004 BGE's first refunding mortgage bonds are secured by a

  • 83A%Series, due 2001 - 74% Series, due 2007 mortgage lien on nearly all of its assets, including all utility properties and franchises and its subsidiary capital stock.
  • 7T% Series, due 2002 - 6%% Series, due 2008 Capital stock pledged under the mortgage is that of Safe *6X% Series, due 2003 Harbor Water Power Corporation and Constellation Holders of the Remarketed Floating Rate Series Due Enterprises, Inc. When BGE transfers its generating assets to September 1, 2006 have the option to require BGE to subsidiaries of Constellation Energy, these assets will remain repurchase their bonds at face value on September 1 of subject to the lien of BGE's mortgage. However, BGE will each year. BGE is required to repurchase and retire at par remain liable for this debt after the assets are transferred. any bonds that are not remarketed or purchased by the BGE is required to make an annual sinking fund payment remarketing agent. BGE also has the option to redeem all

-ach August 1 to the mortgage trustee. The amount of the or some of these bonds at face value each September 1.

"*'payment is equal to 1% of the highest principal amount of ConstellationEnergy Group Inc. and Subsidiaries I

I BGE's Other Long-Term Debt The interest paid on the debentures, which the Trust will use We show the weighted-average interest rates and maturity to make distributions on the TOPrS, is included in "Interest dates for BGE's fixed-rate medium-term notes outstanding Expense" in the Consolidated Statements of Income and is at December 31, 1999 in the following table. deductible for income tax purposes.

Weighted-Average BGE fully and unconditionally guarantees the TOPrS based Series Interest Rate Maturity Dates on its various obligations relating to the trust agreement, B 8.10% 2000-2006 indentures, debentures, and the preferred security guarantee C 7.33 2000-2003 agreement.

D 6.66 2001-2006 The debentures are the only assets of the Trust. The Trust E 6.66 2006-2012 is wholly owned by BGE because it owns all the common G 6.08 2001-2008 securities of the Trust that have general voting power.

For the payment of dividends and in the event of liquidation Some of the medium-term notes include a "put option." of BGE, the debentures are ranked prior to preference stock These put options allow the holders to sell their notes back to and common stock.

BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium Diversified Businesses term notes with put options.

Revolving CreditAgreements Series E Notes Principal Put Option Dates ComfortLink has a $50 million unsecured revolving credit (In millions) agreement that matures September 26, 2001. Under the terms 6.75%, due 2012 $60.0 June 2002 and 2007 of the agreement, ComfortLink has the option to obtain loans 6.75%, due 2012 25.0 June 2004 and 2007 at various rates for terms up to nine months. ComfortLink 6.73%, due 2012 25.0 June 2004 and 2007 pays a facility fee on the total amount of the commitment.

At December 31, 1999, ComfortLink had $33 million BGE has $60 million of revolving credit agreements with several outstanding under this agreement.

banks that are available through 2000. At December 31, 1999, Mortgage and ConstructionLoans BGE had no outstanding borrowings under these agreements.

Our diversified businesses' mortgage and construction loans These banks charge us commitment fees based on the daily have varying terms. The following mortgage notes require average of the unborrowed amount, and we pay market interest monthly principal and interest payments:

rates on any borrowings. These agreements also support BGE's commercial paper notes, as described in Note 7 on page 65. "*7.90%, due in 2000

  • 9.65%, due in 2028

"*8.00%, due in 2001

  • 8.00%, due in 2033 BGE ObligatedMandatorily Redeemable "*4.25%, due in 2009 Trust PreferredSecurities The 8.00% mortgage note due in 2003 requires interest On June 15, 1998, BGE Capital Trust I (Trust), a Delaware payments until maturity. The variable rate mortgage notes business trust established by BGE, issued 10,000,000 Trust and construction loans require periodic payment of principal Originated Preferred Securities (TOPrS) for $250 million and interest.

($25 liquidation amount per preferred security) with a distribution rate of 7.16%.

UnsecuredNotes The Trust used the net proceeds from the issuance of the The unsecured notes mature on the following schedule:

common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures Amount due June 30, 2038 (debentures) from BGE in the aggregate (In millions) principal amount of $257.7 million with the same terms as 7.125%, due March 13, 2000 $ 15.0 the TOPrS. The Trust must redeem the TOPrS at $25 per 7.55%, due April 22, 2000 35.0 preferred security plus accrued but unpaid distributions when 7.50%, due May 5, 2000 139.0 the debentures are paid at maturity or upon any earlier 7.43%, due September 9, 2000 30.0 redemption. BGE has the option to redeem the debentures 5.43% due October 15, 2000 5.0 at any time on or after June 15, 2003 or at any time when 7.66%, due May 5, 2001 135.0 certain tax or other events occur. 5.67%, due May 5, 2001 152.0 Total unsecured notes at December 31, 1999 $511.0 ConstellationEnergy Group Inc. and Subsidiaries

I Maturities of Long-Tenn Debt Weighted Average Interest Rates for Variable Rate Debt

._. 1lof our long-term borrowings mature on the following Our weighted average interest rates for variable rate debt were:

schedule (includes sinking fund requirements): Year Ended December 31. 1999 1998 Diversified BGE Year BGE Businesses Floating rate series mortgage bonds 5.41% 5.90%

(In millions) Remarketed floating rate 2000 $ 401.9 $284.4 series mortgage bonds 5.19 5.70 2001 282.2 366.6 Medium-term notes, Series D 5.29 5.74 2002 154.0 1.5 Medium-term notes, Series G 5.38 2003 286.8 10.4 Medium-term notes; Series H 5.64 2004 154.0 6.0 Pollution control loan 3.22 3.48 Thereafter 1,428.6 17.9 Port facilities loan 3.24 3.61 Total long-term debt Adjustable rate pollution control loan 3.59 3.75 at December 31, 1999 $2,707.5 $686.8 Economic development loan 3.26 3.59 Variable rate pollution control loan 3.30 3.45 At December 31, 1999, BGE had long-term loans totaling

$255.0 million that mature after 2002 (including $110.0 million Diversified Businesses of medium-term notes discussed in this Note under "BGE's Loans under credit agreement 5.68 6.02 Other Long-Term Debt") that lenders could potentially require Mortgage and construction loans 6.65 8.17 us to repay early. Of this amount, $145.0 million could be repaid in 2000, $60.0 million in 2002, and $50.0 million thereafter. At December 31, 1999, $122.0 million is classified as current portion of long-term debt as a result of these provisions.

Note 9.

Leases There are two types of leases--operating and capital. Capital Lease expense was:

leases qualify as sales or purchases of property and are reported * $12.2 million in 1999, in the Consolidated Balance Sheets. Capital leases are not

  • $10.5 million in 1998, and material in amount. All other leases are operating leases and are reported in the Consolidated Statements of Income. We * $9.5 million in 1997.

present information about our operating leases below. At December 31, 1999, we owed future minimum payments for long-term, noncancelable, operating leases as follows:

Outgoing Lease Payments Year (In millions)

We, as lessee, lease some facilities and equipment used in our 2000 $ 8.2 businesses. The lease agreements expire on various dates and 2001 6.1 have various renewal options. We expense all lease payments 2002 4.5 associated with our regulated utility operations. 2003 3.2 2004 2.4 Thereafter 9.7 Total future minimum lease payments $34.1 ConstellationEnergy Group Inc. and Subsidiaries I

r (Note 10.

Commitments, Guarantees, and Contingencies Commitments We have made substantial commitments in connection with Some of our diversified businesses have committed to our utility construction program for future years. In addition, contribute additional capital and to make additional loans our electric business has entered into two long-term contracts to some affiliates, joint ventures, and partnerships in which for the purchase of electric generating capacity and energy. they have an interest. At December 31, 1999, the total amount The contracts expire in 2001 and 2013. We made payments of investment requirements committed to by our diversified under these contracts of: businesses was $174.2 million. This amount includes

  • $67.8 million in 1999, $121 million for our energy services businesses commitment to Orion Power Holdings, Inc.
  • $70.7 million in 1998, and BGE and BGE Home Products & Services have agreements
  • $65.6 million in 1997.

to sell on an ongoing basis an undivided interest in a desig At December 31, 1999, we estimate our future payments for nated pool of customer receivables. Under the agreements, capacity and energy that we are obligated to buy under these BGE can sell up to a total of $40 million, and BGE Home contracts to be: Products & Services can sell up to a total of $50 million.

Year (In millions) Under the terms of the agreements, the buyer of the receiv 2000 $ 69.7 ables has limited recourse against BGE and has no recourse 2001 37.1 against BGE Home Products & Services. BGE and BGE 2002 13.9 Home Products & Services have recorded reserves for credit 2003 13.8 losses. At December 31, 1999, BGE had sold $28.2 million 2004 13.6 and BGE Home Products & Services had sold $43.3 million Thereafter 113.4 of receivables under these agreements.

Total estimated future payments for capacity and energy under long-term contracts $261.5 Guarantees Constellation Energy has issued guarantees in an amount up to $69.2 million related to credit facilities and contractual Portions of these contracts are expected to be uneconomic performance of certain of its diversified subsidiaries.

upon the deregulation of electric generation. Therefore, we However, the actual subsidiary liabilities related to these recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract guarantees totaled $21.7 million at December 31, 1999.

costs over the market based revenues to recover these costs BGE guarantees two-thirds of certain debt of Safe Harbor over the remaining terms of the contracts as discussed in Water Power Corporation. The maximum amount of our Note 4 on page 59. At December 31, 1999, the accrued guarantee is $23 million. At December 31, 1999, Safe Harbor portion of these contracts was $47.5 million. Water Power Corporation had outstanding debt of $20.4 million, of which $13.6 million is guaranteed by BGE.

At December 31, 1999, our remaining diversified businesses had guaranteed outstanding loans and letters of credit of certain power projects and real estate projects totaling

$48.8 million. Our diversified businesses also guarantee certain other borrowings of various power projects and real estate projects.

We assess the risk of loss from these guarantees to be minimal.

ConstellationEnergy Group Inc. and Subsidiaries

I

'Environmental Matters Waste Disposal

'lean Air The EPA and several state agencies have notified us that we The Clean Air Act of 1990 contains two titles designed to are considered a potentially responsible party with respect to reduce emissions of sulfur dioxides and nitrogen oxides the cleanup of certain environmentally contaminated sites (NOx) from electric generating stations-Title IV and Title I. owned and operated by others. We cannot estimate the Title IV primarily addresses emissions of sulfur dioxides. cleanup costs for all of these sites.

Compliance is required in two phases: We can, however, estimate that our current 15.43% share of

"*Phase I became effective January 1, 1995. We met the the reasonably possible cleanup costs at one of these sites, requirements of this phase by installing flue gas desulfur Metal Bank of America (a metal reclaimer in Philadelphia),

ization systems, switching fuels, and retiring some units. could be as much as $4.9 million higher than amounts we have recorded as a liability on our Consolidated Balance

"*Phase II became effective January 1, 2000. We met the Sheets. This estimate is based on a Record of Decision compliance requirements through a combination of issued by the EPA.

switching fuels and allowance trading.

On July 12, 1999, the EPA notified us, along with nineteen Title I addresses emissions of NOx. The Maryland Department other entities, that we may be a potentially responsible party of the Environment (MDE) has issued regulations, effective at the 68th Street Dump/Industrial Enterprises Site, also October 18, 1999, which require up to 65% NOx emissions known as the Robb Tyler Dump located in Baltimore, reductions by May 1, 2000. We have entered into a settlement Maryland. The EPA indicated that it is proceeding with plans agreement with the MDE since we cannot meet this deadline. to conduct a remedial investigation and feasibility study. This Under the terms of the settlement agreement, BGE will install site was proposed for listing as a federal Superfund site in emissions reduction equipment at two sites by May 2002. In January 1999, but the listing has not been finalized. Although the meantime, we are taking steps to control NOx emissions our potential liability cannot be estimated, we do not expect at our generating plants. such liability to be material based on our records showing The Environmental Protection Agency (EPA) issued a final rule that we did not send waste to the site.

in September 1998 that requires up to 85% NOx emissions Also, we are coordinating investigation of several sites where "eduction by 22 states including Maryland and Pennsylvania.

gas was manufactured in the past. The investigation of these

,_-'WAhile the rule was appealed by several groups including sites includes reviewing possible actions to remove coal tar.

utilities and states, Maryland will meet the requirements In late December 1996, we signed a consent order with the of the rule by 2003. MDE that requires us to implement remedial action plans for Based on the MDE and EPA regulations, we currently contamination at and around the Spring Gardens site, located estimate that the additional controls needed at our generating in Baltimore, Maryland. We submitted the required remedial plants to meet the MDE's 65% NOx emission reduction action plans and they have been approved by the MDE. Based requirements will cost approximately $135 million. Through on the remedial action plans, the costs we consider to be December 31, 1999, we have spent approximately $51 million probable to remedy the contamination are estimated to total to meet the MDE's 65% reduction requirements. We estimate $47 million in nominal dollars (including inflation). We have the additional cost for EPA's 85% reduction requirements to recorded these costs as a liability on our Consolidated Balance be approximately $35 million by 2003. Sheets and have deferred these costs, net of accumulated In July 1997, the EPA published new National Ambient Air amortization and amounts we recovered from insurance Quality Standards for very fine particulates and revised companies, as a regulatory asset. We discuss this further in standards for ozone attainment. In 1999, these new standards Note 5 on page 61. Through December 31, 1999, we have were successfully challenged in court. The EPA is expected to spent approximately $34 million for remediation at this site.

appeal the 1999 court rulings to the Supreme Court. While these standards may require increased controls at our fossil generating plants in the future, implementation will be delayed for several years. We cannot estimate the cost of these increased controls at this time because the states, including Maryland and Pennsylvania, still need to determine what reductions in pollutants will be necessary to meet the new federal standards.

ConstellationEnergy Group Inc. and Subsidiaries I

r We are also required by accounting rules to disclose In addition we, as well as others, could be charged for a additional costs we consider to be less likely than probable portion of any third party claims associated with a nuclear costs, but still "reasonably possible" of being incurred at these incident at any commercial nuclear power plant in the sites. Because of the results of studies at these sites, it is country. At December 31, 1999, the limit for third party reasonably possible that these additional costs could exceed claims from a nuclear incident is $9.34 billion under the the amount we recognized by approximately $14 million in provisions of the Price Anderson Act. If third party claims nominal dollars ($7 million in current dollars, plus the impact exceed $200 million (the amount of primary insurance), our of inflation at 3.1% over a period of up to 36 years). share of the total liability for third party claims could be up We do not expect the cleanup costs of the remaining sites to to $176.2 million per incident. That amount would be have a material effect on our financial results. payable at a rate of $20 million per year.

Nuclear Insurance Insurancefor Worker Radiation Claims If there were an accident or an extended outage at either unit As an operator of a commercial nuclear power plant in of Calvert Cliffs, it could have a substantial adverse financial the United States, we are required to purchase insurance to effect on us. The primary contingencies that would result from cover radiation injury claims of certain nuclear workers.

an incident at Calvert Cliffs could include: On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations.

"*physical damage to the plant, Waiving the right to make additional claims under the old

"*recoverability of replacement power costs, and policy was a condition for acceptance under the new policy.

"*our liability to third parties for property damage and We describe both the old and new policies below.

bodily injury. "*Nuclear worker claims reported on or after January 1, 1998 We have insurance policies that cover these contingencies, are covered by a new insurance policy with an annual but the policies have certain industry standard exclusions. industry aggregate limit of $200 million for radiation Furthermore, the costs that could result from a covered major injury claims against all those insured by this policy.

accident or a covered extended outage at either of the Calvert "°All nuclear worker claims reported prior to January 1, 1998 Cliffs units could exceed our insurance coverage limits. are still covered by the old insurance policies. Insureds under the old policies, with no current operations, are not Insurancefor CalvertCliffs and Third Party Claims required to purchase the new policy described above, and For physical damage to Calvert Cliffs, we have $2.75 billion may still make claims against the old policies for the next of property insurance from an industry mutual insurance eight years. If radiation injury claims under these old policies company. If an outage at either of the two units at Calvert exceed the policy reserves, all policyholders could be Cliffs is caused by an insured physical damage loss and lasts assessed, with our share being up to $6.3 million.

more than 12 weeks, we have insurance coverage for replace If claims under these polices exceed the coverage limits, ment power costs up to $490.0 million per unit, provided by the provisions of the Price Anderson Act (discussed in this an industry mutual insurance company. This amount can be section) would apply.

reduced by up to $98.0 million per unit if an outage at both units of the plant is caused by a single insured physical damage loss. If accidents at any insured plants cause a shortfall of funds at the industry mutual insurance company, all policyholders could be assessed, with our share being up to $21.7 million.

ConstellationEnergy Group Inc. and Subsidiaries

I Recoverability of Electric Fuel Costs California Power Purchase Agreements

. Jntil July 1, 2000, we will continue to recover our cost of Constellation Power, Inc. and subsidiaries and Constellation

"'electric fuel as long as the Maryland PSC finds that, among Investments, Inc. (whose power projects are managed by other things, we have kept the productive capacity of our Constellation Power) have $301.8 million invested in 14 projects generating plants at a reasonable level. To do this, the that sell electricity in California under power purchase agree Maryland PSC will evaluate the performance of our gener ments called "Interim Standard Offer No. 4" agreements.

ating plants, and will determine if we used all reasonable and Under these agreements, the projects supply electricity to cost-effective maintenance and operating control procedures. utility companies at:

The Maryland PSC, under the Generating Unit Performance "*a fixed rate for capacity and energy for the first 10 years Program, measures annually whether we have maintained the of the agreements, and productive capacity of our generating plants at reasonable levels. To do this, the program uses a system-wide generating

"*a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term performance target and an individual performance target for of the agreements.

each base load generating unit. In fuel rate hearings, actual generating performance adjusted for planned outages will Generally, a "capacity rate" is paid to a power plant for its be compared first to the system-wide target. availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally If that target is met, it should mean that the requirements of is the cost of a utility's cheapest next-available source of Maryland law have been met. If the system-wide target is not generation to service the demands on its system.

met, each unit's adjusted actual generating performance will be compared to its individual performance target to determine We use the term "transitioned" to describe when the 10-year if the requirements of Maryland law have been met and, if periods for fixed energy rates have expired for these power not, to determine the basis for possibly imposing a penalty generation projects and they began supplying electricity at on BGE. Even if we meet these targets, parties to fuel rate variable rates. The four remaining projects that have not hearings may still question whether we used all reasonable transitioned will do so by December 2000.

and cost-effective procedures to try to prevent an outage. The projects that have already transitioned to variable rates

'f the Maryland PSC decides we were deficient in some way, have had lower revenues under variable rates than they did

,-the Maryland PSC may not allow us to recover the cost of under fixed rates. Once the remaining projects have transi replacement energy. tioned to variable rates, we expect the revenues from those The two units at Calvert Cliffs use the cheapest fuel. As a result, projects also to be lower than they are under fixed rates.

the costs of replacement energy associated with outages at We discuss the earnings for these projects in the "Diversified these units can be significant. We cannot estimate the Businesses" section of Management's Discussion and amount of replacement energy costs that could be challenged Analysis on page 32.

or disallowed in future fuel rate proceedings, but such amounts could be material.

Under the terms of the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000.

We discuss competition and its impact on BGE's generation business further in Note 4 on page 58. The discontinuance of BGE's electric fuel rate clause is discussed further in N6te 1 on page 50.

ConstellationEnergy Group Inc. and Subsidiaries I

F (Note 11.

