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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:}}
("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-1-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-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.
: 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 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,.
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
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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
("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 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 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 Hi 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
.r 2-00 TUE 12:43 AM ECONO LODGE FAX NO. 3153431222 P. 02/03 (MNJ?.I6 9:,'5/sT.
~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
("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
~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
~:~: ~>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
("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, 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.
1.13. "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.
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.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 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 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: 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 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-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.
: 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 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
("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 Journal under "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.
DCLAN01:128295 2
: 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 =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.
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 1 8 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 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.
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 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
*- SI1!70d ID3108 I1:00 003'ZcI/Z.
61:00 ooBe-/Z-.:-
P. 09/13 Th 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 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.
: 14. SIGNATORS' AUTHORTTYICOUNTERPARTS-The undersigned certify that they are authorized to execLte tis Agreement on behalf of their respecive Parttes.
This Agreement may be executed in two or more counterparts.
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.
: 15. NO DEDICATION OF FACLITIlES.
No underaking by PRODUCER or ,CUSTOMER
'::^ ---..' ---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',
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.
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;
.!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
: 14. SIGNATORS' AUTHORITYICOUNTERPART,.
The undersigned certify thaT they are authorized to cxewWut this Agreement on behalf of their respective Parties.
This Agreement may be executed in two or more counterparts, each of which shall be an original.
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
: 15. 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. 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:
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.
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 I i 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) 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
*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 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
$ 20.01 $ 19.98 Market price per share-year-end
$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
*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.
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
In creating the Constellation Energy Group holding company/&, Now we are putting in place the major pieces of the competitive
 
==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:
Be a leader in wholesale power marketing and generation in North America.
Provide premier utility services to Maryland while managing the transition to competitive energy markets.
In this report, you will read about the overall progress we have made in executing those strategies.
The results of our efforts point to the fact that your company is both determined and winning in the competitive energy marketplace.
Despite our progress, we are not satisfied with the recent performance of our stock. The investment return on Constellation Energy Group's stock, and the utility industry in general, has lagged behind the overall market. Still, we were one of the stronger performers among utilities in 1999, with total share holder return outpacing the Standard & Poor's Electric Utility Index by more than 19%. In early February 2000, our market price reached a 52-week high. The relative strength of our stock provides tangible evidence that investors are starting to reward some companies, like Constellation Energy Group, that are taking a focused approach to grow in a deregulated environment.
We are working hard on all fronts to ensure we continue to build shareholder value 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.0 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 a holding company. Following your approval at the annual shareholders' meeting, the Constellation Energy Group started trading on the New York Stock Exchange on May 3. Throughout the legislative session, we worked closely with key stakeholders and state lawmakers to develop the legal framework that would shape Maryland's electric market. In April, Governor Parris Glendening signed comprehensive legislation that is the foundation for opening Maryland's electric generation business to competition.
With legislation in place, we moved quickly to negotiate an equitable settlement agreement with all but one of the key parties to BGE's electric deregulation transition plan. On November 10, 1999, the Maryland Public Service Commission (PSC) approved that settlement, allowing all BGE electric customers to choose their electric suppliers beginning July 1, 2000. (For highlights of the settlement order, see page 6.) This historic decision resolves many critical details needed to ensure a smooth transition from a regulated to a competitive electric market. Most important, it enables Constellation Energy Group to move forward on sound financial footing, while providing BGE's customers with important safeguards.
Significantly for BGE residential customers, the settlement secures a 6.5% reduction in electric base rates for six years and financial protections for low-income customers.
For Constellation Energy Group, it allows us to recover a significant portion of our transition costs, as well as move our utility generation assets to our nonregulated subsidiaries.
While the settlement decision has been appealed in court, we believe that electric deregulation in the state and our company's plans can move forward.
Par, we launched a new growth-oriented energy company.business strategies we believe will make us winners.W i.nancial Results Reflect rowng Pains of Change The move to a deregulated electric generation supply market comes with some growing pains. A part of our settlement required that we recognize certain expenses related to the deregulation of our utility generating assets before July 1, 2000.Consequently, after accounting for one-time charges and the extraordinary loss related to deregulation, our reported earnings were $1.74 a share compared with $2.06 in 1998. Excluding these charges, our earnings per share in 1999 were $2.48 per share, a 12.7% increase over operating eamings of $2,20 in 1998.Despite this initial earnings reduction, we feel the settlement order is a good agreement that positions the company to successfully pursue opportunities in a competitive energy market.Utility earnings from operations, excluding the nonrecurring charges, increased about 5% in 1999 versus 1998. Diversified earnings from operations grew 67% over 1998, thanks to substantial contributions from Constellation Power Source, our power marketing business.Earnings and Dividends Dectared Pe Shore of Common Stock---~ip~ -------1995 19W6 1997 1998 1999 s Earnings per Share-Reported J Earrirgs per Share-Before Nonrecurring Charges 11ividends per Share Return on Average Common Equity H2% 1995 1996 1997 1998 1999 Common Stock Market Price and Book Value Per Share I Market Price per Share A Book Value per Share j I 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 one of a handful of customer-focused merchant energy companies able to deliver effective energy solutions in a competitive wholesale marketplace.
In fact, PHB Hagler Bailly, a leading management and economic consulting company in the energy industry, named Constellation Power Source the top U.S. power marketer in its Energy Industiy Outlook 2000. In 1998, we were a founding investor, along with a Goldman, Sachs & Co. affiliate, of Orion Power Holdings, Inc. Since then, Orion has steadily increased its generation portfolio.
When the acquisition of Duquesne Light Company's generation assets announced last year is completed, Orion's portfolio will 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 megawatt-hours.
This marks the tenth consecutive year they've set a record for total output. Calvert Cliffs Nuclear Power Plant generated 13.3 million megawatts, nearly matching its all-time production level set in 1998. We are expecting a decision from the Nuclear Regulatory Commission sometime this year on our application to extend the operating licenses for the Calvert Cliffs Nuclear Power Plant. Commission approval will allow these two units to operate for up to 20 years beyond the current licenses, extending operation dates to 2034 and 2036. BGE's distribution and customer service employees faced one of their most challenging years ever. The devastating ice storm in January was followed by Hurricane Floyd in September, which caused the worst damage to our system in our history. Our employees responded heroically during the restoration efforts of both storms, and we learned a lot from our efforts. Following an intense critique of that experience, we are implementing ways to improve service restoration and communications with customers during major outages.Advancing Our With deregulation legislation in place and our PSC settlement approved, we took major steps toward advancing our competitive business strategy.
As deregulation unfolds and we move forward, we will experience vast changes in the way we do business.
In the past, the majority of our earnings have come from BGE. That equation is changing.
Under deregulation, the delivery of electricity and gas will remain regulated, while both electric generation and gas supply will be competitive.
We'll Be Ready for Customer Choice Operationally, our first priority for the year 2000 is to have all systems ready to meet the July 1 deadline for opening the electric market in Maryland.
The transition will require major internal changes from an organizational standpoint.
To accomplish this, we're reorganizing our operations into three main business units the regulated BGE utility, our Constellation Power Source merchant energy company, and our nuclear subsidiary.
Our goal is to have these businesses operating smoothly to effect a seamless transition to customer choice. On July 1, 2000, pending full regulatory approval, BGE's generating assets will be transferred to our nonregulated subsidiaries.
Our fossil energy plants will become part of Constellation Power Source, while the Calvert Cliffs Nuclear Plant will move under Constellation Nuclear Group. BGE will, as a result, become a "pipes and wires" utility, continuing its historic role of delivering natural gas and electricity through its networks to homes and businesses throughout Central Maryland.I Strategyin 2 0 0 0 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. We're Building a Merchant Energy Organization Our growth strategy centers on the domestic wholesale energy market. This year, Constellation Power Source will take the next steps in building a full-scale merchant energy business by bringing together our power marketing, plant development, and plant operations.
And it will align our 6,200 megawatts of existing utility generating assets in the mid-Atlantic region with our national power marketing and risk management capabilities.
Our approach to this business is different from that of our competitors'.
Some power marketers are pure traders or speculators-they bet on whether it will be hot next July in a particular area of the country. Like any gamble, it can pay off for those who bet right. But that is not the type of business we're building.
Using its marketing expertise, Constellation Power Source identifies customer opportunities across the United States and determines how best to capitalize on them. We then use a portfolio approach to decide the right mix of power plants to develop, own, and operate and how much generation to control under contract.
This business model has worked well. It helps us maintain a balance between supply and demand in each region and optimizes our capital investments in power plants.Investing Today to Gain Advantage To promote growth in our domestic merchant energy business, we're committed to significant new capital investment over the next several years. We have placed orders for 5,100 megawatts of turbines including 800 megawatts of peaking units generating plants that are used during high periods of demand--to come on-line in 2001. We now have 17 power project sites under active development.
With our concentration on domestic projects, we will make a controlled exit from our Latin American investments when market conditions warrant.
Remaining a Regional Leader We've been serving the energy needs of Central Maryland for nearly two centuries and have always had a strong corporate presence in the community.
As Constellation Energy Group, we intend to remain a major local employer, continuing to serve our local customers while developing a Baltimore based business that serves wholesale customers throughout the United States. As we make this transition, BGE, our regulated utility, will continue to deliver energy reliably and affordably to our local customers.
At the same time, our other nonregulated affiliates will continue to provide a variety of competitive energy products and services to retail and business customers throughout the region.
Thanks to Ed Crooke During the last several years, we've learned a lot about our competitive strengths and how we can use them to create new business opportunities.
Through the process, we've developed a focus that will keep us positioned to take advantage of opportunities that leverage those strengths and avoid those markets or business sectors that don't. I want to express my sincere personal thanks to Ed Crooke for his tireless efforts in helping us get to this point. Ed energized our strategic planning efforts, sharpening our focus and building on our strengths.
Ed retired as Vice Chairman at the end of 1999 after 31 years of service. His 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.We're Determined and Winning! We said last year that we were "determined to win" in the competitive energy market. That hasn't changed. During 1999, our employees proved their determination every day as we continued our aggressive evolution into the type of company that can thrive and prosper in the deregulated merchant energy market. 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 ahead. But by the end of 2000 we will have transformed Constellation Energy Group into an entirely new energy company, streamlined in structure and focused on sustained growth in total shareholder return. I Christian H. Poindexter Chairman of the Board, President and Chief Executive Officer February 20,2000 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, 2000, most customers can choose their electric supplier.
BGE will continue to deliver the energy to all customers in areas it traditionally serves. 0 Also on July 1, BGE will reduce annual residential electric rates by about 6.5 percent, about $54 million, and then freeze those rates for six years. For residential customers who do not choose another electricity supplier, BGE will provide their electricity supply at fixed rates for up to six years under its Standard Offer Service.
M Electric distribution rates will be frozen for a four-year period for industrial and commercial customers.
Also, industrial customers will be able to choose from four payment options that will fix the electric energy rates and transition charges for a period of time. 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.
AD Starting on July 1, generation supply will be deregulated.
BGE, upon receiving all regulatory approvals, will transfer its generation assets to Constellation Energy Group's nonregulated affiliate companies.
SBGE will itemize rates and show separate components on its bill for delivery service, transition charges, standard offer service, transmission, universal service, and taxes. 3= BGE will be the default supplier, providing service for customers whose contracted electricity is not delivered or who choose to return to BGE for supply. BGE will reduce its generation assets by $150 million between July 1, 1999 and June 30, 2000. Universal service will be provided for low-income customers without increasing their bills.\ _/" \i eqImt-PI I UM LIAM "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.
The Constellation Energy Group's move to the new energy market took a big step in 1997 when we created our Constellation Power Source subsidiary From the outset, Constellation Power Source was built to buy, sell, and trade energy in the wholesale power market. But that was only a start. As we move into the competitive market, Constellation Power Source is using the results and experience it's gained to build a merchant energy company that will be our power source for the future.Building a Merchant Energy Company If results are beginnings, then the story of Constellation Energy's future starts with Constellation Power Source. In just over two years, Constellation Power Source has moved from a start-up energy marketing company to being named 1999's "Best Power Marketer" by PHB Hagler Bailly, an international energy consulting company.