Fair Market VaLue of Financial Instruments The fair value of a financial instrument represents the amount It was not practicable to estimate the fair value of investments at which the instrument could be exchanged in a current trans held by our diversified businesses in:

action between willing parties, other than in a forced sale or "*several financial partnerships that invest in nonpublic debt liquidation. Significant differences can occur between the fair and equity securities, and value and carrying amount of financial instruments that are recorded at historical amounts. We used the following methods "*several partnerships that own solar powered energy production facilities.

and assumptions in estimating fair value disclosures for financial instruments: This is because the timing and amount of cash flows from these investments are difficult to predict. We report these

"*Cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrow investments at their original cost in our Consolidated ings, current portions of long-term debt and preference Balance Sheets.

stock, and certain deferred credits and other liabilities: The investments in financial partnerships totaled $35.8 million The amounts reported in the Consolidated Balance Sheets at December 31, 1999 and $41.9 million at December 31, 1998, approximate fair value. representing ownership interests up to 10%. The total assets of

"*Investments and other assets where it was practicable to all of these partnerships totaled $5.9 billion at December 31, 1998 estimate fair value: The fair value is based on quoted (which is the latest information available).

market prices where available. The investments in solar powered energy production facility

"*Fixed-rate long-term debt, and redeemable preference partnerships totaled $10.9 million at December 31, 1999 and stock: The fair value is based on quoted market prices 1998, representing ownership interests up to 13%. The total where available or by discounting remaining cash flows at assets of all of these partnerships totaled $31.3 million at current market rates. The carrying amount of variable-rate December 31, 1998 (which is the latest information available) long-term debt approximates fair value.

We show the carrying amounts and fair values of financial Guarantees instruments included in our Consolidated Balance Sheets in It was not practicable to determine the fair value of the following table, and we describe some of the items certain loan guarantees of Constellation Energy and its separately below: subsidiaries. Constellation Energy guaranteed outstanding 1999 1998 debt of $16.5 million at December 31, 1999. BGE guaranteed At December31.

Carrying Fair Carrying Fair outstanding debt of $13.6 million at December 31, 1999 Amount Value Amount Value and $18.0 million at December 31, 1998. Our diversified (In millions) businesses guaranteed outstanding debt totaling $48.8 million Investments and other at December 31, 1999 and $59.7 million at December 31, 1998.

assets for which it is: We do not anticipate that we will need to fund these guarantees.

Practicable to estimate fair value $ 313.3 $ 313.3 $ 213.0 $ 213.0 Not practicable to estimate fair value 46.7 N/A 56.5 N/A Fixed-rate long-term debt 2,728.9 2,637.3 2,954.7 3,076.6 Redeemable preference stock - - 7.0 7.2 ConstellationEnergy Group Inc. and Subsidiaries

I "Note 12.

'..Auarterly Financial Data (Unaudited)

Our quarterly financial information has not been audited but, in management's opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations.

1999 Quarterly Data 1998 Quarterly Data Earnings Earnings Earnings Earnings Income Applicable Per Share Income Applicable Per Share From to Common of Common From to Common of Common Revenues Operations Stock Stock Revenues Operations Stock Stock (In millions, except per-shareamounts) (In millions, except per-share amounts)

Quarter Ended Quarter Ended March 31 $ 932.3 $198.1 $ 82.8 $0.55 March 31 $ 866.1 $183.4 $ 74.4 $0.50 June 30 820.0 163.9 68.0 0.45 June 30 767.6 156.2 57.4 0.39 September 30 970.4 277.7 136.1 0.91 September 30 934.0 320.4 160.9 1.08 December 31 1,063.5 120.2 (26.8) (0.18) December 31 790.4 81.1 13.2 0.09 Year Ended Year Ended December 31 $3,786.2 $759.9 $260.1 $1.74 December 31 $3,358.1 $741.1 $305.9 $2.06 Our second quarter results include a $3.6 million after-tax Our third quarter results include a $10.4 million after-tax gain write-down of a financial investment (see Note 3). for earnings in a partnership (see Note 3).

Our third quarter results include: Our fourth quarter results include:

- $7.5 million associated with Hurricane Floyd (see the "Electric Operations and Maintenance Expenses"

"*a $15.4 million after-tax write-off of a real estate investment (see Note 3), and section of Management's Discussion and Analysis),

. a $37.5 million deferral of revenues collected associated "*a $5.5 million after-tax write-off of an energy services "withthe deregulation of our electric generation business investment (see the "Other Energy Services" section (see Note 5), of Management's Discussion and Analysis).

  • a $17.3 million after-tax write-down of a financial investment (see Note 3),
  • a $6.7 million after-tax write-off of a power project (see Note 3), and
  • a $3.4 million after-tax write-down of certain senior-living facilities (see Note 2).

Our fourth quarter results include:

  • a $66.3 million extraordinary charge associated with the Restructuring Order (see Note 4),
  • the recognition of the $37.5 million of revenues that were deferred in the third quarter (see above),
  • $75 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order (see the "Electric Depreciation and Amortization Expense" section of Management's Discussion and Analysis),
  • a $4.9 million after-tax gain on a financial investment (see Note 3),
  • $12.0 million after-tax write-downs of certain power projects (see Note 3), and
  • a $2.4 million after-tax write-down of certain 3/4. senior-living facilities (see Note 2).

The sum of the quarterlyearningsper share amounts may not equal the totalfor the year due to the effects of rounding.

Constellation Energy Group Inc. and Subsidiaries

I SConstellation Energy Group Board of Directors*

Christian H. H. Furlong Douglas L. Becker James T. Brady Beverly B. Byron J. Owen Cole Poindexter Baldwin President and FormerSecretary, Former Director,AllFirst Chairman,President Co-ChiefExecutive MarylandDepartment Congresswoman, Financial,Inc. and Chairman,President and Chief Executive Officer, Sylvan of Business and U.S. House of AllFirst Bank and ChiefExecutive Officer, Mercantile Economic Representatives Age 70 Officer, Constellation Learning Systems, Inc.

Bankshares Age 34 Development Age 67 BGE Director from Energy Group Corporation BGE Director from Age 59 BGE Director from 1977-1999 Age 61 Age 68 1998-1999 Constellation 1993-1999 Elected April 1999 BGO Director since 1988 BGE Director from Elected April 1999 Enterprises Director Elected April 1999 Elected April 1999 1988-1999 from 1998-1999 Elected April 1999 Elected May 1999

-WA W Roger W. Gale Jerome W. Geckle Dr. Freeman A.

Dan A. Colussy Edward A. Crooke James R.

Curtiss, Esq. Presidentand Chief Retired Chairman, Hrabowski, III Former Chairman, Former Vice Partner,Winston Executive Officer, PHHCorporation President, University Presidentand Chief Chairman,

& Strawn PHB HaglerBailly Age 70 of Maryland Executive Officer, ConstellationEnergy Age 46 Age 53 BGE Director from Baltimore County UNC Incorporated Group; Former BGE Director from Constellation 1980-1999 Age 49 Age 68 Chairman,President, 1994-1999 Enterprises Director Elected April 1999 BGE Director from BGE Director from and Chief Executive Elected April 1999 from 1998-1999 1994-1999 1992-1999 Officer, Constellation Enterprises,Inc. Elected May 1999 Elected April 1999 Elected April 1999 Age 61 BGE Director from 1988-1999 Elected April 1999 Srm =X=

Michael D.

Nancy Lampton Charles R. Larson George V. George L. Mayo A.

McGowan t Russell, Jr., Esq. Shattuck, III Sullivan Chairmanand Chief Admiral, United States Navy (Retired) Former Chairman Attorney at Law, Co-Chairmanand Chairman,Golf Executive Officer, Age 63 and Chief Executive Law Offices of Co-ChiefExecutive America Stores, Inc.

American Life and Accident Insurance BGE Director from Officer, BGE PeterG. Angelos Officer, DB Alex. Brown, Age 60 Company of Kentucky 1998-1999 Age 72 Age 70 LLC andDeutsche Banc BGE Director from Elected April 1999 BGE Director from BGE Director from Securities, Inc. 1992-1999 Age 57 1980-1999 1988-1999 Age 45 Elected April 1999 BGE Director from 1994-1999 Elected April 1999 Elected April 1999 Constellation Enterprises Elected April 1999 Director from 1998-1999 Elected May 1999 I ConstellationEnergy Group Inc. and Subsidianes

I Committees of the Board N Constettation Energy Group Off icers Business Unit Leaders Audit Committee Christian H. Poindexter Frank 0. Heintz J. Owen Cole, Chairman Chairman, Presidentand President-Elect Douglas L. Becker Chief Executive Officer Baltimore Gas and Electric Co.

James T. Brady Age 61 Age 55 George L. Russell, Jr.

Thomas F.Brady Charles W.Shivery Committee on Management Vice President, Corporate President Jerome W. Geckle, Chairman Strategy & Development ConstellationPower Source, Inc.

J. Owen Cole Age 50 Age 54 Dan A. Colussy Mayo A. Shattuck, I1H David A. Bruane Robert E. Denton Michael D. Sullivan Vice President Finance& Accounting, President ChiefFinancialOfficer and Secretary ConstellationNuclear Group, LLC Committee on Nuclear Power Age 59 Age 57 James R. Curtiss, Chairman Beverly B. Byron Robert S. Fleishmnan John F. Walter Charles R. Larson Vice President, CorporateAffairs President George V. McGowan and GeneralCounsel Constellation Power, Inc.

Age 46 Age 65 Executive Committee George V. McGowan, Chairman Linda D. Miller William H. Munn H. Furlong Baldwin Vice President,Human Resources President James T. Brady Age 49 BGE Home Products & Services, Inc.

Edward A. Crooke Age 52 Dr. Freeman A. Hrabowski, III Richard . Bange, Jr.

Christian H. Poindexter Controller and Assistant Secretary Steven D. Kesler

-/ George L. Russell, Jr. Age 55 President ConstellationReal Estate Group, Inc.

Long-Range Strategy Committee Thomas E. Ruezin, Jr. ConstellationInvestments, Inc.

H. Furlong Baldwin, Chairman Treasurer andAssistant Secretary Age 48 Douglas L. Becker Age 45 Dan A. Colussy Gregory S. Jaroelnski Edward A. Crooke President James R. Curtiss ConstellationEnergy Source, Inc.

Roger W. Gale Age 47 Jerome W. Geckle Nancy Lampton Charles R. Larson Mayo A. Shattuck, HI Michael D. Sullivan Committee on Workplace Diversity Beverly B. Byron, Chairman Roger W. Gale Dr. Freeman A. Hrabowski, IH Nancy Lampton

  • The Board is divided into three classes with one class of directors elected at each annual shareholder meeting for a three-year term.

4 George V. McGowan will retire from the Board in April 2000.

ConstellationEnergy Group Inc. and Subsidiaries

FQ Five-Year Statistical Summary 1999 1998 1997 1996 1995 Common Stock Data QuarterlyEarningsPerShare First Quarter $0.55 $0.50 $0.43 $0.62 $0.41 0.45 0.39 0.05 0.36 0.28 Second Quarter 0.91 1.08 1.11 0.93 1.04 Third Quarter (0.18) 0.09 0.12 (0.06) 0.29 Fourth Quarter Total $1.74 $2.06 $1.72 $1.85 $2.02 Total EarningsPerShare Before NonrecurringCharges Includedin Operations $2.48 $2.20 $2.28 $2.27 $2.02 Dividends Dividends Declared Per Share $1.68 $1.67 $1.63 $1.59 $1.55 1.68 1.66 1.62 1.58 1.54 Dividends Paid Per Share Dividend Payout Ratio Reported 96.6% 81.1% 94.8% 85.9% 76.7%

Excluding nonrecurring charges to earnings 67.7% 75.9% 71.5% 70.0% 76.7%

Market Prices High $ 31'P $ 35', $ 34'/A6 $ 291/b $ 29 24"/16 29'/ 24'A 25 22 Low 34'A 261A 28'h Close 29 307A Capital Structure Consolidated 48.8% 53.5% 48.0% 45.0% 42.8%

Long-Term Debt 4.4 5.4 4.7 5.1 Short-Term Borrowings 2.7 2.9 4.8 6.5 8.5 BGE Preferred and Preference Stock 43.1 43.6 42.5 43.4 44.3 Common Shareholders' Equity Utility Only 40.4%

50.9% 51.5% 45.4% 42.5%

Long-Term Debt 2.4 5.8 6.1 5.2 Short-Term Borrowings 3.5 3.6 5.9 7.8 10.0 BGE Preferred and Preference Stock 44.4 43.2 44.9 42.9 43.6 Common Shareholders' Equity The sum of the quarterlyearningsper share amounts may not equal the totalfor the yeardue to the effects of roundingand changes in the average number of sharesoutstanding throughout the year.

The quarterlyearningsper share amounts include certain one-time adjustmentsas shown in Note 12 to the ConsolidatedFinancialStatements.

Constellation Energy Group Inc. and Subsidiaries

SShareho lder Information I Common Stock Dividends* and Price Ranges 1999 1998 Dividend Price Dividend Price Declared High Low Declared High Low First Quarter $ .42 $31% $2411/46 First Quarter $ .41 $34 X $29/4 Second Quarter .42 31 % 25X Second Quarter .42 325%6 29 1/4 Third Quarter .42 30X 273/6 Third Quarter .42 335/ 29'/16 Fourth Quarter .42 31 X 27% Fourth Quarter .42 35 X 30X Total $1.68 Total $1.67 Dividend* Policy Executive Offices The common stock is entitled to dividends when and as declared 250 W. Pratt Street by the Board of Directors. There are no limitations in any Baltimore, Maryland 21201 indenture or other agreements on payment of dividends. Mail: P.O. Box 1475, Baltimore, Maryland 21203-1475 Dividends have been paid on the common stock continuously since 1910. Future dividends depend upon future earnings, the Shareholder Investment Plan financial condition of the company, and other factors. Constellation Energy Group's Shareholder Investment Plan provides common shareholders an easy and economical way to Common Stock Dividend Dates acquire additional shares of common stock. The plan allows Record dates are normally on the 10th of March, June, September, shareholders to reinvest all or part of their common stock and December. Quarterly dividends are customarily mailed to each dividends; purchase additional shares of common stock; deposit shareholder on or about the 1st ofApril, July, October, and January. the common stock they hold into the plan; and request a transfer or sale of shares held in their accounts.

Stock Trading Constellation Energy Group's common stock, which is traded Stock Transfer Agents and Registrars under the ticker symbol CEG, is listed on the New York, Transfer Agent and Registrar:

__._. Chicago, and Pacific stock exchanges, and has unlisted trading Constellation Energy Group, Inc.

privileges on the Boston, Cincinnati, and Philadelphia Baltimore, Maryland exchanges. As of December 31, 1999, there were 66,093 Co-Transfer Agent and Registrar:

common shareholders of record. Harris Trust and Savings Bank Chicago, Illinois Annual Meeting The annual meeting of shareholders will be held at 10 a.m. on Shareholder Assistance and Inquiries Friday, April 28,2000, in the 2nd floor Conference Room of If you need assistance with lost or stolen stock certificates or the Gas and Electric Building, located at 39 W. Lexington St., dividend checks, name changes, address changes, stock transfers, Baltimore, Maryland 21201. the Shareholder Investment Plan, or other matters, you may contact our shareholder service representatives as follows:

Form 10-K Upon written request, the company will furnish, without By telephone (Monday-Friday,8 a.m. -4:45 p.m. EST):

charge, a copy of its and BGE's Annual Report on Form Baltimore Metropolitan Area 410-783-5920 10-K, including financial statements. Requests should be Within Maryland 1-800-492-2861 addressed to David A. Brune, Chief Financial Officer and Outside Maryland 1-800-258-0499 Secretary, Vice President, Finance & Accounting, 20th Floor, 250 W. Pratt St., Baltimore, Maryland 21201. By U.S. mail:

Constellation Energy Group, Inc.

Auditors Shareholder Services PricewaterhouseCoopers LLP P.O. Box 1642 Baltimore, MD 21203-1642 In person or by overnightdelivery:

  • Dividends paidprior to April 30, 1999 were on BGE Constellation Energy Group, Inc.

Shareholder Services, Room 820 common stock. As a result of the common stock share 39 W. Lexington Street

-.. _ exchange, Constellation Energy is the successor to BGE. Baltimore, MD 21201 ConstellationEnergy Group Inc. and Subsidiaries

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 1O-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended SEPTEMBER 30, 2000 Commission IRS Employer File Number Exact name of registrant as specified in its charter Identification No.

1-12869 CONSTELLATION ENERGY GROUP, INC. 524964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210 MARYLAND (State of Incorporation) 250 W. PRATT STREET, BALTIMORE, MARYLAND 21201 (Address of principal executive offices) (Zip Code) 410-234-5000 (Registrants' telephone number, including area code)

NOT APPLICABLE (Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) have been subject to such filing requirements for the past 90 days.

Yes X No Common Stock, without par value 150,531,716 shares outstanding of Constellation Energy Group, Inc. on October 31, 2000.

TABLE OF CONTENTS Lal Part I--Financial Information Item I - Financial Statements ConstellationEnergy Group, Inc. and Subsidiaries Consolidated Statements of Income ................................................................................................ 3 Consolidated Statements of Comprehensive Income ..................................................................... 3 Consolidated Balance Sheets ............................................................................................................. 4 Consolidated Statements of Cash Flows ........................................................................................... 6 Baltimore Gas and Electric Company and Subsidiaries Consolidated Statements of Income ................................................................................................ 7 Consolidated Statements of Comprehensive Income ................................... 7 Consolidated Balance Sheets ............................................................................................................. 8 Consolidated Statem ents of Cash Flows ........................................................................................... 10 Notes to Consolidated Financial Statements .................................................................................. II Item 2-- Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction ........................................................................................................................................ 18 Strategy ............................................................................................................................................... 19 Current Issues ..................................................................................................................................... 20 Results of Operations ......................................................................................................................... 24 Financial Condition ............................................................................................................................ 32 Capital Resources ............................................................................................................................... 33 Other M atters ...................................................................................................................................... 35 Item 3 - Quantitative and Qualitative Disclosures About M arket Risk ........................................................ 35 Part II Other Information Item 1 - Legal Proceedings .............................................................................................................................. 36 Item 5 -- Other Inform ation ............................................................................................................................... 37 Item 6 -- Exhibits and Reports on Form 8-K .................................................................................................... 38 Signature ............................................................................................................................................................... 39 2

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION Item 1 - Financial Statements Iionsolidated Statements of Income (Unaudited)

Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions, Except Per-ShareAmounts)

Revenues Nonregulated revenues $ 296.7 $ 258.9 $ 781.4 $ 782.2 Regulated electric revenues 598.2 691.2 1,688.0 1,737.2 Regulated gas revenues 86.7 60.1 372.8 332.7 Total revenues 981.6 1,010.2 2,842.2 2,852.1 Expenses Operating expenses 512.2 574.5 1,680.8 1,761.3 Depreciation and amortization 107.6 92.9 370.7 274.0 Taxes other than income taxes 46.4 65.1 158.8 177.2 Total expenses 666.2 732.5 2,210.3 2,212.5 Income From Operations 315.4 277.7 631.9 639.6 Other Income 0.9 1.2 7.0 5.7 Income Before Fixed Charges and Income Taxes 316.3 278.9 638.9 645.3 Fixed Charges Interest expense (net) 66.6 61.7 192.0 181.1 BGE preference stock dividends 3.3 3.4 9.9 10.2 Total fixed charges 69.9 65.1 201.9 191.3

'ncome Before Income Taxes 246.4 213.8 437.0 454.0

'4ncome Taxes Current 108.3 76.7 215.1 152.6 Deferred (7.3) 3.2 (31.0) 20.9 Investment tax credit adjustments (2.1) (2.2) (6.3) (6.4)

Total income taxes 98.9 77.7 177.8 167.1 Net Income $ 147.5 $ 136.1 $ 259.2 $ 286.9 Earnings Applicable to Common Stock $ 147.5 $ 136.1 $ 259.2 $ 286.9 Average Shares of Common Stock Outstanding 150.1 149.6 149.8 149.6 Earnings per Common Share and Earnings Per Common Share Assuming Dilution $0.98 $0.91 $1.73 $1.92 Dividends Declared Per Common Share $0.42 $0.42 $1.26 $1.26 Consolidated Statements of Comprehensive Income (Unaudited)

Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions)

Net Income $ 147.5 $ 136.1 $ 259.2 $ 286.9 Other comprehensive income (loss), net of taxes 17.7 5.0 41.8 (6.5)

Comprehensive Income $ 165.2 $ 141.1 $ 301.0 $ 280.4

,;,.ee Notes to ConsolidatedFinancialStatements.

Certain priorperiod amounts have been reclassified to conform with the current period'spresentation.

3

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)

Item 1 - Financial Statements Consolidated Balance Sheets September 30, December 31, 2000* 1999 (In Millions)

Assets Current Assets Cash and cash equivalents $ 50.4 $ 92.7 Accounts receivable (net of allowance for uncollectibles of $25.5 and $36.6 respectively) 842.1 578.5 Trading securities 180.2 136.5 Assets from energy trading activities 1,573.7 312.1 Fuel stocks 101.9 94.9 Materials and supplies 155.6 149.1 Prepaid taxes other than income taxes 140.2 72.4 Other 36.4 54.0 Total current assets 3,080.5 1,490.2 Investments and Other Assets Real estate projects and investments 296.4 310.1 Investments in power projects 538.8 547.3 Financial investments 192.2 145.4 Nuclear decommissioning trust fund 235.0 217.9 Net pension asset 97.2 99.5 Investment in Orion Power Holdings, Inc. 232.1 105.7 Other 120.4 154.3 Total investments and other assets 1,712.1 1,580.2 Property, Plant and Equipment Regulated property, plant and equipment:

Plant in service 4,746.0 8,620.1 Construction work in progress 68.8 222.3 Plant held for future use 9.7 13.0 Total regulated property, plant and equipment 4,824.5 8,855.4 Nonregulated generation property, plant and equipment 4,906.5 341.3 Other nonregulated property, plant and equipment 165.1 152.7 Nuclear fuel (net of amortization) 137.4 133.8 Accumulated depreciation (3,745.6) (3,559.1)

Net property, plant and equipment 6,287.9 5,924.1 Deferred Charges Regulatory assets (net) 514.2 637.4 Other 61.3 51.9 Total deferred charges 575.5 689.3 Total Assets $ 11,656.0 $ 9,683.8

  • Unaudited See Notes to ConsolidatedFinancialStatements.

Certain priorperiod amiounts have been reclassifiedto confbrin with the currentperiod's presentation.

4

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)

Item 1 - Financial Statements Consolidated Balance Sheets September 30, December 31, 2000* 1999 (In Millions)

Liabilities and Capitalization Current Liabilities Short-term borrowings $ 505.0 $ 371.5 Current portion of long-term debt 660.9 808.3 Accounts payable 693.7 365.1 Liabilities from energy trading activities 1,260.6 163.8 Dividends declared 66.2 66.1 Accrued taxes 90.8 19.2 Other 206.8 209.4 Total current liabilities 3,484.0 2,003.4 Deferred Credits and Other Liabilities Deferred income taxes 1,273.9 1,288.8 Postretirement and postemployment benefits 261.7 269.8 Deferred investment tax credits 103.4 109.6 Other 355.7 253.8 Total deferred credits and other liabilities 1,994.7 1,922.0 Long-term Debt First refunding mortgage bonds of BGE 1,174.7 1,321.7 Other long-term debt of BGE 603.6 1,135.8 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 250.0 250.0 Long-term debt of nonregulated businesses 1,477.2 686.8 Unamortized discount and premium (9.3) (10.6)

Current portion of long-term debt (660.9) (808.3)

Total long-term debt 2,835.3 2,575.4 BGE Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholders' Equity Common stock 1,540.9 1,494.0 Retained earnings 1,569.4 1,499.1 Accumulated other comprehensive income (loss) 41.7 (0.1)

Total common shareholders' equity 3,152.0 2,993.0 Total capitalization 6,177.3 5,758.4 Total Liabilities and Capitalization $ 11,656.0 $ 9,683.8

  • Unaudited See Notes to ConsolidatedFinancialStatements.

Certain priorperiod amounts have been reclassifiedto con fbrin with the currentperiod's presentation.

5

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)

Item 1 - Financial Statements Consolidated Statements of Cash Flows (Unaudited)

Nine Months Ended September 30, 2000 1999 (In Millions)

Cash Flows From Operating Activities Net income $ 259.2 S 286.9 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 411.1 316.2 Deferred income taxes (31.0) 20.9 Investment tax credit adjustments (6.3) (6.4)

Deferred fuel costs 11.0 (51.2)

Accrued pension and postemployment benefits 18.1 35.5 Gain on sale of subsidiaries (13.3)

Write-down of real estate investment 5.2 Write-down of financial investment 33.8 Write-off of power project 10.2 Equity in earnings of affiliates and joint ventures (net) (6.3) 22.4 Changes in assets from energy trading activities (1,261.6) (74.1)

Changes in liabilities from energy trading activities 1,096.8 (12.3)

Changes in other current assets (243.3) (355.5)

Changes in other current liabilities 270.1 234.8 Other 84.3 17.1 Net cash provided by operating activities 588.8 483.5 Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures (626.9) (351.9)

Contributions to nuclear decommissioning trust fund (13.5) (13.2)

Purchases of marketable equity securities (36.3) (17.2)

Sales of marketable equity securities 39.6 12.5 Other financial investments 10.4 15.1 Real estate projects and investments 9.3 46.2 Power projects investments (14.9) (11.0)

Investment in Orion Power Holdings, Inc. (101.5) (97.7)

Other 5.4 (24.6)

Net cash used in investing activities (728.4) (441.8)

Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 7,883.8 2,412.2 Long-term debt 803.0 289.7 Common stock 35.9 9.5 Repayments of short-term borrowings (7,750.3) (2,269.1)

Reacquisitions of long-term debt (691.8) (399.6)

Redemption of preference stock (7.0)

Common stock dividends paid (188.5) (188.3)

Other 5.2 (6.4)

Net cash provided by (used in) financing activities 97.3 (159.0)

Net Decrease in Cash and Cash Equivalents (42.3) (117.3)

Cash and Cash Equivalents at Beginning of Period 92.7 173.7 Cash and Cash Equivalents at End of Period $ 50.4 S 56.4 Other Cash Flow Information:

Interest paid (net of amounts capitalized) $ 205.0 S 174.9 Income taxes paid $ 136.1 $ 102.2 See Notes to ConsolidatedFinancialStatements.

Certain priorperiod amounts have been reclassifledto conjorm with the currentperiod'spresentation.

6

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I - FINANCIAL INFORMATION Item I - Financial Statements Consolidated Statements of Income (Unaudited)

Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions)

Revenues Electric Revenues $ 598.4 $ 691.4 $1,688.4 $ 1,737.5 Gas Revenues 90.1 62.9 377.8 337.3 Nonregulated Revenues 1.5 1.7 3.9 346.7 Total revenues 690.0 756.0 2,070.1 2,421.5 Operating Expenses Electric fuel and purchased energy 388.3 130.0 632.4 375.3 Gas purchased for resale 48.2 21.3 192.0 156.4 Operations and maintenance 88.0 167.1 457.5 539.2 Nonregulated - selling, general, and administrative 1.0 1.1 2.8 285.3 Depreciation and amortization 63.8 89.0 313.6 267.5 Taxes other than income taxes 35.7 64.2 146.2 175.6 Total operating expenses 625.0 472.7 1,744.5 1,799.3 Income From Operations 65.0 283.3 325.6 622.2 Other Income Allowance for equity funds used during constructiot 0.6 1.5 2.1 5.2 Equity in earnings of Safe Harbor Water Power Corporation 1.2 2.4 3.8 Net other income (expense) 3.7 (0.5) 5.4 (3.6)

Total other income 4.3 2.2 9.9 5.4 Income Before Fixed Charges and Income Taxes 69.3 285.5 335.5 627.6 Fixed Charges Interest expense (net) 45.3 48.1 142.2 162.3 Capitalized interest (0.4)

Allowance for borrowed funds used during construction (0.3) (0.8) (2.9) (2.8)

Total fixed charges 45.0 47.3 139.3 159.1 Income Before Income Taxes 24.3 238.2 196.2 468.5 Income Taxes Current 17.9 80.5 119.8 169.1 Deferred (6.3) 4.9 (38.8) 3.5 Investment tax credit adjustments (0.6) (2.1) (4.7) (6.4)

Total income taxes 11.0 83.3 76.3 166.2 Net Income 13.3 154.9 119.9 302.3 Preference Stock Dividends 3.3 3.4 9.9 10.2 Earnings Applicable to Common Stock $ 10.0 $ 151.5 $ 110.0 $ 292.1 Consolidated Statements of Comprehensive Income (Unaudited)

Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions)

Net Income $ 13.3 $ 154.9 $ 119.9 $ 302.3 Other comprehensive loss, net of taxes - (3.4)

-. Comprehensive Income $ 13.3 $ 154.9 $ 119.9 $ 298.9 See Notes to ConsolidatedFinancialStatements.

Certain priorperiodamounts have been reclassifiedto conform with the current period's presentatton.

7

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)

Item 1 - Financial Statements Consolidated Balance Sheets September 30, December 3 1, 2000* 1999 (In Millions)

Assets Current Assets Cash and cash equivalents 16.9 $ 23.5 Accounts receivable (net of allowance for uncollectibles of $13.9 and $13.0 respectively) 389.2 316.1 Notes receivable, affilated company 87.0 Fuel stocks 56.9 94.9 Materials and supplies 38.8 139.1 Prepaid taxes other than income taxes 108.5 72.4 Other 8.0 9.0 Total current assets 705.3 655.0 Investments and Other Assets Nuclear decommissioning trust fund 217.9 Net pension asset 103.8 99.8 Safe Harbor Water Power Corporation 34.5 Other 63.0 61.6 Total investments and other assets 166.8 413.8 Utility Plant Plant in service Electric 3,234.3 7,088.6 Gas 983.1 962.0 Common 528.6 569.5 Total plant in service 4,746.0 8,620.1 Accumulated depreciation (1,674.9) (3,466.1)

Net plant in service 3,071.1 5,154.0 Construction work in progress 68.8 222.3 Nuclear fuel (net of amortization) 133.8 Plant held for future use 9.7 13.0 Net utility plant 3,149.6 5,523.1 Deferred Charges Regulatory assets (net) 514.2 637.4 Other 39.1 43.3 Total deferred charges 553.3 680.7 Total Assets $ 4,575.0 $ 7,272.6

  • Unaudited See Notes to ConsolidatedFinancialStatements.

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BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)

Item 1 - Financial Statements Consolidated Balance Sheets September 30, December 31, 2000* 1999 (In Millions)

Liabilities and Capitalization Current Liabilities Short-term borrowings $ 258.0 $ 129.0 Current portion of long-term debt 309.7 523.9 Accounts payable 336.7 222.8 Customer deposits 43.7 40.6 Dividends declared 3.3 3.3 Accrued taxes 11.4 9.2 Accrued interest 36.4 48.2 Accrued vacation costs 22.7 35.7 Other 20.1 65.8 Total current liabilities 1,042.0 1,078.5 Deferred Credits and Other Liabilities Deferred income taxes 507.0 1,032.0 Postretirement and postemployment benefits 250.6 231.0 Deferred investment tax credits 25.6 109.6 Decommissioning of federal uranium enrichment facilities 27.2 27.2 Other 24.7 42.9 Total deferred credits and other liabilities 835.1 1,442.7 Long-term Debt First refunding mortgage bonds of BGE 1,174.7 1,321.7 Other long-term debt of BGE 603.6 1,135.8 Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 250.0 250.0 Long-term debt of nonregulated businesses 33.0 33.0 Unamortized discount and premium (7.1) (10.6)

Current portion of long-term debt (309.7) (523.9)

Total long-term debt 1,744.5 2,206.0 Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 454.2 1,494.0 Retained earnings 309.2 861.4 Total common shareholder's equity 763.4 2,355.4 Total capitalization 2,697.9 4,751.4 Total Liabilities and Capitalization $ 4,575.0 $ 7,272.6

  • Unaudited See Notes to ConsolidatedFinancialStatements.

9

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I - FINANCIAL INFORMATION (CONTINUED)

Item I - Financial Statements Consolidated Statements of Cash Flows (Unaudited)

Nine Months Ended September 30, 2000 1999 (In Millions)

Cash Flows From Operating Activities Net income $ 119.9 $ 302.3 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 338.2 307.6 Deferred income taxes (38.8) 3.6 Investment tax credit adjustments (4.7) (6.4)

Deferred fuel costs 11.0 (51.2)

Accrued pension and postemployment benefits 14.9 35.0 Allowance for equity funds used during construction (2.1) (5.2)

Equity in earnings of affiliates and joint ventures (net) 1.2 29.0 Changes in assets from energy trading activities (120.1)

Changes in liabilities from energy trading activities 76.3 Changes in other current assets (127.0) (73.2)

Changes in other current liabilities 158.1 41.9 Other 5.2 32.5 Net cash provided by operating activities 475.9 572.1 Cash Flows From Investing Activities Utility construction expenditures (including AFC) (241.0) (246.1)

Allowance for equity funds used during construction 2.1 5.2 Nuclear fuel expenditures (39.5) (45.0)

Deferred energy conservation expenditures (0.5) (0.9)

Contributions to nuclear decommissioning trust fund (8.8) (13.2)

Purchases of marketable equity securities (9.2)

Sales of marketable equity securities 6.0 Other financial investments 6.7 Real estate projects and investments 22.0 Power projects investments (17.9)

Other (5.5) (16.7)

Net cash used in investing activities (293.2) (309.1)

Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 3,655.0 1,608.3 Long-term debt 257.2 Common stock 9.5 Repayments of short-term borrowings (3,526.0) (1,585.8)

Reacquisition of long-term debt (121.7) (375.3)

Redemption of preference stock (7.0)

Preference stock dividends paid (9.9) (10.3)

Distributions to Constellation Energy (188.5) (316.5)

Other 1.8 (1.3)

Net cash used in financing activities (189.3) (421.2)

Net Decrease in Cash and Cash Equivalents (6.6) (158.2)

Cash and Cash Equivalents at Beginning of Period 23.5 173.7 Cash and Cash Equivalents at End of Period $ 16.9 $ 15.5 Other Cash Flow Information:

Interest paid (net of amounts capitalized) $ 147.0 $ 155.0 Income taxes paid $ 111.5 $ 99.4 Non-Cash Transactions On July 1, 2000, BGE transferred $1,578.4 million of generation assets net of associated liabilities to affiliates of Constellation Energy pursuant to the Maryland PSC's Restructuring Order.

See Notes to ConsolidatedFieiancialStatements.

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Notes to Consolidated Financial Statements Weather conditions can have a great impact on our results Restructuring Order further in Management's Discussion for interim periods. This means that results for interim and Analysis beginning on page 18. Please also refer to the periods do not necessarily represent results to be expected Legal Proceedings section on page 36 for a discussion for the year. regarding appeals of the Restructuring Order.

Our interim financial statements on the previous pages Subsequent Event reflect all adjustments that Management believes are On October 23, 2000, we announced three initiatives to necessary for the fair presentation of the financial position advance our growth strategies. The first initiative is that and results of operations for the interim periods presented. we entered into an agreement (the "Agreement") with an These adjustments are of a normal recurring nature. affiliate of The Goldman Sachs Group, Inc. ("Goldman Sachs"). Under the terms of the Agreement, Goldman Holding Company Formation Sachs will acquire up to a 17.5% equity interest in our On April 30, 1999, Constellation Energy Group, Inc. domestic merchant energy business, which will be (Constellation Energy) became the holding company for consolidated under a single holding company ("Holdco").

Baltimore Gas and Electric Company (BGE) and Goldman Sachs will also acquire a ten-year warrant for up Constellation Enterprises, Inc. Constellation Enterprises to 13% of Holdco's common stock (subject to certain was previously owned by BGE. BGE's outstanding adjustments). The warrant is exercisable six months after common stock automatically became shares of common Holdco's common stock becomes publicly available. The stock of Constellation Energy. BGE's debt securities, amount of common stock which Goldman Sachs may obligated mandatorily redeemable trust preferred securities, receive upon exercise will be equal to the excess of the and preference stock remain securities of BGE. market price of Holdco's common stock at the time of exercise over the exercise price of $60 per share for all the Basis of Presentation stock subject to the warrant, divided by the market price.

This Quarterly Report on Form I0-Q is a combined report Holdco may at its option pay Goldman Sachs such excess of Constellation Energy and BGE. The consolidated in cash. Goldman Sachs is acquiring its interest and the financial statements of Constellation Energy include the warrant in exchange for $250 million in cash (subject to accounts of Constellation Energy, BGE and its adjustment in certain instances) and certain assets related subsidiaries, Constellation Enterprises, Inc. and its to our power marketing business. At closing, Goldman subsidiaries, and Constellation Nuclear, LLC and its Sachs' existing services agreement with our power subsidiaries. The consolidated financial statements of marketing business will terminate.

BGE include the accounts of BGE, District Chilled Water General Partnership (ComfortLink), and BGE Capital The second initiative is a plan to separate our domestic Trust I. As Constellation Enterprises and its subsidiaries merchant energy business from our retail services were subsidiaries of BGE prior to April 30, 1999, they are business. The separation will create two stand-alone, included in the consolidated financial statements of BGE publicly traded energy companies. One will be a merchant through that date. energy business engaged in wholesale power marketing and generation under the name "Constellation Energy References in this report to "we" and "our" are to Group" after the separation. The other will be a regional Constellation Energy and its subsidiaries, collectively. retail energy and energy services company, BGE Corp.,

Reference in this report to the "utility business" is to BGE. that will include BGE and other subsidiaries.

Deregulation of Electric Generation The third initiative is a change in our common stock On April 8, 1999, Maryland enacted legislation authorizing dividend policy effective April 2001. We will maintain customer choice and competition among electric suppliers. our current common stock dividend through January In addition, on November 10, 1999, the Maryland Public 2001. In a move closely aligned with our separation plan, Service Commission (Maryland PSC) issued a Restructuring effective April 2001, our annual dividend is expected to Order that resolved the major issues surrounding electric be set at $.48 per share. After the business separation, restructuring. Effective July 1, 2000, the state of Maryland BGE Corp. expects to pay initial annual dividends of $.48 implemented customer choice for electric suppliers. We per share. Constellation Energy Group, as a growing discuss the implications of customer choice and the merchant energy company, expects to initially reinvest its earnings and not pay a dividend in order to fund its aggressive growth plans.

11

The closing of the transaction with Goldman Sachs and certain tax matters. Both are expected to be completed by the separation are subject to customary closing conditions, mid to late 2001.

including regulatory approvals and the receipt of a Private Letter Ruling from the Internal Revenue Service regarding We discuss these strategic initiatives further in our Report on Form 8-K and exhibits filed October 23, 2000.

Information by Operating Segment In 1999, we reported three operating business segments We have restated certain prior period information for

- Electric, Gas, and Energy Services. In response to the comparative purposes based on our new reportable deregulation of electric generation, we realigned our operating segments.

organization and combined our wholesale power marketing business with our domestic plant development Effective July 1, 2000, the financial results of the electric and operations to form a domestic merchant energy generation portion of our business are included in the domestic merchant energy business segment. Prior to that business.

date, the financial results of electric generation are In the first quarter of 2000, we revised our operating included in our regulated electric business.

segments to reflect the realignments of our organization.