In 2000, Constellation Power Source will go even further, bringing together existing pieces from the Constellation Energy Group to form one of the nation's premier merchant energy companies.
Constellation Power Source will no longer be simply an energy marketing company, but a merchant energy company. We are combining the existing power marketing and trading functions under Constellation Power Source with plant operations, development, and generation functions under our Constellation Power and BGE subsidiaries.
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 Getting There With Results pursue a merchant energy strategy, we needed results to prove we were going in the right direction, and Constellation Power Source delivered them. 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 in high-energy growth areas such as Texas and the Midwest.
Constellation Power Source has also captured a significant share of the standard offer electric supply service in New England. In the past year we doubled the size of our state-of the-art power trading floor to pursue more opportunities in the wholesale energy market.Constellation Power Source Quarterly Sales (Millions of MWh) 25-20 10 10 1Q 2Q 3Q 4Q 1Q 2Q 30 4Q 1Q 2Q 3Q 4Q 97 97 97 97 98 98 98 98 99 99 99 99 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 proven they're ready to meet the challenge.
I I For the tenth consecutive year, our fossil fuel plants in 1999 set a new generation record producing 19.4 million megawatt hours. Our employees did it safely, achieving one of the best safety records in our region.In addition to incorporating BGE's existing fossil plants to support power marketing and trading activities, Constellation Power Source is also looking to add generating assets in strategic locations.
Last year, Constellation Power Source committed capital to fund an additional 5,100 megawatts of generating capacity in strategic growth areas.Constellation Power Source has already brought under its umbrella the domestic independent power plants developed Generating Results at Our Power Plants Our generating plants produced more than electricity in 1999-they produced competitive results.The power behind our merchant energy strategy comes, in part, from BGE's generating plants. On July 1, 2000, BGE's fossil fuel power plants and the Calvert Cliffs Nuclear Power Plant are expected to become part of our nonregulated subsidiaries.
From that time on, the power they produce will be managed by our Constellation Power Source merchant energy company for the wholesale power market.On the way to that new market, our employees have worked to ensure our plants continue to improve so they're ready to generate safe, efficient, and competitively priced power. Generation highlights from 1999 included: Our fossil and nuclear plants combined set an all-time generation record for the second consecutive year, producing 32.7 million megawatt-hours-about a 1% increase over last year's record production.
by our Constellation Power, Inc., subsidiary.
Constellation Power, which has been operating in nonregulated power markets since 1985, brings a wealth of competitive experience as well as direct ownership positions in 28 energy projects located throughout the United States. Together with Goldman Sachs, Tokyo Electric Power Company, Inc., and Mitsubishi Corporation, we continue our investment interest in Orion Power Holdings, Inc., which buys existing power plants. With acquisitions announced last year, Orion's portfolio will have more than 5,200 megawatts of generating capacity throughout the Northeast and Upper Midwest regions of the United States. 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.  * ( After registering the lowest accident rate in the region in 1998, our fossil fuel plants continued to improve on safety, finishing the year with an OSHA rate of 1.32 accidents per 100 employees for the year-the best safety numbers in their history.  -For the first time ever our Calvert Cliffs Nuclear Power Plant received the highest rating given by the Institute of Nuclear Power Operations, which highlighted safety and teamwork as plant strengths.  -Calvert Cliffs' license renewal efforts took several major steps forward, as the Nuclear Regulatory Commission concluded there are neither safety nor environmental issues standing in the way of extending the plant's operating licenses an additional 20 years. The new operating licenses are expected to be issued this year.
"Nuclear power has an important role 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 Nuclear Group When electric deregulation takes effect in Maryland, the Calvert Cliffs Nuclear Power Plant will be moved under the unregulated umbrella of our new afiliate, the Constellation Nuclear Group, LLC. Power produced by Calvert Cliffs will be managed by our Constellation Power Source subsidiary.
In preparing itself for this new market, Calvert Cliffs also has produced impressive results. In 1999, the plant generated a near-record 13.3 million megawatt-hours.
And, for the first time ever, it received the highest rating given by the Institute of Nuclear Power Operations, which highlighted safety and teamwork as plant strengths.
In addition to nuclear generating capacity, Constellation Nuclear Group also includes our Constellation Nuclear Services subsidiary.
Formed in 1999, it provides nuclear consulting services specializing in nuclear power plant 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 experience other power companies can use.So far, Constellation Nuclear Services has signed 13 contracts with six utilities and two energy industry groups for license renewal and life-cycle related work. Building A Bright Future With our experience and accomplishments in both generation and wholesale power marketing and trading, we're building on a solid foundation for success in the competitive market. Moving forward, we will be able to meet customers' complex energy needs through structured transactions, manage their energy risks, and develop, own, and operate power plants that support our overall business.
That means we're not just building a premier merchant energy company, we're building a bright future for our customers, shareholders, and us.I I 0
I"BGE is truly a public service company, delivering the electricity and natural gas that are the lifeblood of Central Maryland's economy. 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 BGEo doubt, 1999 was a landmark year for both Maryland and BGE. Most important, the fundamental rules for deregulating Maryland's energy industry were set. Last year's results are dramatically changing the role of the local gas and electric utility. The changes ahead mark both an end and a beginning for BGE. What ends is BGE's 90-year monopoly on both supplying and delivering energy to its Central Maryland customers.
What begins is a company completely dedicated to the delivery of energy. In adapting to the new role in Maryland's energy market, BGE is taking another step in (ýýs 184-year evolution.
Next Step in a 184-Year Evolution As of November 1, 1999, all BGE natural gas customers could choose their gas supplier.
On July 1, 2000, the same will happen for all BGE electric customers.
While customers may choose another energy supplier, BGE will continue to deliver natural gas and electricity through its pipes and wires to their homes and businesses in Central Maryland.
While deregulation will change the role the utility has played over the past century, it won't change BGE's core mission delivering safe, economical, reliable, and profitable energy to its customers-something it's been doing for 184 years. Navigating the Challenges There is no question that given the challenges that deregulation presents, BGE has its work cut out for it in the years ahead. Within the context of a 6.5% residential electric delivery rate reduction, six-year rate freeze, and meeting its standard offer service obligations (see Settlement Order Highlights, page 6), BGE must achieve corporate profitability targets while maintaining and improving customer satisfaction, system safety, and reliability.
I Yet, it enters its new era well prepared for successful operations.
It has spent years getting ready for operating in a deregulated environment.
Now that many of the rules have been set, our BGE team is more focused than ever. Preparing for Customer Choice Since 1997, our BGE employees have been working toward a deadline that was set just last year-July 1, 2000. That's when Marylanders can choose their electric supplier and BGE's primary role will be to deliver that supply over its wires. Ensuring our systems are ready and customers are educated about their energy choices remain our top priorities and biggest challenges.
As active participants in the numerous Maryland Public Service Commission roundtables and technical groups, our employees have been working through the regulatory 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 under customer choice. In the new era, our employees will be responsible for enrolling customers who have chosen other suppliers.
They will also have to support competitive billing and unbundling of the current electric bill as well as settle load and capacity obligations between BGE, other suppliers, and the Pennsylvania-New Jersey Maryland Interconnection-the power grid we operate in.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 Delivery:
Still Regulated and Handled by BGE BGE Distribution Your Business Supplier A Power Plant II Your Home Supplier B Power Plant BGE 'll Power Plant Power Supply: This is the portion of the electric business that will be open to competition.
Electricity is generated by power plants and transmitted over high-voltage lines to local distribution systems. With deregulation, customers can choose to buy electricity from a number of different suppliers including other utilities, energy marketers or retailers, or BGE.  *Transmission rates will remain regulated by the Federal Energy Regulatory Commission.
Power Delivery and Restoration:
Once electricity reaches BGE's distribution system, it's delivered to homes or businesses over our power lines. While customers can choose another supplier, BGE will continue to be responsible for maintaining the lines that deliver the power. BGE will also continue to restore power after service interruptions and provide emergency services.I Power Generation:
Open to Competition To meet these requirements, the team is extending the ,..apabilities of our Customer Information System, developing new e-commerce interfaces with electricity suppliers, and implementing a new system to support load and capacity settlement.
Also we have designed a newly itemized bill and are working with the state to educate consumers so they can make informed choices.
Focused on Reliability, Power Quality and Costs Today the standards for power quality and service reliability are higher than they've ever been. That's because in the digital age, a split-second loss of power can shut down an entire production line. To provide customers the quality of service they require, we have been improving our delivery systems.
Using new technology, we are increasing reliability and power quality while reducing costs. An example is our award-winning System Control Integration Program, which brings substation monitoring and control systems into the 21st century. A team of employees designed and built what has become the prototype for future BGE substations.
The program automatically gives our system planners, operators, 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.
In addition to these benefits, this program reduces substation construction and maintenance costs because there are fewer components and less to maintain once it's built. Focused on Preventing Outages and Improving Restoration after Storms We continue to direct our focus from responding to outages to preventing them. Over the last five years, we have invested about $285 million to improve overall electric system perform ance. Notably, from 1994 to 1998, we reduced the average number of service interruptions by 36%. Even with these improvements, BGE's Utility Operations Group last year faced one of its most challenging years ever for weather-related events. A devastating ice storm hit in January. Then the wrath of Hurricane Floyd in September caused the worst damage to our system in company history.
Our employees responded in heroic fashion to both of these 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 taught us some valuable lessons in what we need to do to meet customers' expectations during major outages. As a result, we are implementing significant changes to our processes and systems to shorten restoration time and provide customers with better information about our progress.
Meeting Demand for Natural Gas Delivery There has been tremendous growth in demand for natural gas hookups over the past few years, and we've expanded our system to respond to it. Since January 1997, our gas employees have added more than 28,000 new homes and collected increased access fees to do that. In the last three years, they've achieved a nearly 7% annual ,, growth in operating income. They have achieved this growth while keeping gas rates economical for our customers.
Measuring Success by Customer Satisfaction The result of all of our efforts is ultimately measured by 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.
Over the years BGE employees have met the high standards set by customers, maintaining consistently high satisfaction ratings from residential customers and performing well above the national average when compared with other investor-owned utilities.
We have also seen marked improvement in how small business and large industrial customers view us, a record we continue to work to improve.
After deregulation of the supply side of the business, we will be an energy delivery company, serving marketers and suppliers as well as our traditional customer base. To reflect these changes, we are now expanding and modifying our customer satisfaction monitoring.
Now, more than ever, we need to know how we are measuring up in our customers' eyes.I I I Ultimately, a company is only as good as its employees.
Likewise, a community is only as strong as its citizens and businesses.
Generating Success with Powerful Partnerships Throughout its long history, BGE and its employees have formed powerful partnerships for positive change with the communities we serve. We begin 2000 as Constellation Energy 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:Constellation Energy Group and its employees led Maryland companies in both United Way and March of Dimes giving. We contributed more than $2.3 million to the United Way, and our $105,000 contribution to the March of Dimes was tops in the state. m Our corporate contributions program remained a leader, evaluating and responding to 1,650 requests for support, and donating over $5 million to programs that provide for those 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 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.
I=n To recognize our 1998 recycling efforts, the Environmental Protection Agency in 1999 named BGE a WasteWise Prograrr Champion.
During that period we recycled 562 tons of paper, 599 tons of aluminum, and 750 tons of utility poles.QU Always innovating, employees at our coal-fired power plants have developed a variety of ways to manage coal ash in an environmentally sound manner. Last year, our Brandon Shores plant opened a unique ash processing facility.
Owned and operated by Separation Technologies, Inc., it produced more than 30,000 tons of low-carbon ash that was then marketed to ready-mix concrete companies.
Next year's goal is 120,000 tons.At our PowerFest
'99 celebration, employees opened the gates and hosted a full day of fun and educational events for more than 1,500 residents who live near our Brandon Shores/Wagner power plant.