Our remaining nonregulated businesses:

Our new reportable operating segments are - Domestic Merchant Energy, Regulated Electric, and Regulated ", develop, own, and operate international power Gas: projects in Latin America,

"*provide energy products and services,

" Our nonregulated domestic merchant energy business:

"* sell and service electric and gas appliances, and heating and air conditioning systems, engage in

- provides power marketing and risk home improvements, and sell electricity and natural management services, gas through mass marketing efforts,

- develops, owns, and operates domestic power projects, and

"* provide cooling services,

- provides nuclear consulting services. "*engage in financial investments, and

"* develop, own and manage real estate and senior

"* Our regulated electric business purchases and living facilities.

distributes electricity, and

"* Our regulated gas business purchases, transports, and sells natural gas.

Domestic Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated For the three months ended September 30, (in millions) 2000 Unaffiliated revenues $127.9 $ 598.2 $ 86.7 $ 168.8 $(0 $ 981.6 intersegment revenues 367.7 0.1 3.4 19.0 (390.2)

Total revenues 495.6 598.3 90.1 187.8 (390.2) 981.6 Net income (loss) 130.9 15.4 (4.6) 5.8 147.5 1999 Unaffiliated revenues $66.3 S 691.2 $ 60.1 $192.6 S 1 $1,010.2 Intersegment revenues 0.2 2.8 14.5 (17.5)

Total revenues 66.3 691.4 62.9 207.1 (17.5) 1,010.2 Net income (loss) (a) 12.2 152.3 (0.7) (27.7) 136.1 12

Domestic Unallocated Merchant Regulated Regulated Other Corporate Energy Electric Gas Nonregulated Items and Business Business Business Businesses Eliminations Consolidated For the nine months ended September 30, (in millions) 2000 Unaffiliated revenues $ 261.3 $1,688.0 $372.8 $520.1 $ $ 2,842.2 Intersegment revenues 367.6 0.4 5.0 37.3 (410.3)

Total revenues 628.9 1,688.4 377.8 557.4 (410.3) 2,842.2 Net income (loss) (b) 150.2 93.2 18.1 (2.3) 259.2 1999 Unaffiliated revenues $173.3 $1,737.2 $ 332.7 $608.9 I - $2,852.1 Intersegment revenues 0.4 0.7 7.4 26.2 (34.7)

Total revenues 173.7 1,737.9 340.1 635.1 (34.7) 2,852.1 Net income (loss) (a) 43.6 253.4 21.5 (31.6) 286.9 At September 30, 2000 Segment assets $6,098.8 $3,427.0 $1,104.8 $1,298.8 $ (273.4) $11,656.0 At December 31, 1999 Segment assets $1,206.1 $6,312.6 $915.3 $1,231.3 $18.5 $9,683.8 (a) Our electric business recordedexpense of $4.9 millionfor the three months and nine months ended September 30, 1999 related to HurricaneFloyd Ourpower projects business recorded$6.7 millionfor the three months andnine months ended September 30, 1999for the write-offofa geothermalpower plant. Ourfinancialinvestments business recordedexpense of $17. 3 millionfor the three months and $20.9 millionfor the nine months endedSeptember 30, 1999for the write-down of its investment in CapitalRe stock. Our realestate and senior-livingfacilitiesbusiness recordedexpense of $3.4 millionfor the three months and nine months ended September 30, 1999for a write-down of certainsenior-livingfacilities.

(b) Our electric business recordedexpense of $4.2 millionfor the nine months endedSeptember 30, 2000 relatedto employees that elected to participatein a Targeted Voluntary SpecialEarly Retirement Program. In addition, our domestic merchant energy business recordeda $15. 0 million deregulation transitioncost incurredby our power marketing business. We discuss thesefiurther in the Overview section of Management'sDiscussion andAnalysis.

Financing Activity Constellation Energy As discussed on page 11, effective April 30, 1999, In June 2000, Constellation Energy arranged two BGE's outstanding common stock automatically became revolving credit agreements totaling $565.0 million to shares of common stock of Constellation Energy. During support our commercial paper program and for other the period from January 1,2000 through the date of this working capital purposes. Of this amount, $376.5 million report, we issued a total of 975,300 shares of common is for short-term financial needs and $188.5 million, stock, without par value, under our Continuous Offering which expires in three years, is for short and long-term Program for Stock. Net proceeds were about $35.9 financial needs, including letters of credit. As of the date million. of this report, letters of credit totaling $112.5 million were issued under this facility. Also, letters of credit totaling $12.0 million were issued under other credit Constellation Energy issued the following long-term facilities.

notes during the period from January 1, 2000 through the date of this report: Constellation Energy has issued guarantees in an amount Date Net up to $617.3 million related to credit facilities and Principal Issued Proceeds contractual performance of certain of its nonregulated (in millions) subsidiaries. However, the actual subsidiary liabilities 7 7/8% Notes due 2005 $300 4/00 $297.5 related to these guarantees totaled $343.3 million at Floating Rate Notes due 2003 200 4/00 199.3 September 30, 2000.

Extendible Notes due 2010 300 6/00 299.6 Floating Rate Reset Notes due 2002 200 10/00 199.6 13

In connection with the initiative to separate our domestic Commitments merchant energy business from our retail services Some of our nonregulated businesses have committed to business, Constellation Energy expects to redeem all of contribute additional capital and to make additional loans its currently outstanding $1.0 billion debt at or prior to to some affiliates, joint ventures, and partnerships in the separation. The redemption will occur through a which they have an interest. At the date of this report, the combination of open market purchases, tender offers, and total amount of investment requirements committed to by redemption calls. our nonregulated businesses was $218.0 million.

BGE and Nonregulated Businesses Environmental Matters In October 2000, BGE issued $200.0 million of Floating Clean Air Rate Reset Notes due in 2001 with net proceeds of The Clean Air Act of 1990 contains two titles designed

$199.8 million. to reduce emissions of sulfur dioxide and nitrogen oxide In June 2000, BGE arranged a $25.0 million long-term (NOx) from electric generating stations - Title IV and Title I.

revolving credit agreement to support its commercial paper program and for other working capital purposes. Title IV addresses emissions of sulfur dioxide.

In conjunction with the July 1,2000 transfer of Compliance is required in two phases:

generation assets, BGE is contingently liable for $278.0 " Phase I became effective January 1, 1995. We met million of the tax exempt debt assigned to nonregulated the requirements of this phase by installing flue gas affiliates of Constellation Energy as discussed further in desulfurization systems, switching fuels, and retiring the CurrentIssues -Electric Competitionsection of some units.

Management's Discussion and Analysis on page 20.

" Phase 11 became effective January 1, 2000. We met In the future, BGE may purchase some of its long-term the compliance requirements through a combination debt or preference stock in the market. This will depend of switching fuels and allowance trading.

on market conditions and BGE's capital structure, including the mix of secured and unsecured debt. We will meet the ongoing compliance requirements through a combination of switching fuels and allowance Please refer to the FundingforCapitalRequirements trading.

section of Management's Discussion and Analysis on page 34 for additional information about the debt of Title I addresses emissions of NOx. The Maryland BGE and our nonregulated businesses. Department of the Environment (MDE) issued regulations, effective October 18, 1999, which required Stock Option Program up to 65% NOx emissions reductions by May 1, 2000.

In May 2000, our Board of Directors approved the We entered into a settlement agreement with the MDE issuance of non-qualified stock options to officers and since we could not meet this deadline. Under the terms key employees as permitted under existing incentive of the settlement agreement, BGE will install emissions plans. Under the plans, the options are granted at prices reduction equipment at two sites by May 2002. In the not less than the market value of the stock at the date of meantime, we are taking steps to control NOx emissions grant, generally become exercisable ratably over a three at our generating plants.

year period beginning one year from the date of grant, and expire ten years from the date of grant. During the The Environmental Protection Agency (EPA) issued a second quarter, we granted 2,313,000 stock options at an final rule in September 1998 that required up to 85%

exercise price of $34.25. NOx emissions reduction by 22 states including Maryland and Pennsylvania. Maryland expects to meet As permitted by SFAS No. 123, Accountingfor Stock the requirements of the rule by 2003. The emissions Based Compensation,we measure our stock-based reduction equipment installations discussed above will compensation in accordance with Accounting Principles allow us to meet these requirements.

Board Opinion No. 25, Accountingfor Stock Issued to Employees, and related interpretations. Under this standard, compensation expense is measured as the difference between the market value of our common stock and the exercise price of the options on the grant date. Accordingly, no compensation expense was recorded for the stock options granted in 2000.

14

We currently estimate that the controls needed at our On July 12, 1999, the EPA notified us, along with generating plants to meet the MDE's 65% NOx emission nineteen other entities, that we may be a potentially reduction requirements will cost approximately $135 responsible party at the 6 8 " Street Dump/Industrial million. Through the date of this report, we have spent Enterprises Site, also known as the Robb Tyler Dump approximately $82.6 million to meet the 65% reduction located in Baltimore, Maryland. The EPA indicated that requirements. We estimate the additional cost for the it is proceeding with plans to conduct a remedial EPA's 85% reduction requirements to be approximately investigation and feasibility study. This site was

$35 million by the end of 2002. proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized.

In July 1997, the EPA published new National Ambient Although our potential liability cannot be estimated, we Air Quality Standards for very fine particulates and do not expect such liability to be material based on our revised standards for ozone attainment. In 1999, these records showing that we did not send waste to the site.

new standards were successfully challenged in court.

The EPA appealed the 1999 court rulings to the Supreme Also, we are coordinating investigation of several sites Court. In May 2000, the Supreme Court decided to hear where gas was manufactured in the past. The the EPA's appeal. While these standards may require investigation of these sites includes reviewing possible increased controls at our fossil generating plants in the actions to remove coal tar. In late December 1996, we future, implementation, if required, would be delayed for signed a consent order with the MDE that requires us to several years. We cannot estimate the cost of these implement remedial action plans for contamination at increased controls at this time because the states, and around the Spring Gardens site, located in Baltimore, including Maryland and Pennsylvania, still need to Maryland. We submitted the required remedial action determine what reductions in pollutants will be necessary plans and they were approved by the MDE. Based on the to meet the EPA standards. remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to On August 3, 2000, we received letters from the EPA total $47 million. We have recorded these costs as a requesting us to provide certain information under liability on our Consolidated Balance Sheets and have Section 114 of the federal Clean Air Act regarding some deferred these costs, net of accumulated amortization and of our electric generating plants. This information is to amounts we recovered from insurance companies, as a determine compliance with the Clean Air Act and state regulatory asset. Because of the results of studies at these implementation plan requirements, including potential sites, it is reasonably possible that these additional costs application of federal New Source Performance could exceed the amount we recognized by Standards. In general, such standards can require the approximately $14 million. We discuss this further in installation of additional air pollution control equipment Note 5 of our 1999 Annual Report on Form 10-K.

upon the major modification of an existing plant. We Through the date of this report, we have spent believe our generating plants have been operated in approximately $35 million for remediation at this site.

accordance with the Clean Air Act and the rules implementing the Clean Air Act. However, we cannot We do not expect the cleanup costs of the remaining sites estimate the impact of this inquiry on our generating to have a material effect on our financial results.

plants, and our financial results, at this time.

Our potential environmental liabilities and pending Waste Disposal environmental actions are described further in our 1999 The EPA and several state agencies have notified us that Annual Report on Form I 0-K in Item 1. Business we are considered a potentially responsible party with Environmental Matters.

respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We Nuclear Insurance cannot estimate the cleanup costs for all of these sites. If there were an accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant (Calvert We can, however, estimate that our current 15.43% share Cliffs), it could have a substantial adverse financial effect of the reasonably possible cleanup costs at one of these on us. The primary contingencies that would result from sites, Metal Bank of America, a metal reclaimer in an incident at Calvert Cliffs could include:

Philadelphia, could be as much as $4.9 million higher than amounts we have recorded as a liability on our "* physical damage to the plant, Consolidated Balance Sheets. This estimate is based on a "* recoverability of replacement power costs, and Record of Decision issued by the EPA. "* our liability to third parties for property damage and bodily injury.

15

We have insurance policies that cover these All nuclear worker claims reported prior to January 1, contingencies, but the policies have certain industry 1998 are still covered by the old insurance policies.

standard exclusions. Furthermore, the costs that could Insureds under the old policies, with no current result from a covered major accident or a covered operations, are not required to purchase the new extended outage at either of the Calvert Cliffs units could policy described above, and may still make claims exceed our insurance coverage limits. against the old policies for the next eight years. If radiation injury claims under these old policies Insurancefor Calvert Cliffs and Third Party exceed the policy reserves, all policyholders could be Claims assessed, with our share being up to $6.3 million.

For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual If claims under these polices exceed the coverage limits, insurance company. If an outage at either of the two units the provisions of the Price Anderson Act (discussed in at Calvert Cliffs is caused by an insured physical damage this section) would apply.

loss and lasts more than 12 weeks, we have insurance coverage for replacement power costs up to $490.0 Recoverability of Electric Fuel Costs million per unit, provided by an industry mutual Under the terms of the Restructuring Order, BGE's insurance company. This amount can be reduced by up electric fuel rate clause was discontinued effective to $98.0 million per unit if an outage at both units of the July 1, 2000. In September 2000, the Maryland PSC plant is caused by a single insured physical damage loss. approved the collection of the $54.6 million accumulated If accidents at any insured plants cause a shortfall of difference between our actual costs of fuel and energy funds at the industry mutual insurance company, all and the amounts collected from customers that were policyholders could be assessed, with our share being up deferred (included as an asset or liability on the to $15.4 million. Consolidated Balance Sheets and excluded from the Consolidated Statements of Income) under the electric In addition we, as well as others, could be charged for a fuel rate clause through June 30, 2000. We will collect portion of any third party claims associated with a this accumulated difference from customers over a nuclear incident at any commercial nuclear power plant twelve-month period beginning October 2000.

in the country. At the date of this report, the limit for third party claims from a nuclear incident is $9.54 billion California Power Purchase Agreements under the provisions of the Price Anderson Act. If third Constellation Power, Inc. and subsidiaries and party claims exceed $200 million (the amount of primary Constellation Investments, Inc. (whose power projects insurance), our share of the total liability for third party are managed by Constellation Power) have $297.6 claims could be up to $176.2 million per incident. That million invested in 14 projects that sell electricity in amount would be payable at a rate of $20 million per California under power purchase agreements called year. "Interim Standard Offer No. 4" agreements. Under these agreements, the projects supply electricity to utility Insurancefor Worker Radiation Claims companies at:

As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance " a fixed rate for capacity and energy for the first 10 to cover radiation injury claims of certain nuclear years of the agreements, and workers. On January 1, 1998, a new insurance policy " a fixed rate for capacity plus a variable rate for became effective for all operators requiring coverage for energy based on the utilities' avoided cost for the current operations. Waiving the right to make additional remaining term of the agreements.

claims under the old policy was a condition for acceptance under the new policy. We describe both the Generally, a "capacity rate" is paid to a power plant for old and new policies below. its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided Nuclear worker claims reported on or after cost" generally is the cost of a utility's cheapest next January 1, 1998 are covered by a new insurance available source of generation to service the demands on policy with an annual industry aggregate limit of its system.

$200 million for radiation injury claims against all those insured by this policy. We use the term "transitioned" to describe when the 10 year periods for fixed energy rates have expired for these power generation projects and they began supplying electricity at variable rates. The two remaining projects that have not transitioned will do so by December 2000.

16

The projects that have already transitioned to variable In addition, BGE receives charges from Constellation rates have had lower revenues under variable rates than Energy for certain corporate functions. Certain costs are they did under fixed rates. Once the remaining projects directly assigned to BGE. We allocate other corporate have transitioned to variable rates, we expect the function costs based on a total percentage of expected revenues from those projects also to be lower than they use by BGE. Management believes this method of are under fixed rates. allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs We discuss these projects on page 26 of Management's were $9.6 million for the quarter and $16.9 million for Discussion and Analysis. the nine months ending September 30, 2000. These costs were not material in 1999 due to the transfer of certain Other Nonregulated Businesses BGE employees to the holding company during that In September 2000, our real estate and senior-living year.

facilities business converted 984,307 preferred shares of Corporate Office Properties Trust (COPT) into Balance Sheet approximately 1.8 million common shares of COPT. We As a result of the deregulation of electric generation, discuss the prior COPT transactions in Note 3 of our BGE transferred its generation assets to nonregulated 1999 Annual Report on Form 10-K. affiliates of Constellation Energy effective July 1, 2000.

In conjunction with this transfer, Constellation Power We discuss our other nonregulated businesses' activities Source Generation, Inc. issued approximately $366 further in the OtherNonregulatedBusinesses section of million in unsecured promissory notes to BGE.

Management's Discussion and Analysis on page 31. Repayments of the notes by Constellation Power Source Generation, Inc. will be used exclusively to service Related Party Transactions - BGE current maturities of certain BGE long-term debt. As of Income Statement September 30, 2000, $87 million of these notes are still Under the Restructuring Order, BGE is providing outstanding and will mature on March 14, 2001.

standard offer service to customers at fixed rates over various time periods during the transition period, July 1, Amounts related to the corporate functions performed at 2000 to June 30, 2006, for those customers that do not the Constellation Energy holding company and to BGE's choose an alternate supplier. Constellation Power Source purchases to meet its standard offer service obligation is under contract to provide BGE with the energy and resulted in intercompany accounts payable to capacity required to meet its standard offer service Constellation Energy and affiliates of $197.2 million at obligations for the first three years of the transition September 30, 2000. These amounts were not material in period. The cost of BGE's purchased energy from 1999.

nonregulated affiliates of Constellation Energy to meet its standard offer service obligation was $373.2 million for the quarter and nine months ended September 30, 2000.

17

Item 2. Management's Discussion Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction o Effective July 1, 2000, we formed a nonregulated On April 30, 1999, Constellation Energy@ Group, Inc. holding company, Constellation Power Source (Constellation Energy) became the holding company for Holdings, Inc., that includes the wholesale power Baltimore Gas and Electric Company (BGE)and marketing and risk management activities of Constellation Enterprises, Inc. Constellation Enterprises Constellation Power Source,TM Inc., the domestic was previously owned by BGE. power projects of Constellation Investments,TM Inc.

and Constellation Power,TM Inc., and subsidiaries, Constellation Energy's subsidiaries primarily include a and the generating assets of Constellation Power domestic merchant energy business focused mostly on Source Generation.

power marketing and merchant generation in North America, and BGE. As a result of these changes, effective July 1, 2000, our domestic merchant energy business includes the This Quarterly Report on Form I0-Q is a combined operations of Constellation Power Source Holdings and report of Constellation Energy and BGE. The the nuclear generation and consulting services of consolidated financial statements of Constellation Energy Constellation Nuclear, TM LLC.

include the accounts of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises, Inc. and its Also, effective July 1, 2000, the financial results of the subsidiaries, and Constellation Nuclear, LLC and its electric generation portion of our business are included in subsidiaries. The consolidated financial statements of the domestic merchant energy business. Prior to that BGE include the accounts of BGE, ComfortLink, and date, the financial results of electric generation were BGE Capital Trust I. As Constellation Enterprises and its included in BGE's regulated electric business.

subsidiaries were subsidiaries of BGE prior to April 30, BGE remains a regulated electric and gas public utility 1999, they are included in the consolidated financial company with a service territory in the City of Baltimore statements of BGE through that date.

and all or part often counties in Central Maryland.

We realigned our organization in response to the deregulation of electric generation. In the first quarter of Our other nonregulated businesses include the:

2000, we combined our wholesale power marketing "* Latin American power projects of Constellation business with our domestic plant development and Power, and subsidiaries, operations to form a domestic merchant energy business. "* energy products and services of Constellation At the same time, we revised our operating segments to Energy Source,TM Inc.,

reflect those realignments as presented in the Notes to ConsolidatedFinancialStatements on page 12. Several

"* home products, commercial building systems, and residential and commercial electric and gas retail additional changes occurred in conjunction with the marketing of BGE Home Products & Services,TM implementation of the Restructuring Order as described Inc. and subsidiaries, below. We discuss the deregulation of electric generation and the Restructuring Order in the CurrentIssues - "* general partnership, in which BGE is a partner, of Electric Competition section on page 20. District Chilled Water General Partnership (ComfortLink) that provides cooling services for

"* We formed two nonregulated subsidiaries - Calvert commercial customers in Baltimore, Cliffs Nuclear Power Plant, Inc. and Constellation "* financial investments of Constellation Investments, Power Source Generation, Inc. and

"*Effective July 1, 2000, BGE transferred its generation "* real estate and senior-living facilities of assets and related liabilities to these two new entities Constellation Real Estate Group,TM Inc.

at book value.

As discussed in the Subsequent Event section of the Notes to ConsolidatedFinancialStatements on page 11, we announced initiatives to separate our domestic merchant energy business from our retail services business and an investment by an affiliate of Goldman Sachs in our domestic merchant energy business.

18

References in this report to "we" and "our" are to As you read this discussion and analysis, refer to our Constellation Energy and its subsidiaries, collectively. Consolidated Statements of Income on page 3, which Reference in this report to the "utility business" is to present the results of our operations for the quarters and BGE. nine months ended September 30, 2000 and 1999. We analyze and explain the differences between periods in In this discussion and analysis, we explain the general the specific line items of the Consolidated Statements of financial condition and the results of operations for Income. Our analysis is important in making decisions Constellation Energy and BGE including: about your investments in Constellation Energy and/or BGE.

"* what factors affect our business, "owhat our earnings and costs were in the periods Also, this discussion and analysis is based on the presented, operation of the electric generation portion of our utility

"* why earnings and costs changed between periods, business under rate regulation through June 30, 2000.

Our electric business is changing as we have transferred

"* where our earnings came from, our electric generation assets and related liabilities to

"* how all of this affects our overall financial nonregulated subsidiaries of Constellation Energy and condition, we have entered into retail customer choice for electric

"* what we expect our expenditures for capital projects generation effective July 1, 2000. Accordingly, the to be in the future, and results of operations and financial condition described in

"*where we expect to get cash for future capital this discussion and analysis are not necessarily indicative expenditures. of future performance.

Strategy The change toward customer choice will significantly As discussed in the Subsequent Event section of the Notes impact our business. In response to this change, we to ConsolidatedFinancialStatements on page 11, we regularly evaluate our strategies with two goals in mind: announced several initiatives to advance our growth to improve our competitive position, and to anticipate strategies. These initiatives consist of:

and adapt to regulatory change. Prior to July 1, 2000, the majority of our earnings were from BGE. Going forward, "* a plan to separate our domestic merchant energy we expect to derive almost two-thirds of our earnings business from our retail services business, from our domestic merchant energy business. "* an agreement with an affiliate of Goldman Sachs under which it will invest in our domestic merchant While BGE will continue to be regulated and deliver energy business, and electricity and natural gas through its core distribution business, our growth strategies center on the

"* a reduction in our common stock dividend effective nonregulated domestic merchant energy business with April 2001.

the objective of providing new sources of earnings.

In addition, we decided to exit the Latin American portion of our business as a result of our concentration on Currently, our domestic merchant energy business owns or controls 8,500 megawatts of generation. We have planned domestic merchant energy. Currently, we are actively construction of 1,100 megawatts of peaking capacity in the seeking a buyer for the Latin American portion of our Mid-Atlantic/Mid-West region by the summer of 2001 and business and expect to complete our exit strategy in an additional 4,300 megawatts of peaking and combined 2001.

cycle production facilities in the Mid-West and South We also might consider one or more of the following regions are scheduled for completion in 2002 and beyond.

strategies:

By 2005, our domestic merchant energy business expects to own or control approximately 30,000 megawatts. "* the complete or partial separation of our transmission and distribution functions,

"* the construction or purchase of additional nuclear and non-nuclear generation assets,

"* mergers or acquisitions of utility or non-utility businesses, and

"° sale of generation assets or one or more businesses.

19

With the shift toward customer choice, competition, and "*All customers, except a few commercial and the growth of our domestic merchant energy business, industrial companies that have signed contracts with various factors will affect our financial results in the BGE, can choose their electric energy supplier future. These factors include, but are not limited to, beginning July 1, 2000. BGE will provide a operating our generation assets in a deregulated market standard offer service for customers that do not without the benefit of a fuel rate adjustment clause, the select an alternative supplier. In either case, BGE timing and implications of deregulation in other regions will continue to deliver electricity to all customers in where our domestic merchant energy business will areas traditionally served by BGE.

operate, the loss of revenues due to customers choosing "*BGE's electric base rates were frozen through alternative suppliers, higher volatility of earnings and cash June 30, 2000.

flows, and increased financial requirements of our domestic merchant energy business. Please refer to the "* BGE reduced residential base rates by approximately 6.5%, on average about $54 million Forward-LookingStatements section on page 37 for a year, beginning July 1, 2000. These rates will not additional factors.

change before July 2006.

Current Issues - Electric Competition "* Commercial and industrial customers have up to Electric utilities are facing competition on various fronts, four service options that will fix electric energy rates including: and transition charges for a period that generally ranges from four to six years.

  • the construction of generating units to meet

"* BGE's electric fuel rate clause was discontinued increased demand for electricity, effective July 1, 2000.

  • the sale of electricity in bulk power markets,

"* Electric delivery service rates are frozen for a four

  • competing with alternative energy suppliers, and year period for commercial and industrial
  • electric sales to retail customers. customers. The generation and transmission components of rates are frozen for different time On April 8, 1999, Maryland enacted the Electric periods depending on the service options selected Customer Choice and Competition Act of 1999 (the by those customers.

"Act") and accompanying tax legislation that has significantly restructured Maryland's electric utility "*BGE will recover $528 million after-tax of its industry and modified the industry's tax structure. potentially stranded investments and utility restructuring costs through a competitive transition In the Restructuring Order discussed below, the Maryland charge on customers' bills. Residential customers PSC addressed the major provisions of the Act. The will pay this charge for six years. Commercial and accompanying tax legislation is discussed in detail in industrial customers will pay in a lump sum or over Note 4 of our 1999 Annual Report on Form 10-K. the four to six-year period, depending on the service option selected by each customer.

On November 10, 1999, the Maryland PSC issued a

"*Generation-related regulatory assets and nuclear Restructuring Order that resolved the major issues decommissioning costs are included in delivery surrounding electric restructuring, accelerated the service rates effective July 1, 2000 and will be timetable for customer choice, and addressed the major recovered on a basis approximating their provisions of the Act. The Restructuring Order also amortization schedules prior to July 1, 2000.

resolved the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for "*Effective July 1, 2000, BGE unbundled rates to electric services) and a petition filed in September 1998 show separate components for delivery service, by the Office of People's Counsel (OPC) to lower our transition charges, standard offer services electric base rates. The major provisions of the (generation), transmission, universal service, and Restructuring Order are discussed below. taxes.

" Effective July 1, 2000, BGE transferred, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy.

20

"*BGE reduced its generation assets, as discussed in " BGE assigned approximately $47 million to Calvert Note 4 of our 1999 Annual Report on Form 10-K, by Cliffs Nuclear Power Plant, Inc. and $231 million to

$150 million pre-tax during the period July 1, 1999 Constellation Power Source Generation of tax June 30, 2000 to mitigate a portion of BGE's exempt debt related to the transferred assets. Also, potentially stranded investments. Constellation Power Source Generation issued

"*Universal service is being provided for low-income approximately $366 million in unsecured customers without increasing their bills. BGE will promissory notes to BGE. Repayments of the notes provide its share of a statewide find totaling $34 by Constellation Power Source Generation will be million annually. used exclusively to service the current maturities of certain BGE long-term debt.

We believe that the Restructuring Order provided " BGE transferred equity associated with the sufficient details of the transition plan to competition for generating assets to Calvert Cliffs Nuclear Power BGE's electric generation business to require BGE to Plant, Inc. and Constellation Power Source discontinue the application of Statement of Financial Generation, Inc.

Accounting Standards (SFAS) No. 71, Accountingfor the Effects of Certain Types ofRegulation for that portion of The fossil fuel and nuclear fuel inventories, its business. Accordingly, in the fourth quarter of 1999, materials and supplies, and certain purchased power we adopted the provisions of SFAS No. 101, Regulated contracts of BGE were also assumed by these Enterprises- A ccountingforthe DiscontinuationofFASB subsidiaries.

Statement No. 71 and Emerging Issues Task Force Effective July 1, 2000, BGE provides standard offer Consensus (EITF) No. 97-4, Deregulationofthe Pricing service to customers at fixed rates over various time ofElectricity - Issues Related to the Application ofFASB periods during the transition period for those customers Statements No. 71 and 101 for BGE's electric generation that do not choose an alternate supplier. In addition, the business. BGE's transmission and distribution business electric fuel rate was discontinued effective July 1, 2000.

continues to meet the requirements of SFAS No. 71 as that Constellation Power Source provides BGE with the business remains regulated. We describe the effect of energy and capacity required to meet its standard offer applying these accounting requirements in Note 4 of our service obligations for the first three years of the 1999 Annual Report on Form 10-K. transition period. Thereafter, BGE will competitively bid Please refer to the Legal Proceedingssection on page 36 the energy and capacity.

for a discussion regarding appeals of the Restructuring Constellation Power Source obtains the energy and Order. capacity to supply BGE's standard offer service As a result of the deregulation of electric generation, the obligations from affiliates that own Calvert Cliffs following occurred effective July 1, 2000: Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants, supplemented with energy purchased from BGE transferred, at book value, its nuclear generating the wholesale energy market as necessary.

assets, its nuclear decommissioning trnst fuind, and Our domestic merchant energy business is affected by related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book weather conditions in the different regions of North value, its fossil generating assets and related liabilities America. Typically, demand for electricity, and its price, and its partial ownership interest in two coal plants is higher in the summer and the winter, when weather is and a hydroelectric plant located in Pennsylvania to more extreme. All regions of North America typically Constellation Power Source Generation. In total, do not experience extreme weather conditions at the these generating assets represent about 6,240 same time. To date, the majority of our generation is megawatts of generation capacity with a total net located in the PJM (Pennsylvania-New Jersey-Maryland) book value at June 30, 2000 of approximately $2.4 Interconnection. Accordingly, our financial results are billion. affected by weather in this area. However, by 2005, we expect to own or control approximately 30,000 megawatts of generation throughout various regions of North America.

21

Current Issues - Regulated Businesses to us. If these fuel costs went up, the Maryland PSC We also believe it is important to discuss factors that permitted us to increase the fuel rate.

have a strong influence on the performance of our Under the Restructuring Order, BGE's electric fuel rate regulated electric and regulated gas businesses. In was frozen until July 1, 2000, at which time the fuel rate addition to electric restructuring which was discussed clause was discontinued. We deferred the difference earlier, regulation by the Maryland PSC, the weather, and other factors, including the condition of the economy between our actual costs of fuel and energy and what we collected from customers under the fuel rate through in our service territory influence BGE's businesses.

June 30, 2000.

Regulation by the Maryland PSC In September 2000, the Maryland PSC approved the Under traditional rate regulation that continues after July collection of the $54.6 million accumulated difference 1,2000 for BGE's electric transmission and distribution, between our actual costs of fuel and energy and the and gas businesses, the Maryland PSC determines the amounts collected from customers that were deferred rates we can charge our customers. Currently, BGE's under the electric fuel rate clause through June 30, 2000.

rates consist primarily of a "base rate" and a "fuel rate."

We will collect this accumulated difference from Base Rate customers over a twelve-month period beginning The base rate is the rate the Maryland PSC allows BGE October 2000. Effective July 1, 2000, earnings are to charge its customers for the cost of providing them affected by the changes in the cost of fuel and energy.

service, plus a profit. BGE has both an electric base rate We charge our gas customers separately for the natural and a gas base rate. Higher electric base rates apply gas they purchase from us. The price we charge for the during the summer when the demand for electricity is natural gas is based on a market based rates incentive higher. Gas base rates are not affected by seasonal mechanism approved by the Maryland PSC. We discuss changes.

market based rates in more detail in the Gas Cost BGE may ask the Maryland PSC to increase base rates Adjustments section on page 30 and in Note I of our 1999 from time to time. The Maryland PSC historically has Annual Report on Form 10-K.

allowed BGE to increase base rates to recover increased Weather utility plant asset costs, plus a profit, beginning at the Weather conditions can have a great impact on BGE's time of replacement. Generally, rate increases improve results for interim periods primarily due to the impact on our utility earnings because they allow us to collect more sales volumes and commodity prices. This means that revenue. However, rate increases are normally granted results for interim periods do not necessarily represent based on historical data and those increases may not results to be expected for the year.

always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates. Weather affects the demand for electricity and gas for our regulated businesses. Very hot summers and very On November 17, 1999, BGE filed an application with cold winters increase demand. Mild weather reduces the Maryland PSC to increase its gas base rates. On demand. Residential sales for our regulated businesses June 19, 2000, the Maryland PSC authorized a $6.4 are impacted more by weather than commercial and million annual increase in our gas base rates effective industrial sales, which are mostly affected by business June 22, 2000.

needs for electricity and gas.

As a result of the Restructuring Order, BGE's residential However, the Maryland PSC allows us to record a electric base rates are frozen until 2006.

monthly adjustment to our regulated gas business Electric delivery service rates are frozen for a four-year revenues to eliminate the effect of abnormal weather period for commercial and industrial customers. The patterns. We discuss this further in the Weather generation and transmission components of rates are Normalizationsection on page 30.

frozen for different time periods depending on the We measure the weather's effect using "degree days." A service options selected by those customers.

degree day is the difference between the average daily Fuel Rate actual temperature and a baseline temperature of 65 Through June 30, 2000, we charged our electric degrees. Cooling degree days result when the average customers separately for the fuel we used to generate daily actual temperature exceeds the 65 degree baseline.

electricity (nuclear fuel, coal, gas, or oil) and for the net Heating degree days result when the average daily actual cost of purchases and sales of electricity. We charged the temperature is less than the baseline.

actual cost of these items to the customer with no profit 22

During the cooling season, hotter weather is measured by Current Issues - Gas Competition more cooling degree days and results in greater demand Currently, no regulation exists for the wholesale price of for electricity to operate cooling systems. During the natural gas as a commodity, and the regulation of heating season, colder weather is measured by more interstate transmission at the federal level has been heating degree days and results in greater demand for reduced. All BGE gas customers have the option to electricity and gas to operate heating systems. purchase gas from other suppliers.

We show the number of heating degree days in the Current Issues - Calvert Cliffs License quarter and nine months ended September 30, 2000 and Extension 1999, and the percentage change in the number of degree On March 23, 2000, the Nuclear Regulatory days between these periods in the following table:

Commission (NRC) approved a 20-year license Quarter Ended Nine Months Ended extension for both units of Calvert Cliffs, extending the September 30 September 30 license for Unit 1 to 2034 and for Unit 2 to 2036.

2000 _999 2000 1999 On April 11, 2000 the United States Court of Appeals for the District of Columbia Circuit, in National Heating degree days ........... 142 75 2,959 2,981 Whistleblowers Center v. Nuclear Regulatory Percent change Commission and Baltimore Gas and Electric Company, from prior period ......... 89.3% (0.7)% upheld the NRC's denial of the Center's motion to intervene in BGE's license renewal proceeding. The Cooling degree days ........... 445 629 714 832 NRC had denied the Center's motion to intervene for Percent change failing to file timely contentions. The Center has filed a from prior period ........ (29.3)% (14.2)% petition for certiorari, a request to hear an appeal, with the U.S. Supreme Court.

Other Factors Other factors, aside from weather, impact the demand for Current Issues - Regional Transmission electricity and gas in our regulated businesses. These Organizations factors include the "number of customers" and "usage In December 1999, the FERC issued Order 2000, per customer" during a given period. We use these terms amending its regulations under the Federal Power Act to later in our discussions of regulated electric and gas advance the formation of Regional Transmission operations. In those sections, we discuss how these and Organizations (RTOs). The regulations require that each other factors affected electric and gas sales during the public utility that owns, operates, or controls facilities for periods presented. the transmission of electric energy in interstate commerce make certain filings with respect to forming and The number of customers in a given period is affected by participating in a RTO. FERC also identified the new home and apartment construction and by the number minimum characteristics and functions that a of businesses in our service territory. Under the transmission entity must satisfy in order to be considered Restructuring Order, BGE's electric customers can a RTO.

become delivery service customers only and can purchase their electricity from other sources. We will According to the Order, a public utility that is a member collect a delivery service charge to recover the fixed of an existing transmission entity that has been approved costs for the service we provide. The remaining electric by FERC as in conformance with the Independent customers will receive standard offer service from BGE System Operator (ISO) principles set forth in the FERC at the fixed rates provided by the Restructuring Order. Order No. 888, such as BGE, through its membership in Usage per customer refers to all other items impacting the PJM must make a filing no later than January 15, customer sales that cannot be measured separately. These 2001. While not required until 2001, PJM and the joint factors include the strength of the economy in our service transmission owners, including BGE, made the filing on territory. When the economy is healthy and expanding, October 11, 2000. That filing explained the extent to customers tend to consume more electricity and gas. which PJM met the minimum characteristics and Conversely, during an economic downtrend, our finctions of a RTO and explained its plans to conform to customers tend to consume less electricity and gas. these characteristics and functions.

As a member of the PJM, an existing ISO, BGE does not expect to be materially impacted by the Order. However, BGE, along with other members of the PJM, is appealing certain aspects of the Order. We cannot determine the full impact of the Order at this time.

23

Results of Operations for the Quarter and Nine Months Ended September 30,2000 Compared with the Same Periods of 1999 In this section, we discuss our earnings and the factors Quarter Ended September 30, 2000 affecting them. We begin with a general overview, then Our total earnings for the quarter ended September 30, separately discuss earnings for our operating segments. 2000 increased $11.4 million, or $.07 per share, Changes in fixed charges, income taxes, and other compared to the same period of 1999. However, our total income are discussed in the aggregate for all segments in earnings before nonrecurring charges decreased $20.9 the ConsolidatedNonoperatingIncome and Expenses million or $. 15 per share mostly due to extremely mild section on page 32. summer weather in 2000. We also recognized $26.0 million, or almost one-half, of the annual impact of a Overview 6.5% annual residential rate reduction that was effective Total EarningsPerShare of Common Stock July 1, 2000. This decrease was partially offset by a Quarter Ended Nine Months Ended $37.5 million deferral of electric revenues recorded in September 30 September 30 September 1999 associated with the deregulation of our 2000 1999 2000 1999 electric generation business that had a negative impact in Earnings before that year. We did not have a similar deferral in 2000.

nonrecurring charges We also had higher earnings from our other nonregulated included in operations: businesses in the third quarter of 2000 compared to the Domestic merchant same period of 1999.

energy ......................... $.87 $.14 $1.10 $34 Regulated electric .......... .10 1.05 .65 1.73 In addition, we recorded the following nonrecurring charges in operations during the third quarter of 1999:

Regulated gas ................. (.03) .12 .14 Other nonregulated ........ .04 (.06) (.01) (.05) 0 $4.9 million after-tax, or $.03 per share, of expenses Total earnings per share related to Hurricane Floyd, before nonrecurring . a $6.7 million after-tax, or $.05 per share, write-off charges included in of a geothermal power project, operations ................... .98 1.13 1.86 2.16

  • a $17.3 million after-tax, or $.12 per share, write Nonrecurring charges down of a financial investment, and included in operations:

Deregulation . a $3.4 million after-tax, or $.02 per share, write transition cost ......... (.10) down of certain senior-living facilities.