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 )1999 1998 1997 1996 1995 (Dollar amounts in millions, except per share amounts)Summary of Operations Total Revenues $3,786.2 $3,358.1 $3,307.6 $3,153.2 $2,934.8 Operating Expenses 3,026.3 2,617.0 2,584.0 2,483.7 2,239.1 Income From Operations 759.9 741.1 723.6 669.5 695.7 Other Income (Expense) 7.9 5.7 (52.8) 6.1 8.8 Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8 675.6 704.5 Fixed Charges 255.0 262.7 258.7 237.0 237.6 Income Before Income Taxes 512.8 484.1 412.1 438.6 466.9 Income Taxes 186.4 178.2 158.0 166.3 169.5 Income Before Extraordinary Item 326.4 305.9 254.1 272.3 297.4 Extraordinary Loss, Net of Income Taxes (66.3) ---Net Income $ 260.1 $ 305.9 $ 254.1 $ 272.3 $ 297.4 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 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 Dividends Declared Per Share of Common Stock $ 1.68 $ 1.67 $ 1.63 $ 1.59 $ 1.55 Summary of Financial Condition Total Assets $9,683.8 $9,275.0 $8,900.0 $8,678.2 $8,419.1 Capitalization Long-term debt $2,575.4 $3,128.1 $2,988.9 $2,758.8 $2,598.2 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 Common shareholders' equity 2,993.0 2,981.5 2,870.4 2,854.7 2,811.2 Total Capitalization
$5,758.4 $6,299.6 $6,159.3 $5,958.0 $5,920.6 Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.87 2.60 2.35 2.44 4.84 1.94 (0.12)5.62 4.11 2.34 2.52 Book Value Per Share of Common Stock $ 20.01 Number of Common Shareholders (In Thousands) 66.1$ 19.98 $ 19.44 $ 19.33 69.9 73.7$ 19.06 77.6 79.8 Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Constellation Energy Group Inc. and Subsidiaries Compounded Growth 5-Year 10-Year 6.35% 6.42% 7.10 6.88 3.65 4.78 (24.55) (12.75) 2.84 4.23 2.09 3.43 3.22 4.65 3.91 8.61 2.84 2.96 (1.72) 0.65 2.47 0.72 (2.05) (1.53) 2.16 1.99 4.25 5.30 (0.07) 2.18 (Utility Operating Statistics )I 1998 1997 1996 1995 Compounded Growth Electric Operating Statistics Revenues (In Millions)
Residential Commercial Industrial System Sales Interchange and Other Sales Other Total Sales (In Thousands)-MWH Residential Commercial Industrial System Sales Interchange and Other Sales Total Customers (In Thousands)
Residential Commercial Industrial Total Average Use per Residential Customer-KWH Average Rate per KWH (System Sales)-Residential Commercial Industrial Peak Load (One-Hour)-MW Capability at Summer Peak-MW System Load Factor Gas Operating Statistics Revenues (In Millions)
"-'- Residential -Excluding Delivery Service -Delivery Service Commercial-Excluding Delivery Service -Delivery Service Industrial -Excluding Delivery Service -Delivery Service System Sales Off-System Sales Other Total Sales (In Thousands)-DTH Residential -Excluding Delivery Service -Delivery Service Commercial-Excluding Delivery Service -Delivery Service Industrial -Excluding Delivery Service -Delivery Service System Sales Off-System Sales 5-Year 10-Year$ 975.2 $ 948.6 939.3 912.9 204.3 211.5 2,118.8 2,073.0 112.1 120.8 29.1 27.0 $2,260.0 $2,220.8 11,349 10,965 13,565 13,219 4,350 4,583 29,264 28,767 4,785 5,454 34,049 34,221 1,021.4 1,009.1 107.7 106.5 4.7 4.6 1,133.8 1,120.2 11,111 10,866 8.59 8.65 6.92 6.91 4.70 4.62 6,383 6,045 6,522 6,422 55.7% 57.4% $ 298.1 $ 279.2 11.5 4.9 79.3 75.6 24.4 19.4 8.2 8.0 16.1 16.0 437.6 403.1 42.9 40.9 7.7 7.2 $ 488.2 $451.2 34,272 33,595 4,468 1,890 11,733 11,775 20,288 16,633 1,367 1,412 33,118 34,798 105,246 100,103 15,543 16,724 Total 120.789 116.827 Customers (In Thousands)
Residential 543.5 532.5 524.5 516.5 506.8 Commercial 39.9 39.6 39.3 38.9 38.4 Industrial 1.3 1.3 1.3 1.3 1.3 Total 584.7 573.4 565.1 556.7 546.5 Average Use per Residential Customer (Excluding Delivery Service)--Therms 631 631 762 848 794 Average Rate per Therm-$ Residential (Excluding Delivery Service) Commercial (Excluding Delivery Service) Industrial (Excluding Delivery Service) Peak Day Sendout (In Thousands)-DTH Peak Day Capability (In Thousands)-DTH
.87 .68 .60 727.8 836.6.83 .64 .57 658.4 833.0.81 .62 .57 765.0 870.0.73 .55 .59 709.0 870.0.62 .47 .41 706.3 847.0 1.76 1.20 1.03 1.09 -(0.74) 1.70 1.19 (4.85) (2.65) 6.00 3.61 5.92 2.92 5.46 1.84 (0.91) 0.93 (0.25) 0.95 Utility operating statistics do not reflect the elimination of intercompany transactions.
Constellation Energy Group Inc. and Subsidiaries 1999$ 932.5 $ 958.7 $ 955.2 0.92% 4.16% 892.6 861.3 879.4 1.95 3.45 211.9 207.6 208.5 (0.13) 0.63 2,037.0 2,027.6 2,043.1 1.26 3.45 132.7 155.9 167.0 (1.02) 20.20 22.3 25.5 21.0 8.79 3.87 $2,192.0 $2,209.0 $2,231.1 1.22 3.86 10,806 11,243 10,966 1.24 1.85 12,718 12,591 12,635 1.89 2.05 4,575 4,596 4,591 (0.38) 0.21 28,099 28,430 28,192 1.29 1.67 6,224 7,580 8,149 (3.38) 23.18 34,323 36,010 36,341 0.54 2.98 1,001.0 995.2 988.2 0.86 1.12 105.9 104.5 103.4 1.11 1.25 4.5 4.3 4.1 3.28 4.25 1,111.4 1,104.0 1,095.7 0.89 1.14 10,794 11,297 11,097 0.38 0.72 8.63 8.53 8.71 (0.32) 2.26 7.02 6.84 6.96 0.03 1.37 4.63 4.52 4.54 0.26 0.44 5,980 5,955 5,947 1.12 1.87 6,741 6,800 6,731 (0.60) 0.57 56.9% 57.5% 57.2% 0.36 (0.30) $ 321.7 $ 320.1 $ 248.3 2.56 2.09 0.5 -113.5 125.1 109.9 (8.10) (3.45) 12.9 7.2 3.7 60.37 18.68 11.4 17.1 16.7 (16.50) (7.76) 17.2 14.6 16.3 10.89 (3.38) 477.2 484.1 394.9 1.03 0.89 37.5 26.6 6.9 6.6 5.6 7.35 (3.76) $ 521.6 $ 517.3 $ 400.5 3.00 1.72 39,958 43,784 40,211 (3.18) (1.49) 205 -18,435 22,698 23,612 (13.13) (6.08) 12,964 8,755 6,982 25.60 13.38 2,016 2,887 4,102 (20.88) (9.47) 38,791 36,201 35,925 (0.43) (1.73) 112,369 114,325 110,832 (0.65) (0.50) 14,759 9,968 127.128 124.293 110.832 2.13 0.88 I Introduction On April 30, 1999, Constellation Energy Group, Inc.  (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE) and Constellation Enterprises, Inc. Constellation Enterprises was previously owned by BGE. Constellation Energy's subsidiaries primarily include BGE and a group of energy services businesses focused mostly on power marketing and merchant generation in North America.
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.
Our energy services businesses are: "* Constellation Power Source, T M Inc.-wholesale power marketing, "* Constellation PowerM Inc. and Subsidiaries-power projects, "* Constellation Energy Source,TM Inc.--energy products and services, "* Constellation Nuclear GroupM LLC-nuclear generation and consulting services, "* BGE Home Products & Services, T M Inc. and Subsidiaries-home products, commercial building systems, and residential and small commercial gas retail marketing, and "* District Chilled Water General Partnership (ComfortLink) -a general partnership, in which BGE is a partner, that provides cooling services for commercial customers in Baltimore.
Our other businesses are:
* Constellation Investments, T M Inc.-financial investments, and
* Constellation Real Estate Group,TM Inc.-real estate and senior-living facilities.
References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively.
References in this report to the "utility business" are to BGE.In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy including:
"* what factors affect our business, "* what our earnings and costs were in 1999 and 1998, "* why earnings and costs changed from the year before, "* where our earnings came from, "* how all of this affects our overall financial condition, "* what our expenditures for capital projects were in 1997 through 1999, and what we expect them to be in 2000 through 2002, and "* where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 41, which present the results of our operations for 1999, 1998, and 1997. We analyze and explain the differences between periods by operating segment. Our analysis is important in making decisions about your investments in Constellation Energy. Also, this discussion and analysis is based on the operation of the electric generation portion of our utility business under current rate regulation.
The electric utility industry is under going rapid and substantial change. On April 8, 1999, Maryland enacted legislation authorizing customer choice and competition among electric suppliers.
On November 10, 1999, the Maryland Public Service Commission (Maryland PSC) issued Order No. 75757 (Restructuring Order) approving a Stipulation and Settlement Agreement between BGE and a majority of the active parties involved in the electric restruc turing proceeding that resolves the major issues surrounding electric restructuring.
See the "Electric Restructuring" section on page 24 and Note 4 on page 58 for a detailed discussion of the Restructuring Order. Our electric business will change significantly beginning July 1, 2000 as we enter into retail customer choice for electric generation and our generation assets are transferred to nonregulated subsidiaries of Constellation Energy. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance.
Constellation Energy Group Inc. and Subsidiaries SManagement's Discussion and AnaLysis) of Financial Condition and Results of Operations Strategy " M The change toward customer choice will significantly impact our business going forward. In response to this change, we regularly evaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. We are realigning our organization combining all of our domestic merchant energy businesses.
We will continue to invest in the growth of these businesses, with the objective of providing new sources of earnings in anticipation of lower electric utility revenues.
In addition, we might consider one or more of the following strategies:
"* the complete or partial separation of our transmission and distribution functions, "* 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.
We cannot predict whether any of the strategies described above may actually occur, or what their effect on our financial condition or competitive position might be. However, with the shift toward customer choice, competition, and the growth of our nonregulated subsidiaries, various factors Will affect our financial results in the future. These factors include, but are not limited to, operating our currently regulated generation assets in a deregulated market beginning July 1, 2000 without the benefit of a fuel rate adjustment clause, the loss of revenues due to customers choosing alternate suppliers, higher volatility of earnings and cash flows, and increased financial requirements of our nonregulated subsidiaries.
Please refer to the "Forward Looking Statements" section on page 39 for additional factors.Current Issues Competition-Electric Electric utilities are facing competition on various fronts, including:
"* construction of generating units to meet increased demand for electricity, "* sale of electricity in bulk power markets, "* competing with alternative energy suppliers, and "* electric sales to retail customers.
On April 8, 1999, Maryland enacted legislation authorizing customer choice and competition among electric suppliers.
In addition, on November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring.
These matters are discussed further in the "Electric Restructuring" section on page 24 and Note 4 on page 58. As a result of the deregulation of BGE's electric generation, no earlier than July 1, 2000, and upon receipt of all regulatory approvals, we expect that BGE will transfer, at book value, its nuclear generating assets and its nuclear decommissioning trust fund to a subsidiary of Constellation Nuclear Group, LLC. In addition, we expect that BGE will transfer, at book value, its fossil generating assets and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to a nonregulated subsidiary of Constellation Energy. In total, these generating 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.We expect BGE to transfer approximately
$278 million of tax exempt debt to our nonregulated subsidiaries related to the transferred assets and that BGE will receive approximately
$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. Under the Restructuring Order, BGE will provide standard offer service to customers at fixed rates over various time periods during the transition period for those customers that do not choose an alternate supplier once customer choice begins July 1, 2000. In addition, the electric fuel rate will be discontinued effective July 1, 2000. Nonregulated subsidiaries of Constellation Energy will provide BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Standard offer service will be competitively bid thereafter.