TVSERP ...................... (.03)

In the following sections, we discuss our earnings by Hurricane Floyd business segment in greater detail.

expenses ................ (.03) (.03)

Write-off of power Nine Months Ended September 30,2000 project .............. (.05) .05) Our total earnings for the nine months ended September Write-down of financial 30, 2000 decreased $27.7 million, or S. 19 per share, investment .............. (.12) .14) compared to the same period of 1999. Our total earnings Write-down of senior before nonrecurring charges decreased $44.4 million or living facilities ........ (.02) ( .02) $.30 per share mostly due to the $75.0 million, or $45.4 Earnings per share ....... $.98 $.91 $1.73 $1 .92 million after-tax, amortization of the regulatory asset recorded for the reduction of BGE's generation plant Earnings for the periods presented below reflect a during the first half of 2000 and the large impact of the significant shift in earnings from the regulated electric 6.5% annual residential rate reduction reflected in the business to the domestic merchant energy business as a third quarter. This decrease was partially offset by the result of the transfer of BGE's electric generation assets $37.5 million deferral of electric revenues in 1999. In to nonregulated subsidiaries on July 1, 2000 in addition, we recorded the following nonrecurring charges accordance with the Restructuring Order. We discuss the in operations:

Restructuring Order in more detail in CurrentIssues Electric Competition section on page 20. a $15.0 million after-tax, or $. 10 per share, deregulation transition cost in June 2000 to a third party incurred by our power marketing business to provide BGE's standard offer service requirements, 24

- a $4.2 million after-tax, or $.03 per share, expense We cannot estimate the impact of the increased financial during the first and second quarters of 2000 for risks associated with customer choice. However, these BGE employees that elected to participate in a financial risks could have a material impact on our Targeted Voluntary Special Early Retirement financial results.

Program (TVSERP),

- $4.9 million after-tax, or S.03 per share, of expenses In addition, effective July 1, 2000, under the terms of separate agreements, domestic merchant energy business related to Hurricane Floyd in 1999, revenues include 90% of the competitive transition

  • a $6.7 million after-tax, or S.05 per share, write-off of charges BGE collects from its customers (CTC revenues) a geothermal power project in 1999, and the portion of its revenues providing for
  • a $20.9 million after-tax, or $.14 per share, write decommissioning costs.

down of a financial investment in 1999, and

- a $3.4 million after-tax, or S.02 per share, write-down Earnings of certain senior-living facilities in 1999.

Quarter Ended Nine Months Ended Domestic Merchant Energy Business September 30 September 30 Our domestic merchant energy business engages 2000 1999 2000 1999 primarily in power marketing and domestic power (In millions, exceptper shareamounts) generation. We describe these businesses in more detail Revenues ........................... $495.6 $66.3 $628.9 $173.7 in our 1999 Annual Report on Form 10-K in Item 1. Operating expenses ........... 221.7 40.7 312.3 87.8 Business -Diversified Businesses. Depreciation and amortization ................. 38.6 1.5 41.9 3.6 As discussed in the CurrentIssues -- Electric Taxes other than Competition section on page 20, our domestic merchant income taxes ................ 13.1 - 13.1 energy business was significantly impacted by the July 1, Operating income .............. $222.2 $24.1 $261.6 $82.3 2000 implementation of customer choice in Maryland.

Net income ........................ $130.9 $12.2 $150.2 $43.6 At that time, BGE's generating assets became part of our nonregulated domestic merchant energy business, and Earnings per share ............. $ .87 $ .09 $ 1.00 $ .29 Constellation Power Source began selling to BGE the Above amounts includeintercompany transactionseliminatedin our energy and capacity required to meet its standard offer ConsolidatedFinancialStatements.

service obligations for the first three years of the transition period. Revenues During the quarter ended September 30, 2000, domestic Constellation Power Source will obtain the energy and merchant energy revenues increased $429.3 million capacity to supply BGE's standard offer service compared to the same period of 1999 mostly because of:

obligations from affiliates that own Calvert Cliffs and BGE's former fossil plants, supplemented with energy - a $373.2 million increase related to providing BGE purchased from the wholesale energy market as the energy and capacity required to meet its standard necessary. Constellation Power Source will also manage offer service obligation effective July 1, 2000, and our wholesale market price risk. - a $59.3 million increase related to CTC and decommissioning revenues included in the domestic Our earnings are exposed to the risks of the competitive merchant energy business effective July 1, 2000.

wholesale electricity market to the extent that Constellation Power Source has to purchase energy During the nine months ended September 30, 2000, and/or capacity to meet obligations to supply power to domestic merchant energy revenues increased $455.2 BGE at market prices or costs, respectively, which may million compared to the same period of 1999 mostly approach or exceed BGE's standard offer service rates. If because of the increase in revenues associated with the the price of obtaining energy in the wholesale market implementation of customer choice as discussed above exceeds the fixed standard offer service price, our and higher revenues from our power marketing and earnings would be adversely affected. We are also domestic generation businesses.

affected by operational risk, that is, the risk that a generating plant will not be available to produce energy Power marketing revenues increased during the nine when the energy is required. Imbalances in demand and months ended September 30, 2000 compared to the same supply can occur not only because of plant outages, but period of 1999 mostly because of higher transaction also because of transmission constraints, or extreme volumes. These higher volumes were offset partially by temperatures (hot or cold) causing demand to exceed lower margins.

available supply.

25

Our domestic generation business revenues increased Under these agreements, the electricity rates change from during the nine months ended September 30, 2000 fixed rates to variable rates beginning in 1996 and compared to the same period of 1999 mostly because of continuing through 2000. The projects which already the gain recognized on the termination of an operating have had rate changes have lower revenues under arrangement and the sale of certain subsidiaries. In April variable rates than they did under fixed rates. When the 2000, Constellation Operating Services, Inc. (COSI), a remaining projects transition to variable rates, we expect subsidiary of Constellation Power, Inc., ended its their revenues also to be lower than they are under fixed exclusive arrangement with Orion Power Holdings, Inc. rates.

to operate Orion's facilities. Orion purchased from COSI the four subsidiary companies formed to operate power At the date of this report, 12 projects had already plants owned by Orion. This increase was offset partially transitioned to variable rates. The remaining two by lower revenues associated with our California power projects will transition in December 2000.

purchase agreements discussed below.

Our power projects business continues to pursue Mark-to-MarketAccounting alternatives for some of these projects including:

Constellation Power Source uses the mark-to-market method of accounting. We discuss the mark-to-market

"* repowering the projects to reduce operating costs, method of accounting and Constellation Power Source's "* changing fuels to reduce operating costs, activities in more detail in Note I of our 1999 Annual "* renegotiating the power purchase agreements to Report on Form I0-K. improve the terms, As a result of the nature of its business activities,

"° restructuring financing to improve existing terms, Constellation Power Source's revenue and earnings will and selling its ownership interests in the projects.

fluctuate. We cannot predict these fluctuations, but the We evaluate the carrying amount of our investment in effect on our revenues and earnings could be material. these projects for impairment using the methodology The primary factors that cause these fluctuations are: discussed in Note I of our 1999 Annual Report of Form

"* the number and size of new transactions, 10-K. Constellation Power's management uses its best estimates to determine if there has been an impairment of

"* the magnitude and volatility of changes in these investments and considers various factors including commodity prices and interest rates, and forward price curves for energy, fuel costs, and operating

"* the number and size of open commodity and costs. However, it is possible that future estimates of derivative positions Constellation Power Source market prices and project costs could vary from those holds or sells. used in evaluating these assets, and the impact of such variations could be material.

Constellation Power Source's management uses its best estimates to determine the fair value of commodity and We also describe these projects and the transition process derivative positions it holds and sells. These estimates in the Notes to ConsolidatedFinancialStatements on consider various factors including closing exchange and page 16.

over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is possible that Operating Expenses future market prices could vary from those used in During the quarter ended September 30, 2000, domestic recording assets and liabilities from power marketing and merchant energy operating expenses increased $181.0 trading activities, and such variations could be material. million compared to the same period of 1999 mostly Assets and liabilities from energy trading activities (as because of increases of $102.6 million in fuel costs and shown in our ConsolidatedBalance Sheets beginning on $79.2 million in operations and maintenance costs. These page 4) increased at September 30, 2000 compared to fuel and operations and maintenance costs were December 31, 1999 because of business growth during associated with the generation plants that were the period. transferred from BGE effective July 1, 2000.

CaliforniaPowerPurchaseAgreements Our domestic generation business has $297.6 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements.

26

During the nine months ended September 30, 2000, Earnings domestic merchant energy operating expenses increased

$224.5 million compared to the same period of 1999 Quarter Ended Nine Months Ended mostly because of: September 30 September 30 2000 1999 2000 1999 the transfer of fuel, operations, and maintenance costs (In millions, except pershareamounts) from BGE effective July 1, 2000, as discussed on Electric revenues ................. $598.4 $691.4 $1,688.4 $1,737.9 page 26, Electric fuel and a $10.2 million write-off ofa geothermal power purchased energy ........... 388.3 130.0 632.4 376.2 project in August 1999 by our domestic power Operations and projects business. This write-off occurred because the maintenance ................... 62.0 146.3 384.7 468.5 expected future cash flow from the project was less Depreciation and than the investment in the project due to the declining amortization ................... 52.0 78.3 276.7 227.0 water temperature of the geothermal resource used by Taxes other than the plant for production, income taxes .................. 30.5 59.5 121.0 149.2

  • a $24.0 million deregulation transition cost in June Operating income ................ $65.6 $277.3 $273.6 $517.0 2000 to a third party incurred by our power Net income .......................... $15.4 $152.3 $93.2 $253.4 marketing business to provide BGE's standard offer Earnings per share ............. $ .10 $1.02 $ .62 $1.70 service requirements, and Above amounts include intercompanytransactionseliminated in our
  • an increase in operating expenses at our power ConsolidatedFinancialStatements.

marketing business due to the growth of the business.

Electric Revenues Depreciation and Amortization Expense The changes in electric revenues in 2000 compared to Domestic merchant energy depreciation and amortization 1999 were caused by:

expense increased $37.1 million for the quarter and

$38.3 million for the nine months ended September 30, Quarter Ended Nine Months Ended 2000 compared to the same periods of 1999 mostly September 30 September 30 because of $36.8 million of expenses associated with the 2000 vs. 1999 2000 vs. 1999 generation plants that were transferred from BGE (In millions) effective July 1, 2000.

Electric system sales Taxes Other than Income Taxes volum es ............................. $(28.5) $4.5 During the quarter and nine months ended September 30, Rates ................... (75.5) (62.9) 2000, domestic merchant energy taxes other than income Total change in electric taxes increased $13.1 million compared to the same revenues from electric periods of 1999 because of $12.9 million of taxes other system sales ..................... (104.0) (58.4) than income taxes associated with the generation plants Interchange and that were transferred from BGE effective July 1, 2000. other sales ........................ (24.9) (30.2)

O ther ................................... 35.9 39.1 Regulated Electric Business Total change in As previously discussed, our regulated electric business electric revenues ............... $(93.0) $(49.5) was significantly impacted by the July 1, 2000 implementation of customer choice. These changes Electric System Sales Volumes include BGE's generating assets and related liabilities "Electric system sales volumes" are sales to customers in our becoming part of our nonregulated domestic merchant service territory at rates set by the Maryland PSC. These energy business on that date. sales do not include interchange sales and sales to others.

The percentage changes in our electric system sales volumes, by type of customer, in 2000 compared to 1999 were:

Quarter Ended Nine Months Ended September 30 September 30 2000 vs. 1999 2000 vs. 1999 Residential .............. (10.8)% (0.7)%

Commercial ............. 0.2 3.8 Industrial ................. 13.2 4.1 27

During the quarter ended September 30, 2000, we sold less choice, BGE sold energy to PJM members and to others electricity to residential customers due to extremely mild after it had satisfied the demand for electricity in its own summer weather. We sold about the same amount of system.

electricity to commercial customers. We sold more electricity to industrial customers mostly because usage by Effective July 1, 2000, BGE no longer engages in Bethlehem Steel (our largest customer) was higher in 2000 interchange sales and these activities are included in our because of a 1999 shut down for a planned upgrade to their domestic merchant energy business which results in the facilities that temporarily reduced their electricity decrease in interchange and other sales for the quarter and consumption in that year. nine months ended September 30,2000 compared to the same periods of 1999. In addition, BGE had lower During the nine months ended September 30, 2000, we interchange and other sales during the first half of 2000 sold about the same amount of electricity to residential when increased demand for system sales reduced the customers due to the extremely mild summer weather being amount of energy it had available for off-system sales.

substantially offset by warmer spring and early summer weather, an increased number of customers, and higher Other usage per customer. We sold more electricity to During the quarter and nine months ended September 30, commercial customers mostly due to higher usage per 2000, other revenues increased compared to the same customer and an increased number of customers. We sold periods of 1999 mostly because of a $37.5 million more electricity to industrial customers due to the increase deferral of electric revenues recorded in September in usage by Bethlehem Steel, offset partially by lower usage 1999, which had a negative impact in that year. This by other industrial customers. deferral was recorded on the basis that as of September 30, 1999 these revenues were subject to refund pending Rates the approval of the Restructuring Order by the Maryland Prior to July 1,2000, our rates primarily consisted of an PSC at that time.

electric base rate and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric fuel rate and Electric Fuel and Purchased Energy Expenses unbundled its rates to show separate components for Quarter Ended Nine Months Ended delivery service, transition charges, standard offer services September 30 September 30 (generation), transmission, universal service, and taxes. In 2000 1999 2000 1999 addition, BGE's rates were frozen in total except for the (In millions) implementation of a residential base rate reduction totaling Actual costs ............... $388.3 $191.8 $642.1 $454.7 approximately $54 million annually. Under the terms of Net deferral of costs the intercompany agreements whereby BGE obtains the under electric fuel energy and capacity to meet its standard offer service rate clause ............. - (61.8) (9.7) (78.5) obligation, 90% of the CTC revenues BGE collects and the Total electric fuel and portion of its revenues providing for decommissioning purchased energy costs, are included in revenues of the domestic merchant expenses ................ $388.3 $130.0 $632.4 $376.2 energy business effective July 1, 2000.

Actual Costs During the quarter ended September 30, 2000, rate During the quarter and nine months ended September 30, revenues decreased compared to the same period of 1999 2000, our actual costs of fuel and purchased energy were mostly because we recognized $26.0 million, or almost higher compared to the same periods of 1999 mostly one-half of the 6.5% annual residential rate reduction, and because of the implementation of customer choice.

$59.3 million of CTC and decommissioning revenues are included in the domestic merchant energy business. As discussed in the CurrentIssues -- Electric Competition section on page 20, effective July 1, 2000, BGE During the nine months ended September 30, 2000, rate transferred its generating assets to, and began purchasing revenues decreased $62.9 million compared to the same substantially all of the energy and capacity required to periods of 1999 as a result of the rate reduction and transfer provide electricity to standard offer service customers of revenues discussed above, offset partially by higher rate from, nonregulated affiliates of Constellation Energy. For revenues during the first half of 2000. the quarter and nine months ended September 30, 2000, the cost of energy BGE purchased from nonregulated Interchange and Other Sales affiliates of Constellation Energy was $373.2 million. The "Interchange and other sales" are sales in the PJM energy higher amnount paid for purchased energy is offset by market and to others. The PJM is an ISO that also operates lower operations and maintenance, depreciation, taxes, a regional power pool with members that include many and other costs at BGE as a result of no longer owning wholesale market participants, as well as BGE, and other and operating the transferred electric generation plants.

utility companies. Prior to the implementation of customer 28

Prior to July 1, 2000, BGE's purchased fuel and energy During the nine months ended September 30, 2000, costs only included actual costs of fuel to generate regulated electric depreciation and amortization expense electricity (nuclear fuel, coal, gas, or oil) and electricity we increased $49.7 million compared to 1999 mostly bought from others. because of the $75.0 million amortization of the regulatory asset for the reduction in generation plant ElectricFuel Rate Clause provided for in the Restructuring Order and higher Prior to July 1, 2000, we deferred the difference between amortization associated with other generation regulatory our actual costs of fuel and energy and what we collected assets. This was partially offset by the absence of $36.8 from customers under the fuel rate in a given period. million of depreciation and amortization expense Effective July 1, 2000, the fuel rate clause was associated with the transfer of the generation assets.

discontinued under the terms of the Restructuring Order.

Electric Taxes Other Than Income Taxes During the quarter and nine months ended September 30, Regulated electric taxes other than income taxes 2000, the net deferral of costs under the electric fuel rate decreased $29.0 million for the quarter and $28.2 million clause decreased compared to the same periods of 1999 for the nine months ended September 30, 2000 compared due to the discontinuation of the fuel rate clause effective to the same periods of 1999. This was mostly due to July 1, 2000. comprehensive changes to the tax laws under the Electric Customer Choice and Competition Act of 1999. The We discuss the accumulated difference between our actual comprehensive tax law changes are discussed further in costs and what we collected through June 30, 2000 in the Note 4 of our 1999 Annual Report on Form 10-K. In Recoverability ofElectric Fuel Costs section of the Notes addition, regulated electric taxes other than income taxes to ConsolidatedFinancialStatements on page 16.

reflect the absence of $12.9 million of taxes other than Electric Operations and Maintenance Expenses income taxes associated with the generation assets that During the quarter ended September 30, 2000, regulated were transferred to the domestic merchant energy electric operations and maintenance expenses decreased business effective July 1, 2000.

$84.3 million compared to 1999 mostly because effective July 1, 2000, $79.2 million of costs were no longer Regulated Gas Business incurred by this business segment. These costs were Earnings associated with the electric generation assets that were transferred to the domestic merchant energy business. In Quarter Ended Nine Months Ended addition, 1999 operations and maintenance expenses September 30 September 30 include approximately $7.5 million of costs associated 2000 1999 2000 1999 Hurricane Floyd that had a negative impact in that quarter. (In millions, except pershareamounts)

Gas revenues ........................ $90.1 $62.9 $377.8 $340. I During the nine months ended September 30, 2000, Gas purchased for resale ...... 48.2 21.3 192.0 156.4 regulated electric operations and maintenance expenses Operations and decreased $83.8 million compared to 1999 mostly due to maintenance .................... 26.2 20.8 73.1 69.1 the absence of $79.2 million of costs associated with the Depreciation and transfer of the electric generation assets. Also, 1999 am ortization .................... 11.3 10.2 35.5 34.4 operations and maintenance expenses include costs Taxes other than associated with Hurricane Floyd and a major winter ice income taxes ................... 5.0 4.6 25.0 25.2 storm earlier that year. This decrease is partially offset Operating income (loss) ....... $(0.6) $6.0 $52.2 $55.0 by the $7.0 million of expense recognized in 2000 for electric business employees that elected to participate in Net income (loss) ................. S(4.6) $(0.7) $18.1 $21.5 the TVSERP. Earnings per share ................ S(.03) $.12 $.14 Above amounts include intercompanytransactionseliminated in our Electric Depreciation and Amortization ConsolidatedFinancialStatements.