Nonregulated subsidiaries of Constellation Energy will obtain the energy and capacity to supply BGE's standard offer service obligations from the Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants, supplemented with energy purchased from the wholesale energy market as necessary.
Our earnings will be exposed to the risks of the competitive whole sale electricity market to the extent that our nonregulated subsidiaries have to purchase energy and/or capacity or generate energy to meet obligations to supply power to BGE at market prices or costs, respectively, which may approach or exceed Constellation Energy Group Inc. and Subsidiaries I I BGE's standard offer service rates. We will also be affected by operational risk, that is, the risk that a generating plant is not available to produce energy when the energy is required.
Until July 1, 2000, we will continue to recover our cost of electric fuel as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. After July 1, 2000, any energy purchased to meet BGE's load commitments will become a cost of doing business in the newly competitive marketplace.
Therefore, if BGE provides standard offer service at fixed rates to its customers that do not select an alternative provider as required under the terms of the Restructuring Order, and the load demand exceeds our capacity to supply energy due to a plant outage, we would be required to purchase additional power in the wholesale energy market. If the price of obtaining energy in the wholesale market exceeds the fixed standard offer service price, our earnings would be adversely affected.
Imbalances in demand and supply can occur not only because of plant outages, but also because of transmission constraints or due to extreme temperatures (hot or cold) causing demand to exceed available supply. We will use appropriate risk management techniques consistent with our business plan and policies to address these issues. We cannot estimate the impact of the increased financial risks associated with this transition.
However, these financial risks could have a material impact on our, and BGE's, financial results.
Competition-Gas Currently, no regulation exists for the wholesale price of 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 November 1, 1999, all BGE residential customers have the option to purchase gas from other suppliers.
Early Retirement Program In recognition of the changing business environment, in 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.Calvert Cliffs License Extension In 1998, we filed an application with the Nuclear Regulatory . Commission (NRC) for a 20-year license extension for Calvert Cliffs to extend its license beyond 2014 for Unit 1 and 2016 for Unit 2. License renewal evaluations focus on age-related issues in long-lived passive components (passive components include buildings, the reactor vessel, piping, ventilation ducts, electric cables, etc.). We must demonstrate that we can ensure that these passive components will continue to perform their intended functions through the renewal period. The NRC will also consider the impact of the 20-year license extension on the environment.
According to the NRC's timetable, approval of BGE's application is expected in April 2000. However, we cannot predict the actual timing of the NRC's decision, or the impact, if any, on our financial results. If we do not receive the license extension, we may not be able to operate the Calvert Cliffs units beyond 2014 and 2016. BGE is currently involved in a lawsuit titled National Whistleblower Center v. Nuclear Regulatory Commission and Baltimore Gas and Electric Company regarding its license extension process. The matter involves an appeal of the NRC's dismissal of Whistleblower's petition to intervene in the license renewal proceeding.
At issue was the NRC's adoption of a streamlined procedure for the proceeding, including the requirement that any requests for extensions 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 ultimately dismissed Whistleblower's petition to intervene.
This matter is pending before the court. Environmental and Legal Matters You will find details of our environmental matters in Note 10 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 Report on Form 10-K under Item 3. Legal Proceedings.
Some of the information is about costs that may be material to our financial results.
Year 2000 We did not experience any significant problems associated with the year 2000 issue. Accounting Standards Issued We discuss recently issued accounting standards in Note 1 on page 54.I Constellation Energy Group Inc. and Subsidiaries I
Results of Operations this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments.
Overview Total Earnings Per Share of Common Stock 1999 1998 1997 Utility business $2.03 $1.93 $1.94 Diversified businesses
.45 .27 .34 Total earnings per share before nonrecurring charges included in operations Nonrecurring charges included in operations:
Hurricane Floyd (see Note 2 on page 55) Write-off of merger costs (see Note 2 on page 55) 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)2.48 (.03)(.12) S(.1l)(.04)Total earnings per share before extraordinary item 2.18 Extraordinary loss (see Note 4 on page 59) (.44) Total e-arnings per share $1.74 $1999 Our 1999 total earnings decreased
$45.8 million, or $.32 per share, compared to 1998. Our total earnings decreased mostly because we recorded an extraordinary charge of $66.3 million, or $.44 per share, associated with the deregulation of the electric generation portion of our business.
Our 1999 total 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.In 1999, we had higher utility earnings before the extraordinary charge compared to 1998 mostly because we sold more electricity and gas this year, and we settled a capacity contract 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 higher depreciation and amortization expense mostly due to the $75.0 million, or $48.8 million after-tax, amortization of the regulatory asset recorded in 1999 for the reduction of our generation plant under the Restructuring Order. We discuss our utility earnings and the Restructuring Order in more detail in the "Utility Business" section on page 24.2.20 2.2 In 1999, diversified business earnings before nonrecurring charges increased compared to 1998 mostly because of higher earnings from our power marketing business.
We discuss our diversified business earnings, including the -write-downs, further in the "Diversified Businesses" section (.25) beginning on page 31. 1998 (.04) Our 1998 total earnings increased
$51.8 million, or $.34 per share, compared to 1997. Our total earnings increased mostly -because 1997 results reflect our write-off of costs associated with the terminated merger with Potomac Electric Power Company, and our real estate and senior-living facilities (m0) (.31) business' write-down of its investments in two real estate projects.
This increase was partially offset by: 2.06 1.72 -our real estate and senior-living facilities business' write-down of its investment in a real estate project --in 1998, and 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.In 1998, diversified business earnings before nonrecurring charges decreased compared to 1997 mostly because of lower earnings from our real estate and senior-living facilities and financial investments businesses.
This decrease was partially offset by higher earnings from our power projects and power marketing businesses.
Constellation Energy Group Inc. and Subsidiaries I
Utility Business Before we go into the details of our electric and gas operations, we believe it is important to discuss factors that have a strong influence on our utility business performance:
electric restructuring, regulation by the Maryland PSC, the weather, and other factors, including the condition of the economy in our service territory.
Electric Restructuring 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 accompanying tax legislation is discussed in detail in Note 4 on page 58. 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 alternative 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.
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. 
"* 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. 
"* 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.
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.
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.
BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated.
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.
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.
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.
Generally, rate increases improve our utility earnings because they allow us to collect more revenue.
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.
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.
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.
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.
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.
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.
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.
Cooling degree days result when the average daily actual temperature exceeds the 65 degree baseline.
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.
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.
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.
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.
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.
These factors include the strength of the economy in our service territory.
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:
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
$53.9 million, or $.37 per share, compared to 1998. Our 1998 total utility earnings increased
$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.
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
$2.4 billion.Constellation Energy Group Inc. and Subsidiaries
/
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
$278 million of tax exempt debt to our nonregulated subsidiaries related to the transferred assets and that BGE will receive approximately
$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.
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.
The total assets, liabilities, and common share holders' equity of Constellation Energy will not change as a result of the transfer.
Electric Revenues "The changes in electric revenues in 1999 and 1998 compared the respective prior year were caused by: 1999 1998 (In millions)
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.
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.
This decrease was partially offset by an increase in the number of industrial customers.
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 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.
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.
Fuel Rates In 1999, fuel rate revenues increased compared to 1998 mostly because we sold more electricity.
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.
Interchange and Other Sales "Interchange and other sales" are sales in the PJM (Pennsylvania-New Jersey-Maryland)
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.
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
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)
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 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.
In 1998, electric operations and maintenance expenses increased
$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
$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
$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
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.
We do not expect the impact of customer choice to have a material effect on our, and BGE's, financial results.
Gas Revenues The changes in gas revenues in 1999 and 1998 compared to the respective prior year were caused by: 1999 1998 (In millions)
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.
This was partially offset by lower usage per customer.
We sold more gas to commercial customers mostly because of higher usage per customer, colder winter weather, and an increased number of customers.
We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers.
Usage by Bethlehem Steel decreased due to a shut-down from June to August for an upgrade to their facilities.
In 1998, we sold less gas to residential and commercial customers mostly for two reasons: milder weather and lower usage per customer.
This was partially offset by the increase in the number of customers.
We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers.
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
$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
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.
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.
In 1998, earnings from our other energy services businesses increased compared to 1997 due to improved results from our energy products and services business.
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.
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.
This increase was artially offset by lower earnings from our financial investments
"--business.
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.
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.
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.
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.
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.
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.
Constellation Energy Group Inc. and Subsidiaries I
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.
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.
Cash shortfalls have been covered by cash obtained from the cash flows of other diversified subsidiaries.
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.
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.
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.
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.
Consolidated Nonoperating Income and Expenses Other Income and Expenses In September.
1995, we signed an agreement to merge with Potomac Electric Power Company after all necessary regulatory approvals were received.
In December 1997, both companies mutually terminated the merger agreement.
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
$7.7 million compared to 1998 mostly because we had less BGE preference stock outstanding.
In 1998, fixed charges increased
$4.0 million compared to 1997 mostly because we had more debt outstanding.
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
$8.2 million compared to 1998 because we had higher taxable income from both our utility operations and our diversified businesses.
In 1998, income taxes increased
$20.2 million compared to 1997 because we had higher taxable income from both our utility operations and our diversified businesses.
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
,,ash Flows 1999 1998 (In millions)Cash provided by (used in): Operating Activities Investing Activities Financing Activities
$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.
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.
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.
This was partially offset by a $33.8 million decrease in utility construction expenditures.
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
$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.
Security Ratings Independent credit-rating agencies rate Constellation Energy and BGE's fixed-income securities.
The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities.
These ratings affect how much it will cost each company to sell these securities.
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.
We continuously review and modify those estimates.
Actual investment requirements may vary from the estimates included in the table below because of a number of factors including:
"* 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.
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)
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 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:
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 Our estimates of future electric construction expenditures do not include costs to build more generating units to meet load requirements for BGE customers.
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
$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.
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
$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.
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.
To support its commercial paper program, Constellation Energy maintains
$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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
Given these uncertainties, you should not place undue reliance on these forward looking statements.
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.
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.
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 the effectiveness of internal control procedures.
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.
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.
The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee.
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.
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)
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)
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.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
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)
(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 Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Constellation Energy Group Inc. and Subsidiaries 1999
( 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
$9,683.8 $9,275.0 See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
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)
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 Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
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)
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.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Constellation Energy 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 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.
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.) 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.
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)
$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.
Certain prior-year amounts have been reclassified to conform with the current year's presentation.
Constellation Energy Group Inc. and Subsidiaries Notes to Consolidated Financial Statements
~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.
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.
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.
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:
consolidation, the equity method, and the cost method. Consolidation We use consolidation when we own a majority of the voting stock of the subsidiary.
This means the accounts of our subsidiaries are combined with our accounts.
We eliminate intercompany balances and transactions when we consolidate these accounts.
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.
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.
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.
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.
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.
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 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.
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.
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.
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 EITF No. 97-4 for BGE's electric generation business.
BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated.
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.
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.
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.
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 31, 1998, no short-term borrowings were outstanding since Constellation Energy was not established until April 30, 1999 as discussed in Note 1 on page 49. In 1999, Constellation Energy arranged a $135 million revolving credit agreement for short-term financial needs, including letters of credit. This agreement also supports Constellation Energy's commercial paper notes. This facility replaced a similar facility at one of Constellation Energy's diversified businesses.
At December 31, 1999, letters of credit totaling $23.1 million were issued under this facility.In addition, Constellation Energy had unused committed bank lines of credit totaling $35 million and interim lines totaling $125 million supporting its commercial paper notes at December 31, 1999. The weighted average effective interest rate for Constellation Energy's commercial paper notes was 5.68% for the year ended December 31, 1999. BGE At December 31, 1999, BGE had $129.0 million outstanding consisting entirely of commercial paper notes. At December 31, 1998, BGE had no short-term borrowings outstanding.
At December 31, 1999, BGE had unused committed bank lines of credit totaling $123 million supporting the commercial paper notes compared to $113 million at December 31, 1998. These amounts do not include unused revolving credit agree ments of $60 million at December 31, 1999 and $100 million 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 issuance.
We summarize our long-term debt in the Consolidated Statements of Capitalization.
As you read this section, it may be helpful to refer to those statements.
BGE BGE's First Refunding Mortgage Bonds BGE's first refunding mortgage bonds are secured by a mortgage lien on nearly all of its assets, including all utility properties and franchises and its subsidiary capital stock. Capital stock pledged under the mortgage is that of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. When BGE transfers its generating assets to subsidiaries of Constellation Energy, these assets will remain subject to the lien of BGE's mortgage.
However, BGE will remain liable for this debt after the assets are transferred.
BGE is required to make an annual sinking fund payment -ach August 1 to the mortgage trustee. The amount of the is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repur chases or calls for early redemption.
However, the trustee cannot call the following bonds for early redemption:
"* 5MA% Installment Series, due 2002 -6%% Series, due 2003 "* 5M% Series, due 2000 -5%% Series, due 2004* 8 3 A% Series, due 2001 -74% Series, due
* 7T% Series, due 2002 -6%% Series, due
* 6X% Series, due 2003 Holders of the Remarketed Floating Rate Series Due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1.2007 2008 Constellation Energy Group Inc. and Subsidiaries I
BGE's Other Long-Term Debt We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 1999 in the following table.Weighted-Average Interest Rate 8.10% 7.33 6.66 6.66 6.08 Maturity Dates 2000-2006 2000-2003 2001-2006 2006-2012 2001-2008 Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium term notes with put options.Series E Notes 6.75%, due 2012 6.75%, due 2012 6.73%, due 2012 Principal (In millions)
$60.0 25.0 25.0 Put Option Dates June 2002 and 2007 June 2004 and 2007 June 2004 and 2007 BGE has $60 million of revolving credit agreements with several banks that are available through 2000. At December 31, 1999, BGE had no outstanding borrowings under these agreements.
These banks charge us commitment fees based on the daily average of the unborrowed amount, and we pay market interest rates on any borrowings.
These agreements also support BGE's commercial paper notes, as described in Note 7 on page 65. BGE Obligated Mandatorily Redeemable Trust Preferred Securities On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%. The Trust used the net proceeds from the issuance of the common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the debentures are paid at maturity or upon any earlier redemption.
BGE has the option to redeem the debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur. Constellation Energy Group Inc. and Subsidiaries Series 7.125%, due March 13, 2000 7.55%, due April 22, 2000 7.50%, due May 5, 2000 7.43%, due September 9, 2000 5.43% due October 15, 2000 7.66%, due May 5, 2001 5.67%, due May 5, 2001 Total unsecured notes at December 31, 1999 Amount (In millions)
$ 15.0 35.0 139.0 30.0 5.0 135.0 152.0 $511.0 I B C D E G The interest paid on the debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest Expense" in the Consolidated Statements of Income and is deductible for income tax purposes.
BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, debentures, and the preferred security guarantee agreement.
The debentures are the only assets of the Trust. The Trust is wholly owned by BGE because it owns all the common securities of the Trust that have general voting power. For the payment of dividends and in the event of liquidation of BGE, the debentures are ranked prior to preference stock and common stock. Diversified Businesses Revolving Credit Agreements ComfortLink has a $50 million unsecured revolving credit agreement that matures September 26, 2001. Under the terms of the agreement, ComfortLink has the option to obtain loans at various rates for terms up to nine months. ComfortLink pays a facility fee on the total amount of the commitment.
At December 31, 1999, ComfortLink had $33 million outstanding under this agreement.
Mortgage and Construction Loans Our diversified businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments:
"* 7.90%, due in 2000
* 9.65%, due in 2028 "* 8.00%, due in 2001
* 8.00%, due in 2033 "* 4.25%, due in 2009 The 8.00% mortgage note due in 2003 requires interest payments until maturity.
The variable rate mortgage notes and construction loans require periodic payment of principal and interest.
Unsecured Notes The unsecured notes mature on the following schedule:
Maturities of Long-Tenn Debt ._. 1l of our long-term borrowings mature on the following schedule (includes sinking fund requirements):
Weighted Average Interest Rates for Variable Rate Debt Our weighted average interest rates for variable rate debt were: Year Ended December 31.1999 1998 Year 2000 2001 2002 2003 2004 Thereafter Total long-term debt at December 31, 1999 Diversified BGE Businesses (In millions)
$ 401.9 $284.4 282.2 366.6 154.0 1.5 286.8 10.4 154.0 6.0 1,428.6 17.9$2,707.5 $686.8 At December 31, 1999, BGE had long-term loans totaling $255.0 million that mature after 2002 (including
$110.0 million of medium-term notes discussed in this Note under "BGE's Other Long-Term Debt") that lenders could potentially require 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.
BGE Floating rate series mortgage bonds Remarketed floating rate series mortgage bonds Medium-term notes, Series D Medium-term notes, Series G Medium-term notes; Series H Pollution control loan Port facilities loan Adjustable rate pollution control loan Economic development loan Variable rate pollution control loan Diversified Businesses Loans under credit agreement Mortgage and construction loans 5.41% 5.90%5.19 5.29 5.38 5.64 3.22 3.24 3.59 3.26 3.30 5.70 5.74 3.48 3.61 3.75 3.59 3.45 5.68 6.02 6.65 8.17 Note 9. Leases There are two types of leases--operating and capital. Capital leases qualify as sales or purchases of property and are reported in the Consolidated Balance Sheets. Capital leases are not material in amount. All other leases are operating leases and are reported in the Consolidated Statements of Income. We present information about our operating leases below. Outgoing Lease Payments We, as lessee, lease some facilities and equipment used in our businesses.
The lease agreements expire on various dates and have various renewal options. We expense all lease payments associated with our regulated utility operations.
Lease expense was: * $12.2 million in 1999, * $10.5 million in 1998, and * $9.5 million in 1997. At December 31, 1999, we owed future minimum payments for long-term, noncancelable, operating leases as follows: Year (In millions) 2000 $ 8.2 2001 6.1 2002 4.5 2003 3.2 2004 2.4 Thereafter 9.7 Total future minimum lease payments $34.1 Constellation Energy Group Inc. and Subsidiaries I I (Note 10. Commitments, Guarantees, and Contingencies Commitments We have made substantial commitments in connection with our utility construction program for future years. In addition, our electric business has entered into two long-term contracts for the purchase of electric generating capacity and energy. The contracts expire in 2001 and 2013. We made payments under these contracts of: * $67.8 million in 1999, * $70.7 million in 1998, and * $65.6 million in 1997. At December 31, 1999, we estimate our future payments for capacity and energy that we are obligated to buy under these contracts to be: Year (In millions) 2000 $ 69.7 2001 37.1 2002 13.9 2003 13.8 2004 13.6 Thereafter 113.4 Total estimated future payments for capacity and energy under long-term contracts
$261.5 Portions of these contracts are expected to be uneconomic upon the deregulation of electric generation.
Therefore, we recorded a charge and accrued a corresponding liability 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 as discussed in Note 4 on page 59. At December 31, 1999, the accrued portion of these contracts was $47.5 million.Some of our diversified businesses have committed to contribute additional capital and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest.
At December 31, 1999, the total amount of investment requirements committed to by our diversified businesses was $174.2 million. This amount includes $121 million for our energy services businesses commitment to Orion Power Holdings, Inc. BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a desig nated pool of customer receivables.
Under the agreements, BGE can sell up to a total of $40 million, and BGE Home Products & Services can sell up to a total of $50 million.
Under the terms of the agreements, the buyer of the receiv ables has limited recourse against BGE and has no recourse against BGE Home Products & Services.
BGE and BGE Home Products & Services have recorded reserves for credit losses. At December 31, 1999, BGE had sold $28.2 million and BGE Home Products & Services had sold $43.3 million of receivables under these agreements.
Guarantees Constellation Energy has issued guarantees in an amount up to $69.2 million related to credit facilities and contractual performance of certain of its diversified subsidiaries.
However, the actual subsidiary liabilities related to these guarantees totaled $21.7 million at December 31, 1999. BGE guarantees two-thirds of certain debt of Safe Harbor Water Power Corporation.
The maximum amount of our guarantee is $23 million. At December 31, 1999, Safe Harbor 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.Constellation Energy Group Inc. and Subsidiaries r
'Environmental Matters 'lean Air The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxides and nitrogen oxides (NOx) from electric generating stations-Title IV and Title I. Title IV primarily addresses emissions of sulfur dioxides.
Compliance is required in two phases: "* Phase I became effective January 1, 1995. We met the requirements of this phase by installing flue gas desulfur ization systems, switching fuels, and retiring some units.  "* Phase II became effective January 1, 2000. We met the compliance requirements through a combination of switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) has issued regulations, effective October 18, 1999, which require up to 65% NOx emissions reductions by May 1, 2000. We have entered into a settlement agreement with the MDE since we cannot meet this deadline.
Under the terms of the settlement agreement, BGE will install emissions reduction equipment at two sites by May 2002. In the meantime, we are taking steps to control NOx emissions at our generating plants. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that requires up to 85% NOx emissions "eduction by 22 states including Maryland and Pennsylvania. 
,_-'WAhile the rule was appealed by several groups including utilities and states, Maryland will meet the requirements of the rule by 2003. Based on the MDE and EPA regulations, we currently estimate that the additional controls needed at our generating plants to meet the MDE's 65% NOx emission reduction requirements will cost approximately
$135 million. Through December 31, 1999, we have spent approximately
$51 million to meet the MDE's 65% reduction requirements.
We estimate the additional cost for EPA's 85% reduction requirements to be approximately
$35 million by 2003. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment.
In 1999, these new standards were successfully challenged in court. The EPA is expected to 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.
Waste Disposal The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.43% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America (a metal reclaimer in Philadelphia), could be as much as $4.9 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA. On July 12, 1999, the EPA notified us, along with nineteen other entities, that we may be a potentially responsible party at the 68th Street Dump/Industrial Enterprises Site, also known as the Robb Tyler Dump located in Baltimore, Maryland.
The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized.
Although our potential liability cannot be estimated, we do not expect such liability to be material based on our records showing that we did not send waste to the site. Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the MDE that requires us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland.
We submitted the required remedial action plans and they have been approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million in nominal dollars (including inflation).
We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. We discuss this further in Note 5 on page 61. Through December 31, 1999, we have spent approximately
$34 million for remediation at this site.Constellation Energy Group Inc. and Subsidiaries I I We are also required by accounting rules to disclose additional costs we consider to be less likely than probable costs, but still "reasonably possible" of being incurred at these sites. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately
$14 million in nominal dollars ($7 million in current dollars, plus the impact of inflation at 3.1% over a period of up to 36 years). We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results.
Nuclear Insurance If there were an accident or an extended outage at either unit of Calvert Cliffs, it could have a substantial adverse financial effect on us. The primary contingencies that would result from an incident at Calvert Cliffs could include: "* physical damage to the plant, "* recoverability of replacement power costs, and "* our liability to third parties for property damage and bodily injury. We have insurance policies that cover these contingencies, but the policies have certain industry standard exclusions.
Furthermore, the costs that could result from a covered major accident or a covered extended outage at either of the Calvert Cliffs units could exceed our insurance coverage limits. Insurance for Calvert Cliffs and Third Party Claims For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual insurance company. If an outage at either of the two units at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 12 weeks, we have insurance coverage for replace ment power costs up to $490.0 million per unit, provided by an industry mutual insurance company. This amount can be 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.In addition we, as well as others, could be charged for a portion of any third party claims associated with a nuclear incident at any commercial nuclear power plant in the country. At December 31, 1999, the limit for third party claims from a nuclear incident is $9.34 billion under the provisions of the Price Anderson Act. If third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $176.2 million per incident.
That amount would be payable at a rate of $20 million per year. Insurance for Worker Radiation Claims As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance to cover radiation injury claims of certain nuclear workers.