Expense During the quarter ended September 30, 2000, regulated All BGE customers have the option to purchase gas from electric depreciation and amortization expense decreased other suppliers. To date, customer choice has not had a

$26.3 million compared to 1999 mostly because of the material effect on our, and BGE's, financial results.

absence of $36.8 million of depreciation and amortization expense associated with the transfer ofthe generation assets to the domestic merchant energy business. This was partially offset by higher amortization expense associated with our electric generation regulatory assets.

29

Gas Revenues Weather Normalization The changes in gas revenues in 2000 compared to 1999 The Maryland PSC allows us to record a monthly were caused by: adjustment to our gas revenues to eliminate the effect of abnormal weather patterns on our gas system sales Quarter Ended Nine Months volumes. This means our monthly gas revenues are based September 30 September 30 on weather that is considered "normal" for the month 2000 vs. 1999 2000 vs. 1999 and, therefore, are not affected by actual weather (In millions) conditions.

Gas system sales volumes .......................... $3.9 $11.5 Gas Cost Adjustments Base rates .................................. 0.7 0.2 We charge our gas customers for the natural gas they Weather normalization .............. (1.9) (5.4) purchase from us using gas cost adjustment clauses set by Gas cost adjustments ................. 8.8 (4.4) the Maryland PSC as described in Note I of our 1999 Total change in gas revenues Annual Report on Form 10-K. However, under market from gas system sales ............... 11.5 1.9 based rates, our actual cost of gas is compared to a market 164 36 1 index (a measure of the market price of gas in a given Off-system sales .........................

period). The difference between our actual cost and the O ther .......................................... (0.7) (0.3) market index is shared equally between shareholders and Total change in customers, and does not significantly impact earnings.

gas revenues ........................... $27.2 $ 37.7 Delivery service customers, including Bethlehem Steel, Gas System Sales Volumes are not subject to the gas cost adjustment clauses because The percentage changes in our gas system sales volumes, we are not selling gas to them. We charge these by type of customer, in 2000 compared to 1999 were: customers fees to recover the fixed costs for the transportation service we provide. These fees are the Quarter Ended Nine Months Ended same as the base rate charged for gas sales and are September 30 September 30 included in gas system sales volumes.

2000 vs. 1999 2000 vs. 1999 During the quarter ended September 30, 2000, gas cost Residential ........................... 3.0% 1.5% adjustment revenues increased compared to the same Commercial .......................... 17.6 7.5 period of 1999 mostly because we sold gas at a higher Industrial .............................. 3.4 4.2 price.

During the quarter ended September 30, 2000, we sold During the nine months ended September 30,2000, gas more gas to residential customers compared to the same cost adjustment revenues decreased compared to the period of 1999 due mostly to an increased number of same period of 1999 mostly because we sold less gas to customers. We sold more gas to commercial customers non-delivery service customers. This was partially offset mostly because of higher usage per customer offset by a higher price of gas sold.

partially by fewer customers. We sold more gas to industrial customers mostly because of an increase in the Off-System Sales number of customers. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service During the nine months ended September 30, 2000, we territory. Off-system gas sales, which occur after we sold more gas to residential and commercial customers have satisfied our customers' demand, are not subject to compared to the saone period of 1999 due to higher usage gas cost adjustments. The Maryland PSC approved an per customer and an increased number of customers. arrangement for part of the margin from off-system sales This was partially offset by milder winter weather. We to benefit customers (through reduced costs) and the sold more gas to industrial customers mostly because of remainder to be retained by BGE (which benefits higher usage by Bethlehem Steel and other industrial shareholders). Changes in off-system sales do not customers, and an increased number of customers. significantly impact earnings.

Base Rates During the quarter and nine months ended September 30, During the quarter and nine months ended September 30, 2000, revenues from off-system gas sales increased 2000, base rate revenues increased slightly compared to compared to the same periods of 1999 mostly because the same periods of 1999 mostly because on June 19, we sold more gas off-system at a higher price.

2000, the Maryland PSC authorized a S6.4 million annual increase in our base rates effective June 22, 2000.

30

Gas Purchased For Resale Expenses During the nine months ended September 30, 2000, Actual costs include the cost of gas purchased for resale earnings from our other nonregulated businesses to our customers and for off-system sales. Actual costs increased compared to the same period of 1999 mostly do not include the cost of gas purchased by delivery because of higher earnings from our financial service customers. investments and energy products and services businesses.

In addition, in 1999, we wrote-down a financial During the quarter and nine months ended September 30, investment and certain senior-living facilities, which had 2000, our gas costs increased compared to the same negative impacts in that year. These increases were periods of 1999 mostly because we bought more gas for partially offset by lower earnings from our Latin off-system sales and all of the gas purchased was at a American business primarily due to increased operating higher price. expenses in Guatemala.

Gas Operations and Maintenance Expenses In December 1999, we decided to exit the Latin During the quarter and nine months ended September 30, American portion of our power projects business as part 2000, gas operations and maintenance expenses of our strategy to improve our competitive position. We increased compared to the same periods of 1999 mostly discuss our strategy further in the Strategy section on because of timing of corporate administrative and page 19.

general expenses allocated to our business segments.

In June 1999, our financial investments business wrote Gas Depreciation and Amortization Expense down its investment in Capital Re stock by $3.6 million During the quarter and nine months ended September 30, after-tax, or $.02 per share. In September 1999, our 2000, gas depreciation and amortization expense was financial investments business wrote-down the about the same compared to the same periods of 1999. investment by an additional $17.3 million after-tax, or S.12 per share. These write-downs were recorded to Other Nonregulated Businesses reflect the valuation for the exchange of its shares of common stock in Capital Re for common stock of ACE Earnings Limited during these periods. This exchange is discussed Quarter Ended Nine Months Ended further in our 1999 Annual Report on Form 10-K.

September 30 September 30 2000 1999 2000 1999 In September 1999, our real estate and senior-living facilities business wrote-down certain senior-living facilities (In millions, except pershare amounts) by S3.4 million after-tax, or &.02 per share, related to the Revenues ............................ $187.7 $207.1 $557.4 $635.1 announcement of the sale of those facilities.

Operating exoenses ............... 156.2 233.0 496.7 637.1 Depreciation and Most of Constellation Real Estate Group's real estate and am ortization ...................... 5.8 2.8 16.6 9.0 senior-living projects are in the Baltimore-Washington Taxes other than corridor. The area has had a surplus of available land in income taxes ..................... 1.0 1.0 3.0 2.8 recent years and as a result these projects have been Operating income (loss) ........ $24.7 $(29.7) 41.1 $(13.8) economically hurt.

Net income (loss) .................. S5.7 $(27.7) $(2.3) $(31.6)

Constellation Real Estate's projects have continued to Earnings per share ................ S.04 S(.20) $(.0) $(.21) incur carrying costs and depreciation over the years.

Above amounts inchlde intercompanytransactionseliminatedin our Additionally, this business has been charging interest ConsolidatedFinancialStatements. payments to expense rather than capitalizing them for some undeveloped land where development activities During the quarter ended September 30, 2000, earnings have stopped. These carrying costs, depreciation, and from our other nonregulated businesses increased interest expenses have decreased earnings and are compared to the same period of 1999 mostly because of expected to continue to do so.

higher earnings from our financial investments business.

Our financial investments business had higher earnings Cash flow from real estate and senior-living operations due to an increase in its market performance and a 1999 has not been enough to make the monthly loan payments write-down of a financial investment that had a negative on some of these projects. Cash shortfalls have been impact in that year. In addition, our energy products and covered by cash obtained from the cash flows of, or services business had higher gross margins from its gas additional borrowings by, other nonregulated trading activities. subsidiaries.

31

We consider market demand, interest rates, the Consolidated Nonoperating Income availability of financing, and the strength of the economy and Expenses in general when making decisions about our real estate and senior-living projects. If we were to decide to sell Fixed Charges our projects, we could have write-downs. In addition, if During the quarter and nine months ended September 30, we were to sell our projects in the current market, we 2000, fixed charges increased compared to the same would have losses which could be material, although the periods of 1999 mostly because we had more debt amount of the losses is hard to predict. Depending on outstanding.

market conditions, we could also have material losses on any future sales. Income Taxes During the quarter and nine months ended September 30, Our current real estate and senior-living strategy is to 2000, our total income taxes increased compared to the hold each project until we can realize a reasonable value same periods of 1999 mostly because we had higher for it. Under accounting rules, we are required to write taxable income from our nonregulated businesses and an down the value of a project to market value in either of increase in state and local taxes as a result of two cases. The first is if we change our intent about a comprehensive changes to these laws. This increase was project from an intent to hold to an intent to sell and the partially offset by lower taxable income at BGE. We market value of that project is below book value. The discuss the comprehensive tax law changes in Note 4 of second is if the expected cash flow from the project is our 1999 Annual Report on Form 1O-K.

less than the investment in the project.

Financial Condition During the nine months ended September 30, 2000, we Cash Flows had more cash from financing activities compared to the Nine Months Ended same period of 1999 mostly because we issued more September 30 long-term debt and common stock. This was partially 2000 1999 offset by repayment of our long-term debt that matured.

(In millions) Security Ratings Cash provided by (used in):

Independent credit-rating agencies rate Constellation Operating Activities $588.8 $483.5 Energy and BGE's fixed-income securities. The ratings Investing Activities (728.4) (441.8) indicate the agencies' assessment of each company's Financing Activities 97.3 (159.0) ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how During the nine months ended September 30, 2000, we much it will cost each company to sell these securities.

generated more cash from operations compared to the The better the rating, the lower the cost ofthe securities same period in 1999 mostly because of changes in to each company when they sell them. Constellation working capital requirements. Energy and BGE's securities ratings at the date of this report are:

During the nine months ended September 30, 2000, we used more cash for investing activities compared to the Standard Moody's same period in 1999 mostly due to an increase in & Poors Investors Fiitch investments in new generation facilities. In addition, our Rating Group Service 1B1CA real estate and senior-living facilities business received less cash compared to the same period of 1999, due to ConstellationEnergy the sale of a project in 1999. We did not have a similar Unsecured Debt A- A3 A sale in 2000. BGE Mortgage Bonds AA A] A+

Unsecured Debt A A2 A Trust Originated Preferred Securities and Preference Stock A- "a2" A-32

Capital Resources "* regulation, legislation, and competition, Our business requires a great deal of capital. Our "° BGE load requirements, estimated annual amounts for the years 2000 through "* environmental protection standards, 2002, are shown in the table below. "° the type and number of projects selected for development, We will continue to have cash requirements for: "* the effect of market conditions on those projects,

"* working capital needs including the payments of "° the cost and availability of capital, and interest, distributions, and dividends, "* the availability of cash from operations.

"* capital expenditures, and Our estimates are also subject to additional factors.

"* the retirement of debt and redemption of preference Please see the Forward-LookingStatements section on stock. page 37.

Capital requirements for 2000 through 2002 include Effective July 1, 2000, all of BGE's generation assets were estimates of funding for existing and anticipated projects.

transferred to nonregulated subsidiaries of Constellation We continuously review and modify those estimates.

Energy. The discussion and table for capital requirements Actual requirements may vary from the estimates included below include these generation assets as part of the utility's in the table below because of a number of factors including:

regulated electric business through June 30, 2000. After that date, the capital requirements are included in the domestic merchant energy business.

Calendar Year Estimates 2000 2001 2002 (In millions)

Nonregulated Capital Requirements:

Investment requirements:

Domestic Merchant Energy $ 803 * $ 1,241 S 1,077 Other 37 48 41 Total investment requirements 840 1,289 1,118 Retirement of long-term debt 575 446 7 Total nonregulated capital requirements 1,415 1,735 1,125 Utility Capital Requirements:

Construction expenditures (excluding AFC):

Regulated Electric:

Generation (including nuclear fuel) 94 Transmission and distribution 177 177 171 Total regulated electric 271 177 171 Regulated Gas 56 56 52 Common 23 26 26 Total construction expenditures 350 259 249 Retirement of long-term debt and redemption of preference stock 122 194 147 Total utility capital requirements 472 453 396 Total capital requirements $1,887 $2,188 S1,521

  • Effective July 1, 2000, includes approximately $110 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business.

33

Capital Requirements ElectricTransmission and Distribution,and Gas DomesticMerchant Energy Business Regulated electric transmission and distribution, and gas Our domestic merchant energy business will require construction expenditures primarily include new business additional funding for growing its power marketing construction needs and improvements to existing business and developing and acquiring power projects. facilities.

Our domestic merchant energy business investment Funding for Capital Requirements requirements include the planned construction of 1,100 Domestic Merchant Energy Business megawatts of peaking capacity in the Mid-Atlantic/Mid Funding for the expansion of our domestic merchant West region by the summer of 2001 and an additional energy business is expected from internally generated 4,300 megawatts of peaking and combined cycle fiuds, commercial paper issuances, long-term debt, and production facilities scheduled for completion in 2002 other financing instruments by Constellation Energy and and beyond in the Mid-West and South regions. Longer its subsidiaries, and from time to time equity range, our plans are to own or control approximately contributions from Constellation Energy.

30,000 megawatts of generation capacity by 2005. For further information see the Strategy section on page 19. In addition, on October 23, 2000 we announced initiatives designed to advance our growth strategies in Electric Generation the domestic merchant energy business as discussed in Electric construction expenditures for our regulated the Subsequent Event section in the Notes to electric business include improvements to generating ConsolidatedFinancialStatements on page 11. As part plants and costs for replacing the steam generators at of these initiatives, our domestic merchant energy Calvert Cliffs through June 30, 2000. Thereafter, these business expects to initially reinvest its earnings and not expenditures are reflected in our domestic merchant pay a dividend to fund its growth.

energy business.

At September 30, 2000, Constellation Energy has a In March 2000, we received the license extension from the commercial paper program where it can issue up to $500 NRC that extends our operating licenses to 2034 for Unit 1 million in short-term notes to fund its nonregulated and 2036 for Unit 2 as discussed in the CurrentIssues businesses. To support its commercial paper program, CalvertCliffs License Extension section on page 23. If we Constellation Energy maintains two revolving credit do not replace the steam generators, we will not be able to agreements totaling $565 million, of which one facility operate these units through our operating licenses period. can also issue letters of credit. In addition, Constellation We expect the steam generator replacement to occur during Energy has access to interim lines of credit as required the 2002 refueling outage for Unit I and during the 2003 from time to time to support its outstanding commercial refueling outage for Unit 2. We estimate these Calvert paper.

Cliffs' costs to be:

BGE

$ 38 million in 2000, Funding for utility capital expenditures is expected from

$63 million in 2001, internally generated funds, commercial paper issuances, D

$ 91 million in 2002, and available capacity under credit facilities, the issuance of

$ 60 million in 2003. long-term debt, trust securities, or preference stock, and/or from time to time equity contributions from Additionally, our estimates of future electric generation Constellation Energy.

construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State At September 30, 2000, FERC authorized BGE to issue of Maryland nitrogen oxides emissions (NOx) reduction up to $700 million of short-term borrowings, including regulations as follows: commercial paper. In addition, BGE maintains $183 million in annual committed bank lines of credit and has

  • $ 55 million in 2000, $25 million in bank revolving credit agreements to

$55 million in 2001, and support the commercial paper program. In addition, BGE

  • $ 8 million in 2002. has access to interim lines of credit as required from time to time to support its outstanding commercial paper.

We discuss the NOx regulations and timing of expenditures in the EnvironmentalMatters section of the Notes to ConsolidatedFinancialStatements on page 14.

34

Other NonregulatedBusinesses ConsolidatedFinancialStatements beginning on page 14 BGE Home Products & Services may meet capital and in our 1999 Annual Report on Form 10-K in Item I.

requirements through sales of receivables. ComfortLink has Business - EnvironmentalMatters. These details include a revolving credit agreement totaling $50 million to provide financial information. Some of the information is about liquidity for short-term financial needs. costs that may be material.

Ifwe can get a reasonable value for our real estate projects, Accounting Standards Issued senior-living facilities, and other investments, additional In June 2000, the FASB issued Statement of Financial cash may be obtained by selling them. Our ability to sell or Accounting Standards (SFAS) No. 138, Accountingfor liquidate assets will depend on market conditions, and we CertainDerivativeInstruments and CertainHedging cannot give assurances that these sales or liquidations could Activities, that amends certain provisions of SFAS No.

be made. We discuss the real estate and senior-living 133, Accountingfor Derivative Instrumentsand facilities business and market conditions in the Other Hedging Activities and addresses a limited number of NonregulatedBusinessessection on page 31. implementation issues related to SFAS No. 133.

Other Matters In July 1999, the FASB issued SFAS No. 137 that delays Environmental Matters the effective date for SFAS No. 133 by one year.

We are subject to federal, state, and local laws and Therefore, we must adopt the provisions of SFAS No.

regulations that work to improve or maintain the quality of 133 in our financial statements for the quarter ended the environment. If certain substances were disposed of or March 31,2001.

released at any of our properties, whether currently operating or not, these laws and regulations require us to We are evaluating the implications of SFAS Nos. 133 remove or remedy the effect on the environment. This and 138, but have not determined the effects on our includes Environmental Protection Agency Superfund financial results. However, SFAS Nos. 133 and 138 will sites. You will find details of our environmental matters in not significantly impact our power marketing business as the EnvironmentalMatters section of the Notes to this business uses mark-to-market accounting.

Item 3. Quantitative and Qualitative Disclosures About Market Risk We discuss the following information related to our market risk:

"*risk associated with the purchase and sale of energy in a deregulated environment as discussed in the CurrentIssues Electric Competition section of Management's Discussion and Analysis on page 20,

"* financing activities in the Notes to ConsolidatedFinancialStatements on page 13, and

"*activities of our power marketing business in the Domestic MerchantEnergy Business section of Management's Discussion and Analysis beginning on page 25.

35

PART II. OTHER INFORMATION Item 1. Legal Proceedings Employment Discrimination The second type is claims by one manufacturer Miller v. Baltimore Gas and Electric Company, et al. Pittsburgh Coming Corp. (PCC) - against us and This action was filed on September 20, 2000 in the U.S. approximately eight others, as third-party defendants. On District Court for the District of Maryland. Besides April 17, 2000, PCC declared bankruptcy and we do not BGE, Constellation Energy Group, Constellation expect PCC to prosecute this claim.

Nuclear and Calvert Cliffs Nuclear Power Plant are also named defendants. The action seeks class certification These claims relate to approximately 1,500 individual for approximately 150 past and present employees and plaintiffs and were filed in the Circuit Court for alleges racial discrimination at Calvert Cliffs Nuclear Baltimore City, Maryland in the fall of 1993. To date, Power Plant. The amount of damages is unspecified, about 350 cases have been resolved, all without any however the plaintiffs seek back and front pay, along payments by BGE. We do not know the specific facts with compensatory and punitive damages. We believe necessary to estimate our potential liability for these this case is without merit. However, we cannot predict claims. The specific facts we do not know include:

the timing, or outcome, of it or its possible effect on our,

"* the identity of our facilities containing asbestos or BGE's, financial results.

manufactured by the manufacturer, Moore v. Constellation Energy Group - This action was "* the relationship (if any) of each of the individual filed on October 23, 2000 in the U.S. District Court for plaintiffs to us, the District of Maryland by an employee alleging "* the settlement amounts for any individual plaintiffs employment discrimination. Besides Constellation who are shown to have had a relationship to us, and Energy, BGE and Constellation Holdings, Inc. are also "* the dates on which/places at which the exposure named defendants. The Equal Employment Opportunity allegedly occurred.