On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations.
Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe both the old and new policies below.  "* Nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy.  "° All nuclear worker claims reported prior to January 1, 1998 are still covered by the old insurance policies.
Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies for the next eight years. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be assessed, with our share being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the Price Anderson Act (discussed in this section) would apply.Constellation Energy Group Inc. and Subsidiaries r
Recoverability of Electric Fuel Costs .Jntil July 1, 2000, we will continue to recover our cost of "'electric fuel as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. To do this, the Maryland PSC will evaluate the performance of our gener ating plants, and will determine if we used all reasonable and cost-effective maintenance and operating control procedures.
The Maryland PSC, under the Generating Unit Performance Program, measures annually whether we have maintained the productive capacity of our generating plants at reasonable levels. To do this, the program uses a system-wide generating performance target and an individual performance target for each base load generating unit. In fuel rate hearings, actual generating performance adjusted for planned outages will be compared first to the system-wide target. If that target is met, it should mean that the requirements of Maryland law have been met. If the system-wide target is not met, each unit's adjusted actual generating performance will be compared to its individual performance target to determine if the requirements of Maryland law have been met and, if not, to determine the basis for possibly imposing a penalty on BGE. Even if we meet these targets, parties to fuel rate hearings may still question whether we used all reasonable and cost-effective procedures to try to prevent an outage.  'f the Maryland PSC decides we were deficient in some way, ,-the Maryland PSC may not allow us to recover the cost of replacement energy. The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of replacement energy associated with outages at these units can be significant.
We cannot estimate the amount of replacement energy costs that could be challenged 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.California Power Purchase Agreements Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $301.8 million invested in 14 projects that sell electricity in California under power purchase agree ments called "Interim Standard Offer No. 4" agreements.
Under these agreements, the projects supply electricity to utility companies at: "* a fixed rate for capacity and energy for the first 10 years of the agreements, and "* a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next-available source of generation to service the demands on its system. 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 four remaining projects that have not transitioned will do so by December 2000. The projects that have already transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. Once the remaining projects have transi tioned to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates. We discuss the earnings for these projects in the "Diversified Businesses" section of Management's Discussion and Analysis on page 32.Constellation Energy Group Inc. and Subsidiaries I I (Note 11. Fair Market VaLue of Financial Instruments The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current trans action between willing parties, other than in a forced sale or liquidation.
Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We used the following methods and assumptions in estimating fair value disclosures for financial instruments:
"* Cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrow ings, current portions of long-term debt and preference stock, and certain deferred credits and other liabilities:
The amounts reported in the Consolidated Balance Sheets approximate fair value.  "* Investments and other assets where it was practicable to estimate fair value: The fair value is based on quoted market prices where available. 
"* Fixed-rate long-term debt, and redeemable preference stock: The fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates. The carrying amount of variable-rate long-term debt approximates fair value. We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table, and we describe some of the items separately below: At December 31.Investments and other assets for which it is: Practicable to estimate fair value Not practicable to estimate fair value Fixed-rate long-term debt Redeemable preference stock 1999 1998 Carrying Fair Carrying Fair Amount Value Amount Value (In millions)It was not practicable to estimate the fair value of investments held by our diversified businesses in: "* several financial partnerships that invest in nonpublic debt and equity securities, and "* several partnerships that own solar powered energy production facilities.
This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets. The investments in financial partnerships totaled $35.8 million at December 31, 1999 and $41.9 million at December 31, 1998, representing ownership interests up to 10%. The total assets of all of these partnerships totaled $5.9 billion at December 31, 1998 (which is the latest information available).
The investments in solar powered energy production facility partnerships totaled $10.9 million at December 31, 1999 and 1998, representing ownership interests up to 13%. The total assets of all of these partnerships totaled $31.3 million at December 31, 1998 (which is the latest information available)
Guarantees It was not practicable to determine the fair value of certain loan guarantees of Constellation Energy and its subsidiaries.
Constellation Energy guaranteed outstanding debt of $16.5 million at December 31, 1999. BGE guaranteed outstanding debt of $13.6 million at December 31, 1999 and $18.0 million at December 31, 1998. Our diversified businesses guaranteed outstanding debt totaling $48.8 million at December 31, 1999 and $59.7 million at December 31, 1998. We do not anticipate that we will need to fund these guarantees.
$ 313.3 $ 313.3 $ 213.0 $ 213.0 46.7 N/A 56.5 N/A 2,728.9 2,637.3 2,954.7 3,076.6 --7.0 7.2 Constellation Energy Group Inc. and Subsidiaries F
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 Earnings Earnings Income Applicable Per Share From to Common of Common Revenues Operations Stock Stock (In millions, except per-share amounts) Quarter Ended March 31 $ 932.3 $198.1 $ 82.8 $0.55 June 30 820.0 163.9 68.0 0.45 September 30 970.4 277.7 136.1 0.91 December 31 1,063.5 120.2 (26.8) (0.18) Year Ended December 31 $3,786.2 $759.9 $260.1 $1.74 Our second quarter results include a $3.6 million after-tax write-down of a financial investment (see Note 3). Our third quarter results include: -$7.5 million associated with Hurricane Floyd (see the "Electric Operations and Maintenance Expenses" section of Management's Discussion and Analysis), .a $37.5 million deferral of revenues collected associated "with the deregulation of our electric generation business (see Note 5), 1998 Quarterly Data Earnings Earnings Income Applicable Per Share From to Common of Common Revenues Operations Stock Stock (In millions, except per-share amounts) Quarter Ended March 31 $ 866.1 $183.4 $ 74.4 $0.50 June 30 767.6 156.2 57.4 0.39 September 30 934.0 320.4 160.9 1.08 December 31 790.4 81.1 13.2 0.09 Year Ended December 31 $3,358.1 $741.1 $305.9 $2.06 Our third quarter results include a $10.4 million after-tax gain for earnings in a partnership (see Note 3). Our fourth quarter results include: "* a $15.4 million after-tax write-off of a real estate investment (see Note 3), and "* a $5.5 million after-tax write-off of an energy services investment (see the "Other Energy Services" section 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 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)
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*
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
-/ 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 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 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*
Policy The common stock is entitled to dividends when and as declared by the Board of Directors.
There are no limitations in any indenture or other agreements on payment of dividends.
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.
Common Stock Dividend Dates Record dates are normally on the 10th of March, June, September, and December.
Quarterly dividends are customarily mailed to each shareholder on or about the 1 st of April, July, October, and January.
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.
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.
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
* 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.
Stock Transfer Agents and Registrars Transfer Agent and Registrar:
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:
Constellation Energy Group, Inc. Shareholder Services, Room 820 39 W. Lexington Street Baltimore, MD 21201 Constellation Energy Group Inc. and Subsidiaries I
 
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 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 Constellation Energy 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
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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)
Revenues Nonregulated revenues Regulated electric revenues Regulated gas revenues Total revenues Expenses Operating expenses Depreciation and amortization Taxes other than income taxes Total expenses Income From Operations Other Income Income Before Fixed Charges and Income Taxes Fixed Charges Interest expense (net) BGE preference stock dividends Total fixed charges 'ncome Before Income Taxes '4ncome Taxes Current Deferred Investment tax credit adjustments Total income taxes Net Income Earnings Applicable to Common Stock Average Shares of Common Stock Outstanding Earnings per Common Share and Earnings Per Common Share Assuming Dilution Dividends Declared Per Common Share Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions, Except Per-Share Amounts)$ 296.7 598.2 86.7 981.6 512.2 107.6 46.4 666.2 315.4 0.9 316.3 66.6 3.3 69.9 246.4 108.3 (7.3) (2.1) 98.9 $ 147.5 $ 147.5 150.1$0.98 $0.42$ 258.9 691.2 60.1 1,010.2 574.5 92.9 65.1 732.5 277.7 1.2 278.9 61.7 3.4 65.1 213.8 76.7 3.2 (2.2) 77.7 $ 136.1 $ 136.1 149.6$ 781.4 1,688.0 372.8 2,842.2 1,680.8 370.7 158.8 2,210.3 631.9 7.0 638.9 192.0 9.9 201.9 437.0 215.1 (31.0) (6.3) 177.8 $ 259.2 $ 259.2 149.8$0.91 $0.42$ 782.2 1,737.2 332.7 2,852.1 1,761.3 274.0 177.2 2,212.5 639.6 5.7 645.3 181.1 10.2 191.3 454.0 152.6 20.9 (6.4) 167.1 $ 286.9 $ 286.9 149.6$1.73 $1.26$1.92 $1.26 Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended September 30, 2000 1999$ 147.5 17.7 $ 165.2$ 136.1 5.0 $ 141.1 Nine Months Ended September 30, 2000 (In Millions)
$ 259.2 41.8 $ 301.0 1999 $ 286.9 (6.5) $ 280.4 ,;,.ee Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to conform with the current period's presentation.
3 Net Income Other comprehensive income (loss), net of taxes Comprehensive Income 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 Accounts receivable (net of allowance for uncollectibles of $25.5 and $36.6 respectively)
Trading securities Assets from energy trading activities Fuel stocks Materials and supplies Prepaid taxes other than income taxes Other Total current assets Investments and Other Assets Real estate projects and investments Investments in power projects Financial investments Nuclear decommissioning trust fund Net pension asset Investment in Orion Power Holdings, Inc. Other Total investments and other assets Property, Plant and Equipment Regulated property, plant and equipment:
Plant in service Construction work in progress Plant held for future use Total regulated property, plant and equipment Nonregulated generation property, plant and equipment Other nonregulated property, plant and equipment Nuclear fuel (net of amortization)
Accumulated depreciation Net property, plant and equipment Deferred Charges Regulatory assets (net) Other Total deferred charges$ 50.4 842.1 180.2 1,573.7 101.9 155.6 140.2 36.4 3,080.5 296.4 538.8 192.2 235.0 97.2 232.1 120.4 1,712.1 4,746.0 68.8 9.7 4,824.5 4,906.5 165.1 137.4 (3,745.6) 6,287.9 514.2 61.3 575.5 Total Assets $ 11,656.0
* Unaudited See Notes to Consolidated Financial Statements.
Certain prior period amiounts have been reclassified to confbrin with the current period's presentation.
$ 92.7 578.5 136.5 312.1 94.9 149.1 72.4 54.0 1,490.2 310.1 547.3 145.4 217.9 99.5 105.7 154.3 1,580.2 8,620.1 222.3 13.0 8,855.4 341.3 152.7 133.8 (3,559.1) 5,924.1 637.4 51.9 689.3 $ 9,683.8 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 Current portion of long-term debt Accounts payable Liabilities from energy trading activities Dividends declared Accrued taxes Other Total current liabilities Deferred Credits and Other Liabilities Deferred income taxes Postretirement and postemployment benefits Deferred investment tax credits Other Total deferred credits and other liabilities Long-term Debt First refunding mortgage bonds of BGE Other long-term debt of BGE Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 Long-term debt of nonregulated businesses Unamortized discount and premium Current portion of long-term debt Total long-term debt BGE Preference Stock Not Subject to Mandatory Redemption Common Shareholders' Equity Common stock Retained earnings Accumulated other comprehensive income (loss) Total common shareholders' equity Total capitalization Total Liabilities and Capitalization
$ 505.0 660.9 693.7 1,260.6 66.2 90.8 206.8 3,484.0 1,273.9 261.7 103.4 355.7 1,994.7 1,174.7 603.6 250.0 1,477.2 (9.3) (660.9) 2,835.3 190.0 1,540.9 1,569.4 41.7 3,152.0 6,177.3 $ 11,656.0$ 371.5 808.3 365.1 163.8 66.1 19.2 209.4 2,003.4 1,288.8 269.8 109.6 253.8 1,922.0 1,321.7 1,135.8 250.0 686.8 (10.6) (808.3) 2,575.4 190.0 1,494.0 1,499.1 (0.1) 2,993.0 5,758.4 $ 9,683.8* Unaudited See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to con fbrin with the current period's presentation.