Commission has previously concluded that it was unable to establish a violation of law. The plaintiff seeks, among Until the relevant facts for both types of claims are other things, unspecific monetary damages and back pay. determined, we are unable to estimate what our liability, if We believe this case is without merit. any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs Asbestos may cover a portion of any awards in the actions, our Since 1993, we have been involved in several actions potential liability could be material.

concerning asbestos. The actions are based upon the theory of "premises liability," alleging that we knew of Restructuring Order and exposed individuals to an asbestos hazard. The In early December 1999, the Mid-Atlantic Power Supply actions relate to two types of claims. Association (MAPSA), Trigen-Baltimore Energy Corporation and Sweetheart Cup Company, Inc. filed The first type is direct claims by individuals exposed to appeals of the Restructuring Order, which were consolidated asbestos. We described these claims in BGE's Report on in the Baltimore City Circuit Court. MAPSA also filed a Form 8-K filed August 20, 1993. We are involved in these motion to delay implementation of the Restructuring Order, claims with approximately 70 other defendants.

pending a decision on the merits of the appeals by the court.

Approximately 530 individuals that were never employees of BGE each claim $6 million in damages ($2 million On April 21,2000, the Circuit Court dismissed MAPSA's compensatory and $4 million punitive). These claims were appeal based on a lack of standing (the right of a party to filed in the Circuit Court for Baltimore City, Maryland in bring a lawsuit to court) and denied its motion for a delay of the summer of 1993. We do not know the specific facts the Restructuring Order. However, MAPSA filed an appeal necessary to estimate our potential liability for these claims. of this decision. On May 24, 2000, the Circuit Court The specific facts we do not know include: dismissed both the Trigen and Sweetheart Cup appeals.

"* the identity of our facilities at which the plaintiffs MAPSA subsequently filed several appeals with the allegedly worked as contractors, Maryland Court of Special Appeals, the Maryland Court of

"* the names of the plaintiffs employers, and Appeals, and the Baltimore City Circuit Court. The effect

"* the date on which the exposure allegedly occurred. of the appeals was to delay the implementation of customer choice in BGE's service territory.

To date, 27 of these cases were settled for amounts that were not significant.

However, on August 4, 2000, the delay was rescinded and Asset Transfer Order BGE retroactively adjusted its rates as if customer choice had On July 6, 2000, MAPSA and Shell Energy LLC filed, in been implemented July 1, 2000. the Circuit Court for Baltimore City, a petition for review and a delay of the Maryland PSC's order approving the On September 29, 2000, the Baltimore City Circuit Court transfer of BGE's generation assets issued on June 19, 2000.

issued an order upholding the Restructuring Order.

The Court denied MAPSA's request for a delay on August On October 27, 2000, MAPSA filed an appeal with the 4, 2000, and after a hearing on the petition on August 23, Maryland Court of Special Appeals challenging the 2000 issued an order on September 29, 2000 upholding the September 29, 2000 order issued by the Circuit Court. We Maryland PSC's order on the asset transfer. On October 27, believe that this petition is without merit. However, we 2000, MAPSA filed an appeal with the Maryland Court of cannot predict the timing, or outcome, of this case, which Special Appeals challenging the September 29, 2000 order could have a material adverse effect on our, and BGE's, issued by the Circuit Court. We also believe that this petition financial results. is without merit. However, we cannot predict the timing, or outcome, of this case, which could have a material adverse effect on our, and BGE's, financial results.

Item 5. Other Information Forward-Looking Statements We make statements in this report that are considered

  • operating our generation assets in a deregulated forward-looking statements within the meaning of the market without the benefit of a fuel rate adjustment Securities Exchange Act of 1934. Sometimes these clause, statements will contain words such as "believes,"

° loss of revenue due to customers choosing "expects," "intends," "plans," and other similar words. alternative suppliers, These statements are not guarantees of our future performance and are subject to risks, uncertainties and

  • higher volatility of earnings and cash flows, other important factors that could cause our actual
  • increased financial requirements of our nonregulated performance or achievements to be materially different subsidiaries, from those we project. These risks, uncertainties, and
  • inability to recover all costs associated with factors include, but are not limited to: providing electric retail customers service during the electric rate freeze period, and

"* general economic, business, and regulatory conditions, ° implications from the transfer of BGE's generation assets and related liabilities to nonregulated

"* energy supply and demand, subsidiaries of Constellation Energy, including the

"* competition, outcome of an appeal of the Maryland PSC's Order

  • federal and state regulations, regarding the transfer of generation assets.
  • availability, terms, and use of capital, Given these uncertainties, you should not place undue
  • nuclear and environmental issues, reliance on these forward-looking statements. Please see
  • weather, the other sections of this report and our other periodic
  • implications of the Restructuring Order issued by reports filed with the SEC for more information on these the Maryland PSC, including the outcome of factors. These forward-looking statements represent our estimates and assumptions only as of the date of this MAPSA's appeal, report.
  • commodity price risk, 37

Item 6. Exhibits and Reports on Form 8-K (a) Exhibit No. 3 By-laws of Constellation Energy Group, Inc.

Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges.

Exhibit No. 12(b) Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements.

Exhibit No. 27(a) Constellation Energy Group, Inc. Financial Data Schedule.

Exhibit No. 27(b) Baltimore Gas and Electric Company Financial Data Schedule.

(b) Reports on Form 8-K for the quarter ended September 30, 2000:

Date Filed Items Reported July 7, 2000 Item 2. Acquisition or Disposition of Assets Item 7. Financial Statements and Exhibits 38

SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONSTELLATION ENERGY GROUP, INC.

(Registrant)

BALTIMORE GAS AND ELECTRIC COMPANY (Registrant)

Date: November 14, 2000 Is/ D.A. Brune D. A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 39

EXHIBIT 12(a)

CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 12 Months Ended September December December December December December 2000 1999 1998 1997 1996 1995 (In Millions of Dollars)

Income from Continuing Operations (Before Extraordinary Loss) $ 298.7 $ 326.4 $ 305.9 $ 254.1 $ 272.3 $ 297.4 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 192.3 182.5 169.3 145.1 148.3 152.0 Adjusted Income $ 491.0 $ 508.9 $ 475.2 $ 399.2 $ 420.6 $ 449.4 Fixed Charges:

Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 256.5 $ 245.7 $ 255.3 $ 234.2 $ 203.9 $ 206.7 Earnings required for BGE Preference Stock Dividends 21.4 21.0 33.8 45.1 59.4 61.0 Capitalized Interest 11.6 2.7 3.6 8.4 15.7 15.0 Interest Factor in Rentals 2.2 1.8 1.9 1.9 1.5 2.1 Total Fixed Charges $ 291.7 $ 271.2 $ 294.6 $ 289.6 $ 280.5 $ 284.8 "x"-a-ramings(1) $ 771.1 $ 777.4 $ 766.2 $ 680.4 $ 685.4 $ 719.2 Ratio of Earnings to Fixed Charges 2.64 2.87 2.60 2.35 2.44 2.52 (1) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest.

EXHIBIT 12(b)

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS 12 Months Ended September December December December December December 2000 1999 1998 1997 1996 1995 (In Millions of Dollars)

Income from Continuing Operations (Before Extraordinary Loss) $ 146.0 $ 328.4 $ 327.7 $ 282.8 $ 310.8 $ 338.0 Taxes on Income 91.0 182.0 181.3 161.5 169.2 172.4 Adjusted Income $ 237.0 $ 510.4 $ 509.0 $ 444.3 $ 480.0 $ 510.4 Fixed Charges:

Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 184.1 $ 206.4 $ 255.3 $ 234.2 $ 203.9 $ 206.7 Capitalized Interest - 0.4 3.6 8.4 15.7 15.0 Interest Factor in Rentals 0.9 1.0 1.9 1.9 1.5 2.1 Total Fixed Charges $ 185.0 $ 207.8 $ 260.8 $ 244.5 $ 221.1 $ 223.8 Preferred and Preference Dividend Requirements: (1)

- Preferred and Preference Dividends $ 13.2 $ 13.5 $ 21.8 $ 28.7 $ 38.5 $ 40.6 Income Tax Required 8.2 7.5 12.0 16.4 20.9 20.4 Total Preferred and Preference Dividend Requirements $ 21.4 $ 21.0 $ 33.8 $ 45.1 $ 59.4 $ 61.0 Total Fixed Charges and Preferred and Preference Dividend Requirements $ 206.4 $ 228.8 $ 294.6 $ 289.6 $ 280.5 $ 284.8 Earnings (2) $ 422.0 $ 717.8 $ 766.2 $ 680.4 $ 685.4 $ 719.2 Ratio of Earnings to Fixed Charges 2.28 3.45 2.94 2.78 3.10 3.21 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 2.04 3.14 2.60 2.35 2.44 2.52 (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock.

(2) Earnings are deemed to consist of income from continuing operations (before extraordinary loss) that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.

Exhibit 13A [PROPRIETARY]

Additional Funding Assurances for Decommissioning Pre Realignment & Spin - Constellation Energy Group NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)

NRC minimum requirement for Unit 1 and 82% of Unit 2 (millions) $722 Funds transferred after 2% real rate of return to decommissioning credit (millions) $635 Amount assured through Parental Guarantee $87 FinancialTest II.A.2 Source: September 30, 2000 IO-Q (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy Unsecured Standard & Poor's Rating (September 2000) A Constellation Energy Unsecured Moody's Rating (September 2000) A3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth (Intangible Assets are $43 million) $3,109 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount) $87 Ratio of Tangible Net Worth to Guarantee Amount 35.7 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth $3,109 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof Total Assets $11,656 Total Foreign Assets $260 Total U.S. Assets $11,396 jAmount of Decommissioning Funds Assured for Unit 1 &2 (Guarantee Amount) $87 I ot u.S.

01atlo Assets to (Juarantee Amount I 131.0 1

EXHIBIT 13A (PROPRIETARY)(CONT.)

Post Realignment & Pre Spin NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)

NRC minimum requirement for Unit I and 82% of Unit 2 (millions) $722 Funds transferred after 2% real rate of return to decommissioning credit (millions) $635 Amount assured through Parental Guarantee $87 FinancialTest II.A.2 Source: Proforma September 30, 2000 (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy Unsecured Standard & Poor's Rating (September 2000) A Constellation Energy Unsecured Moody's Rating (September 2000)

A3 (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth (Intangible Assets are $43 million) $3,109 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount) $87 Ratio of Tangible Net Worth to Guarantee Amount 35.7 (iii) Tangible net worth of at least $10 million; and ITangible Net Worth $3,109 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof Total Assets $11,656 Total Foreign Assets $260 Total U.S. Assets $11,396 jAmount of Decommissioning Funds Assured for Unit l&2 (Guarantee Amount) $87 lRatio of U.S. Assets to Guarantee Amount 131.0

EXHIBIT 13A (PROPRIETARY)(CONTINUED)

Post Realignment & Post Spin NRC Financial Test for Parent Guarantees (10 CFR Part 30, App. A, § II.A.2)

NRC minimum requirement for Unit I and 82% of Unit 2 (millions) $722 Funds transferred after 2% real rate of return to decommissioning credit (millions) $635 Amount assured through Parental Guarantee $87 FinancialTest II.A.2 Source: Proforma September 30, 2000 (i) A current rating for its most recent bond issuance of AAA, AA, A, or BBB as issued by Standard and Poor's or AAA, AA, A, or BAA as issued by Moody's; and Constellation Energy expects to be investment grade after the spin (ii) Tangible net worth each at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof (Tangible net worth shall be calculated to exclude the net book value of the nuclear unit(s)); and Tangible Net Worth $1,467 Amount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount) $87 Ratio of Tangible Net Worth to Guarantee Amount 16.9 (iii) Tangible net worth of at least $10 million; and

[Tangible Net Worth $1,467 (iv) Assets located in the United States amounting to at least 90 percent of the total assets or at least six times the current decommissioning cost estimates for the total of all facilities or parts thereof (or prescribed amount if a certification is used), or, for a power reactor licensee, at least six times the amount of decommissioning funds being assured by a parent company guarantee for the total of all reactor units or parts thereof.

Total Assets $6,236 Total Foreign Assets $

Total U.S. Assets $6,236 IAmount of Decommissioning Funds Assured for Unit 1&2 (Guarantee Amount) $87 IRatio of U.S. Assets to Guarantee Amount 71.7

Exhibit 14 10 CFR § 50.75 (c) CALCULATION WORKSHEETS Unit 1 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt) 1,850 BWR Formula (104+0.009*1,850)

Base 1986 Cost (1986$) 120,650,000 Adjustment Factor (2000$) 3.1213 Adjusted Amount (2000$) 376,583,056 NRC Adjustment Factor Calculation NRC Adjustment Formula 0.65 L + 0.13 E + 0.22 B Factor L Factcor E Factor B Weight 0.65 0.13 0.22 2000$ 1.7790 1.22565 8.1890 1.1564 0.1633 1.8016 NRC Adjustment Factor 3.1213 Energy Factor Calculation Energy Factor Formula 0.54Px + 0.46Fx 1986$ 09/2000$ Factor Px: Power Factor 114.2 137.6 1.2049 Fx: Fuel Oil Factor 82 108.0 1.3171 Energy Factor 1.2565 Labor Factor Calculation 1986$ 09/2000$ Factor 130.5 232.16 1.7790

Exhibit 14 (Continued)

Unit 2 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt) 3,467 BWR Formula >3400MWt = 135 Base 1986 Cost (1986$) 135,000,000 Adjustment Factor (2000$) 3.1213 Adjusted Amount (2000$) 421,373,499 82% of Adjusted Amount 345,526,269 NRC Adjustment Factor Calculation NRC Adjustment Formula 0.65 L + 0.13 E + 0.22 B Factor L Factor E Factor B Weight 0.65 0.13 0.22 2000$ 1.7790 1.2565 8.1890 1.lb654 0.16r33 .816.U NRC Adjustment Factor 3.1213 Energy Factor Calculation Energy Factor Formula 0.54Px + 0.46Fx 1986$ 09/2000$ Factor Px: Power Factor 114.2 137.6 1.2049 Fx: Fuel Oil Factor 82 108.0 1.3171 Energy Factor 1.2565 Labor Factor Calculation 1986$ 09/2000$ Factor 130.5 232.16 1.7790

Exhibit 15A [PROPRIETARY]

PROJECTIONS OF EARNINGS CREDIT ON DECOMMISSIONING FUNDS USING 2% ANNUAL REAL RATE OF RETURN FOR NMP 1 AND NMP 2 Unit 1 Proiected Fund Performance and Underfunding Calculation Funds Transferred at Closing Non-Qualified Funds 76,800,000 Qualified Funds 189,200,000 I otal t-unds 266,UUU,UUU Beginning Additional Fund Return Year Balance Assurance Rate Fund Earnings Ending Balance 2001 266,000,000 54,495,836 2% 3,189,092 323,684,927 2002 323,684,927 2% 6,473,699 330,158,626 2003 330,158,626 2% 6,603,173 336,761,799 2004 336,761,799 2% 6,735,236 343,497,034 2005 343,497,034 2% 6,869,941 350,366,975 2006 350,366,975 2% 7,007,340 357,374,315 2007 357,374,315 2% 7,147,486 364,521,801 2008 364,521,801 2% 7,290,436 371,812,237 2009 371,812,237 2% 4,770,819 376,583,056 NRC Minimum Requirement 376,583,056 Ending Balance for 2009 376,583,056 Underrunded Amount Additional Funding Assured 54,495,836 2001 fund earnings are propated for 07/01/01 transaction close 2009 fund earnings are prorated for 08/22/09 license expiration

Exhibit 15A (PROPRIETARY)(continued)

Unit 2 Projected Fund Performance and Underfunding Calculation Funds Transferred at Closing Non-Qualified Funds 3,900,000 Qualified Funds 172,800,000 Total Funds 176,700,000 Beginning Additional Fund Return Year Balance Assurance Rate Fund Earnings Ending Balance 2001 176,700,000 32,523,302 2% 2,081,875 211,305,178 2002 211,305,178 - 2% 4,226,104 215,531,281 2003 215,531,281 - 2% 4,310,626 219,841,907 2004 219,841,907 - 2% 4,396,838 224,238,745 2005 224,238,745 - 2% 4,484,775 228,723,520 2006 228,723,520 - 2% 4,574,470 233,297,990 2007 233,297,990 - 2% 4,665,960 237,963,950 2008 237,963,950 - 2% 4,759,279 242,723,229 2009 242,723,229 - 2% 4,854,465 247,577,693 2010 247,577,693 - 2% 4,951,554 252,529,247 2011 252,529,247 - 2% 5,050,585 257,579,832 2012 257,579,832 - 2% 5,151,597 262,731,429 2013 262,731,429 - 2% 5,254,629 267,986,058 2014 267,986,058 - 2% 5,359,721 273,345,779 2015 273,345,779 - 2% 5,466,916 278,812,694 2016 278,812,694 - 2% 5,576,254 284,388,948 2017 284,388,948 - 2% 5,687,779 290,076,727 2018 290,076,727 - 2% 5,801,535 295,878,262 2019 295,878,262 - 2% 5,917,565 301,795,827 2020 301,795,827 - 2% 6,035,917 307,831,743 2021 307,831,743 - 2% 6,156,635 313,988,378 2022 313,988,378 - 2% 6,279,768 320,268,146 2023 320,268,146 - 2% 6,405,363 326,673,509 2024 326,673,509 - 2% 6,533,470 333,206,979 2025 333,206,979 - 2% 6,664,140 339,871,119 2026 339,871,119 - 2% 5,655,150 345,526,269 NRC Minimum Requirement 345,526,269 Ending Balance for 2009 345,526,269 Underfunded Amount Additional Funding Assured 32,523,302 2001 fund earnings are prorated for 07/01/01 transaction close 2026 fund earnings are prorated for 10/31/26 license expiration date

Exhibit 16 Affidavit of Robert E. Denton STATE OF MARYLAND )

) ss CITY OF BALTIMORE )

Robert E. Denton, upon being first duly sworn according to law, under oath, deposes and states:

1. I am President and Chief Executive Officer of Constellation Nuclear, LLC. I have reviewed the information contained in the "Application for Order and Conforming Administrative Amendments for License Transfers (NRC Facility Operating License Nos. DPR-63 and NPF-69)" and Exhibits thereto, and have been authorized by Constellation Nuclear, LLC to file this Affidavit on its behalf with respect to such information.
2. The information identified within brackets in the "Application for Order and Conforming Administrative Amendments for License Transfers (NRC Facility Operating License Nos. DPR-63 and NPF-69)," and the information in Exhibits 7A, 10A, 11 A, 13A and 16A to the Application contain financial projections related to the operation of Nine Mile Point Units 1 and 2 and confidential financial and corporate information. These documents constitute proprietary commercial and financial information that should be held in confidence by the

Nuclear Regulatory Commission pursuant to 10 CFR§ 9.17(a)(4) and the policy reflected in 10 CFR§ 2.790, because:

(i) This information is of a type that is held in confidence by Constellation Energy Group, Inc. and Constellation Nuclear, LLC and there is a rational basis for doing so because the information contains sensitive financial information concerning the projected revenues and operating expenses of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities.

(ii) This information is being and has been held in confidence by Constellation Energy Group, Inc. and Constellation Nuclear, LLC.

(iii) This information is being transmitted to the Nuclear Regulatory Commission in confidence.

(iv) This information is not available in public sources and could not be gathered readily from other publicly available information.

(v) Public disclosure of this information would create substantial harm to the competitive position of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities by disclosing internal financial projections for these entities and confidential financial and corporate information to other parties whose commercial interests may be adverse to those of Constellation Energy Group, Inc., Constellation Nuclear, LLC and other affiliated entities.

3. Accordingly, Constellation Energy Group, Inc. and Constellation Nuclear, LLC request that the designated documents be withheld from public disclosure pursuant to 10 CFR 2.790(a)(4) and 10 CFR 9.17(a)(4).

Subscribed and sworn to me, a Notary Public, in and for the county and state above named, this

.__day of/", 200W1 My Commission Expires:

(Notary7 ublic)

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