5 CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES PART I -FINANCIAL INFORMATION (CONTINUED)
Item 1 -Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Cash Flows From Operating Activities Net income Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization Deferred income taxes Investment tax credit adjustments Deferred fuel costs Accrued pension and postemployment benefits Gain on sale of subsidiaries Write-down of real estate investment Write-down of financial investment Write-off of power project Equity in earnings of affiliates and joint ventures (net) Changes in assets from energy trading activities Changes in liabilities from energy trading activities Changes in other current assets Changes in other current liabilities Other Net cash provided by operating activities Cash Flows From Investing Activities Purchases of property, plant and equipment and other capital expenditures Contributions to nuclear decommissioning trust fund Purchases of marketable equity securities Sales of marketable equity securities Other financial investments Real estate projects and investments Power projects investments Investment in Orion Power Holdings, Inc. Other Net cash used in investing activities Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings Long-term debt Common stock Repayments of short-term borrowings Reacquisitions of long-term debt Redemption of preference stock Common stock dividends paid Other Net cash provided by (used in) financing activities Net Decrease in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Other Cash Flow Information:
Interest paid (net of amounts capitalized)
Income taxes paid See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassifled to conjorm with the current period's presentation.
6 Nine Months Ended September 30, 2000 1999 (In Millions)$ 259.2 411.1 (31.0) (6.3) 11.0 18.1 (13.3) (6.3) (1,261.6) 1,096.8 (243.3) 270.1 84.3 588.8 (626.9) (13.5) (36.3) 39.6 10.4 9.3 (14.9) (101.5) 5.4 (728.4) 7,883.8 803.0 35.9 (7,750.3)
(691.8) (188.5) 5.2 97.3 (42.3) 92.7 $ 50.4$ $205.0 136.1 S 286.9 316.2 20.9 (6.4) (51.2) 35.5 5.2 33.8 10.2 22.4 (74.1) (12.3) (355.5) 234.8 17.1 483.5 (351.9) (13.2) (17.2) 12.5 15.1 46.2 (11.0) (97.7) (24.6) (441.8) 2,412.2 289.7 9.5 (2,269.1)
(399.6) (7.0) (188.3) (6.4) (159.0) (117.3) 173.7 S 56.4 S $174.9 102.2 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I -FINANCIAL INFORMATION Item I -Financial Statements Consolidated Statements of Income (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions)Revenues Electric Revenues Gas Revenues Nonregulated Revenues Total revenues Operating Expenses Electric fuel and purchased energy Gas purchased for resale Operations and maintenance Nonregulated
-selling, general, and administrative Depreciation and amortization Taxes other than income taxes Total operating expenses Income From Operations Other Income Allowance for equity funds used during constructiot Equity in earnings of Safe Harbor Water Power Corporation Net other income (expense)
Total other income Income Before Fixed Charges and Income Taxes Fixed Charges Interest expense (net) Capitalized interest Allowance for borrowed funds used during construction Total fixed charges Income Before Income Taxes Income Taxes Current Deferred Investment tax credit adjustments Total income taxes Net Income Preference Stock Dividends Earnings Applicable to Common Stock$ 598.4 90.1 1.5 690.0 388.3 48.2 88.0 1.0 63.8 35.7 625.0 65.0 0.6 3.7 4.3 69.3 45.3 (0.3) 45.0 24.3 17.9 (6.3) (0.6) 11.0 13.3 3.3 $ 10.0$ 691.4 62.9 1.7 756.0 130.0 21.3 167.1 1.1 89.0 64.2 472.7 283.3 1.5 1.2 (0.5) 2.2 285.5 48.1 (0.8) 47.3 238.2 80.5 4.9 (2.1) 83.3 154.9 3.4 $ 151.5$1,688.4 377.8 3.9 2,070.1 632.4 192.0 457.5 2.8 313.6 146.2 1,744.5 325.6 2.1 2.4 5.4 9.9 335.5 142.2 (2.9) 139.3 196.2 119.8 (38.8) (4.7) 76.3 119.9 9.9 $ 110.0$ 1,737.5 337.3 346.7 2,421.5 375.3 156.4 539.2 285.3 267.5 175.6 1,799.3 622.2 5.2 3.8 (3.6) 5.4 627.6 162.3 (0.4) (2.8) 159.1 468.5 169.1 3.5 (6.4) 166.2 302.3 10.2 $ 292.1 Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, 2000 1999 2000 1999 (In Millions)$ 13.3 Net Income Other comprehensive loss, net of taxes -. Comprehensive Income$ 154.9$ 13.3 $ 154.9$ 119.9 $ 302.3 -(3.4) $ 119.9 $ 298.9 See Notes to Consolidated Financial Statements.
Certain prior period amounts have been reclassified to 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 Assets Current Assets Cash and cash equivalents Accounts receivable (net of allowance for uncollectibles of $13.9 and $13.0 respectively)
Notes receivable, affilated company Fuel stocks Materials and supplies Prepaid taxes other than income taxes Other Total current assets Investments and Other Assets Nuclear decommissioning trust fund Net pension asset Safe Harbor Water Power Corporation Other Total investments and other assets Utility Plant Plant in service Electric Gas Common Total plant in service Accumulated depreciation Net plant in service Construction work in progress Nuclear fuel (net of amortization)
Plant held for future use Net utility plant Deferred Charges Regulatory assets (net) Other Total deferred charges Total Assets September 30, 2000* 16.9 389.2 87.0 56.9 38.8 108.5 8.0 705.3 103.8 63.0 166.8 3,234.3 983.1 528.6 4,746.0 (1,674.9) 3,071.1 68.8 9.7 3,149.6 514.2 39.1 553.3 $ 4,575.0 December 3 1, 1999 (In Millions)
$ 23.5 316.1 94.9 139.1 72.4 9.0 655.0 217.9 99.8 34.5 61.6 413.8 7,088.6 962.0 569.5 8,620.1 (3,466.1) 5,154.0 222.3 133.8 13.0 5,523.1 637.4 43.3 680.7 $ 7,272.6* Unaudited See Notes to Consolidated Financial Statements.
8 BALTIMORE GAS AND ELECTRIC COMPANY PART I -FINANCIAL INFORMATION (CONTINUED)
Item 1 -Financial Statements Consolidated Balance Sheets AND SUBSIDIARIES Liabilities and Capitalization Current Liabilities Short-term borrowings Current portion of long-term debt Accounts payable Customer deposits 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 Long-term Debt First refunding mortgage bonds of BGE Other long-term debt of BGE Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% debentures of BGE due June 30, 2038 Long-term debt of nonregulated businesses Unamortized discount and premium Current portion of long-term debt Total long-term debt Preference Stock Not Subject to Mandatory Redemption Common Shareholder's Equity Common stock Retained earnings Total common shareholder's equity Total capitalization Total Liabilities and Capitalization September 30, 2000* $ 258.0 309.7 336.7 43.7 3.3 11.4 36.4 22.7 20.1 1,042.0 507.0 250.6 25.6 27.2 24.7 835.1 1,174.7 603.6 250.0 33.0 (7.1) (309.7) 1,744.5 190.0 454.2 309.2 763.4 2,697.9 $ 4,575.0 December 31, 1999 (In Millions)
$ 129.0 523.9 222.8 40.6 3.3 9.2 48.2 35.7 65.8 1,078.5 1,032.0 231.0 109.6 27.2 42.9 1,442.7 1,321.7 1,135.8 250.0 33.0 (10.6) (523.9) 2,206.0 190.0 1,494.0 861.4 2,355.4 4,751.4 $ 7,272.6* Unaudited See Notes to Consolidated Financial Statements.
9 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES PART I -FINANCIAL INFORMATION (CONTINUED)
Item I -Financial Statements Consolidated Statements of Cash Flows (Unaudited)
Cash Flows From Operating Activities Net income Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization Deferred income taxes Investment tax credit adjustments Deferred fuel costs Accrued pension and postemployment benefits Allowance for equity funds used during construction Equity in earnings of affiliates and joint ventures (net) Changes in assets from energy trading activities Changes in liabilities from energy trading activities Changes in other current assets Changes in other current liabilities Other Net cash provided by operating activities Nine Months Ended September 30, 2000 1999 (In Millions)$ 119.9 338.2 (38.8) (4.7) 11.0 14.9 (2.1) 1.2 (127.0) 158.1 5.2 475.9 Cash Flows From Investing Activities Utility construction expenditures (including AFC) Allowance for equity funds used during construction Nuclear fuel expenditures Deferred energy conservation expenditures Contributions to nuclear decommissioning trust fund Purchases of marketable equity securities Sales of marketable equity securities Other financial investments Real estate projects and investments Power projects investments Other Net cash used in investing activities (241.0) 2.1 (39.5) (0.5) (8.8)(5.5) (293.2)Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings Long-term debt Common stock Repayments of short-term borrowings Reacquisition of long-term debt Redemption of preference stock Preference stock dividends paid Distributions to Constellation Energy Other Net cash used in financing activities 3,655.0 (3,526.0)
(121.7)(9.9) (188.5) 1.8 (189.3) (6.6) 23.5 $ 16.9 Net Decrease in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Other Cash Flow Information:
Interest paid (net of amounts capitalized)
Income taxes paid$ $147.0 111.5$ 302.3 307.6 3.6 (6.4) (51.2) 35.0 (5.2) 29.0 (120.1) 76.3 (73.2) 41.9 32.5 572.1 (246.1) 5.2 (45.0) (0.9) (13.2) (9.2) 6.0 6.7 22.0 (17.9) (16.7) (309.1) 1,608.3 257.2 9.5 (1,585.8)
(375.3) (7.0) (10.3) (316.5) (1.3) (421.2) (158.2) 173.7 $ 15.5$ $155.0 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 Consolidated Fieiancial Statements.
10 Notes to Consolidated Financial Statements Weather conditions can have a great impact on our results for interim periods. This means that results for interim periods do not necessarily represent results to be expected for the year. Our interim financial statements on the previous pages reflect all adjustments that Management believes are necessary for the fair presentation of the financial position and results of operations for the interim periods presented.
These adjustments are of a normal recurring nature. Holding Company Formation On April 30, 1999, Constellation Energy Group, Inc.  (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE) and Constellation Enterprises, Inc. Constellation Enterprises was previously owned by BGE. 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. Basis of Presentation This Quarterly Report on Form I0-Q is a combined report of Constellation Energy and BGE. The consolidated financial statements of Constellation Energy include the accounts of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its subsidiaries.
The consolidated financial statements of BGE include the accounts of BGE, District Chilled Water General Partnership (ComfortLink), and BGE Capital Trust I. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively.
Reference in this report to the "utility business" is to BGE. Deregulation of Electric Generation On April 8, 1999, Maryland enacted legislation authorizing customer choice and competition among electric suppliers.
In addition, on November 10, 1999, the Maryland Public Service Commission (Maryland PSC) issued a Restructuring Order that resolved the major issues surrounding electric restructuring.
Effective July 1, 2000, the state of Maryland implemented customer choice for electric suppliers.
We discuss the implications of customer choice and the Restructuring Order further in Management's Discussion and Analysis beginning on page 18. Please also refer to the Legal Proceedings section on page 36 for a discussion regarding appeals of the Restructuring Order. Subsequent Event On October 23, 2000, we announced three initiatives to advance our growth strategies.
The first initiative is that we entered into an agreement (the "Agreement")
with an affiliate of The Goldman Sachs Group, Inc. ("Goldman Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a 17.5% equity interest in our domestic merchant energy business, which will be consolidated under a single holding company ("Holdco").
Goldman Sachs will also acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to certain adjustments).
The warrant is exercisable six months after Holdco's common stock becomes publicly available.
The amount of common stock which Goldman Sachs may receive upon exercise will be equal to the excess of the market price of Holdco's common stock at the time of exercise over the exercise price of $60 per share for all the stock subject to the warrant, divided by the market price. Holdco may at its option pay Goldman Sachs such excess in cash. Goldman Sachs is acquiring its interest and the warrant in exchange for $250 million in cash (subject to adjustment in certain instances) and certain assets related to our power marketing business.
At closing, Goldman Sachs' existing services agreement with our power marketing business will terminate.
The second initiative is a plan to separate our domestic merchant energy business from our retail services business.
The separation will create two stand-alone, publicly traded energy companies.
One will be a merchant energy business engaged in wholesale power marketing and generation under the name "Constellation Energy Group" after the separation.
The other will be a regional retail energy and energy services company, BGE Corp., that will include BGE and other subsidiaries.
The third initiative is a change in our common stock dividend policy effective April 2001. We will maintain our current common stock dividend through January 2001. In a move closely aligned with our separation plan, effective April 2001, our annual dividend is expected to be set at $.48 per share. After the business separation, BGE Corp. expects to pay initial annual dividends of $.48 per share. Constellation Energy Group, as a growing 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 the separation are subject to customary closing conditions, including regulatory approvals and the receipt of a Private Letter Ruling from the Internal Revenue Service regarding certain tax matters. Both are expected to be completed by mid to late 2001. 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 -Electric, Gas, and Energy Services.
In response to the deregulation of electric generation, we realigned our organization and combined our wholesale power marketing business with our domestic plant development and operations to form a domestic merchant energy business.
In the first quarter of 2000, we revised our operating segments to reflect the realignments of our organization.
Our new reportable operating segments are -Domestic Merchant Energy, Regulated Electric, and Regulated Gas: " Our nonregulated domestic merchant energy business:
-provides power marketing and risk management services, -develops, owns, and operates domestic power projects, and -provides nuclear consulting services. 
"* Our regulated electric business purchases and distributes electricity, and "* Our regulated gas business purchases, transports, and sells natural gas.Domestic Merchant Energy Business For the three months ended September 30, 2000 Unaffiliated revenues $127.9 intersegment revenues 367.7 Total revenues 495.6 Net income (loss) 130.9 Regulated Electric Business We have restated certain prior period information for comparative purposes based on our new reportable operating segments.
Effective July 1, 2000, the financial results of the electric generation portion of our business are included in the domestic merchant energy business segment. Prior to that date, the financial results of electric generation are included in our regulated electric business.
Our remaining nonregulated businesses:
", develop, own, and operate international power projects in Latin America, "* provide energy products and services, "* sell and service electric and gas appliances, and heating and air conditioning systems, engage in home improvements, and sell electricity and natural gas through mass marketing efforts, "* provide cooling services, "* engage in financial investments, and "* develop, own and manage real estate and senior living facilities.
Regulated Gas Business Other Nonregulated Businesses Unallocated Corporate Items and Eliminations Consolidated (in millions)$ 598.2 0.1 598.3 15.4$ 86.7 3.4 90.1 (4.6)$ 168.8 19.0 187.8 5.8$(0 (390.2) (390.2)$ 981.6 981.6 147.5 1999 Unaffiliated revenues Intersegment revenues Total revenues Net income (loss) (a)$66.3 66.3 12.2 S 691.2 0.2 691.4 152.3$ 60.1 2.8 62.9 (0.7)$192.6 14.5 207.1 (27.7)S 1 (17.5) (17.5)$1,010.2 1,010.2 136.1 12 Domestic Merchant Energy Business For the nine months ended September 30, 2000 Unaffiliated revenues Intersegment revenues Total revenues Net income (loss) (b) 1999 Unaffiliated revenues Intersegment revenues Total revenues Net income (loss) (a) At September 30, 2000 Segment assets At December 31, 1999 Segment assets$ 261.3 367.6 628.9 150.2 $173.3 0.4 173.7 43.6 $6,098.8 $1,206.1$1,688.0 0.4 1,688.4 93.2 $1,737.2 0.7 1,737.9 253.4$372.8 5.0 377.8 18.1 $ 332.7 7.4 340.1 21.5$520.1 37.3 557.4 (2.3)$608.9 26.2 635.1 (31.6)$ (410.3) (410.3)-$2,852.1 (34.7) (34.7) 2,852.1 286.9$3,427.0 $1,104.8 $1,298.8 $ (273.4) $11,656.0$6,312.6$915.3 $1,231.3$18.5 $9,683.8 (a) Our electric business recorded expense of $4.9 million for the three months and nine months ended September 30, 1999 related to Hurricane Floyd Our power projects business recorded $6.7 million for the three months and nine months ended September 30, 1999for the write-off ofa geothermal power plant. Ourfinancial investments business recorded expense of $17. 3 million for the three months and $20.9 million for the nine months ended September 30, 1999for the write-down of its investment in Capital Re stock. Our real estate and senior-living facilities business recorded expense of $3.4 million for the three months and nine months ended September 30, 1999for a write-down of certain senior-living facilities.  (b) Our electric business recorded expense of $4.2 million for the nine months ended September 30, 2000 related to employees that elected to participate in a Targeted Voluntary Special Early Retirement Program. In addition, our domestic merchant energy business recorded a $15. 0 million deregulation transition cost incurred by our power marketing business.
We discuss these fiurther in the Overview section of Management's Discussion andAnalysis.
Financing Activity Constellation Energy As discussed on page 11, effective April 30, 1999, BGE's outstanding common stock automatically became shares of common stock of Constellation Energy. During the period from January 1,2000 through the date of this report, we issued a total of 975,300 shares of common stock, without par value, under our Continuous Offering Program for Stock. Net proceeds were about $35.9 million.
Constellation Energy issued the following long-term notes during the period from January 1, 2000 through the date of this report: Date Net Principal Issued Proceeds (in millions)7 7/8% Notes due 2005 Floating Rate Notes due 2003 Extendible Notes due 2010 Floating Rate Reset Notes due 2002$300 200 300 4/00 $297.5 4/00 199.3 6/00 299.6 In June 2000, Constellation Energy arranged two revolving credit agreements totaling $565.0 million to support our commercial paper program and for other working capital purposes.
Of this amount, $376.5 million is for short-term financial needs and $188.5 million, which expires in three years, is for short and long-term financial needs, including letters of credit. As of the date 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 facilities.
Constellation Energy has issued guarantees in an amount up to $617.3 million related to credit facilities and contractual performance of certain of its nonregulated subsidiaries.
However, the actual subsidiary liabilities related to these guarantees totaled $343.3 million at September 30, 2000.200 10/00 199.6 13 Regulated Electric Business Regulated Gas Business Other Nonregulated Businesses Unallocated Corporate Items and Eliminations (in millions)Consolidated
$ 2,842.2 2,842.2 259.2 I In connection with the initiative to separate our domestic merchant energy business from our retail services business, Constellation Energy expects to redeem all of its currently outstanding
$1.0 billion debt at or prior to the separation.
The redemption will occur through a combination of open market purchases, tender offers, and redemption calls. BGE and Nonregulated Businesses In October 2000, BGE issued $200.0 million of Floating Rate Reset Notes due in 2001 with net proceeds of $199.8 million.
In June 2000, BGE arranged a $25.0 million long-term revolving credit agreement to support its commercial paper program and for other working capital purposes.
In conjunction with the July 1, 2000 transfer of generation assets, BGE is contingently liable for $278.0 million of the tax exempt debt assigned to nonregulated affiliates of Constellation Energy as discussed further in the Current Issues -Electric Competition section of Management's Discussion and Analysis on page 20. In the future, BGE may purchase some of its long-term debt or preference stock in the market. This will depend on market conditions and BGE's capital structure, including the mix of secured and unsecured debt. Please refer to the Fundingfor Capital Requirements section of Management's Discussion and Analysis on page 34 for additional information about the debt of BGE and our nonregulated businesses.
Stock Option Program In May 2000, our Board of Directors approved the issuance of non-qualified stock options to officers and key employees as permitted under existing incentive plans. Under the plans, the options are granted at prices not less than the market value of the stock at the date of grant, generally become exercisable ratably over a three year period beginning one year from the date of grant, and expire ten years from the date of grant. During the second quarter, we granted 2,313,000 stock options at an exercise price of $34.25. As permitted by SFAS No. 123, Accounting for Stock Based Compensation, we measure our stock-based compensation in accordance with Accounting Principles Board Opinion No. 25, Accounting for 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.Commitments Some of our nonregulated businesses have committed to contribute additional capital and to make additional loans to some affiliates, joint ventures, and partnerships in which they have an interest.
At the date of this report, the total amount of investment requirements committed to by our nonregulated businesses was $218.0 million.
Environmental Matters Clean Air The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating stations -Title IV and Title I. Title IV addresses emissions of sulfur dioxide.
Compliance is required in two phases: " Phase I became effective January 1, 1995. We met the requirements of this phase by installing flue gas desulfurization systems, switching fuels, and retiring some units.  " Phase 11 became effective January 1, 2000. We met the compliance requirements through a combination of switching fuels and allowance trading.
We will meet the ongoing compliance requirements through a combination of switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) issued regulations, effective October 18, 1999, which required up to 65% NOx emissions reductions by May 1, 2000. We entered into a settlement agreement with the MDE since we could not meet this deadline.
Under the terms of the settlement agreement, BGE will install emissions reduction equipment at two sites by May 2002. In the meantime, we are taking steps to control NOx emissions at our generating plants. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that required up to 85% NOx emissions reduction by 22 states including Maryland and Pennsylvania.
Maryland expects to meet the requirements of the rule by 2003. The emissions reduction equipment installations discussed above will allow us to meet these requirements.
14 We currently estimate that the controls needed at our generating plants to meet the MDE's 65% NOx emission reduction requirements will cost approximately
$135 million. Through the date of this report, we have spent approximately
$82.6 million to meet the 65% reduction requirements.
We estimate the additional cost for the EPA's 85% reduction requirements to be approximately
$35 million by the end of 2002. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment.
In 1999, these new standards were successfully challenged in court. The EPA appealed the 1999 court rulings to the Supreme Court. In May 2000, the Supreme Court decided to hear the EPA's appeal. While these standards may require increased controls at our fossil generating plants in the future, implementation, if required, would 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 EPA standards.
On August 3, 2000, we received letters from the EPA requesting us to provide certain information under Section 114 of the federal Clean Air Act regarding some of our electric generating plants. This information is to determine compliance with the Clean Air Act and state implementation plan requirements, including potential application of federal New Source Performance Standards.
In general, such standards can require the installation of additional air pollution control equipment upon the major modification of an existing plant. We believe our generating plants have been operated in accordance with the Clean Air Act and the rules implementing the Clean Air Act. However, we cannot estimate the impact of this inquiry on our generating plants, and our financial results, at this time. Waste Disposal The EPA and several state agencies have notified us that we are considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by others. We cannot estimate the cleanup costs for all of these sites. We can, however, estimate that our current 15.43% share of the reasonably possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could be as much as $4.9 million higher than amounts we have recorded as a liability on our Consolidated Balance Sheets. This estimate is based on a Record of Decision issued by the EPA.On July 12, 1999, the EPA notified us, along with nineteen other entities, that we may be a potentially responsible party at the 6 8" Street Dump/Industrial Enterprises Site, also known as the Robb Tyler Dump located in Baltimore, Maryland.
The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized.
Although our potential liability cannot be estimated, we do not expect such liability to be material based on our records showing that we did not send waste to the site. Also, we are coordinating investigation of several sites where gas was manufactured in the past. The investigation of these sites includes reviewing possible actions to remove coal tar. In late December 1996, we signed a consent order with the MDE that requires us to implement remedial action plans for contamination at and around the Spring Gardens site, located in Baltimore, Maryland.
We submitted the required remedial action plans and they were approved by the MDE. Based on the remedial action plans, the costs we consider to be probable to remedy the contamination are estimated to total $47 million. We have recorded these costs as a liability on our Consolidated Balance Sheets and have deferred these costs, net of accumulated amortization and amounts we recovered from insurance companies, as a regulatory asset. Because of the results of studies at these sites, it is reasonably possible that these additional costs could exceed the amount we recognized by approximately
$14 million. We discuss this further in Note 5 of our 1999 Annual Report on Form 10-K. Through the date of this report, we have spent approximately
$35 million for remediation at this site. We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results.
Our potential environmental liabilities and pending environmental actions are described further in our 1999 Annual Report on Form I 0-K in Item 1. Business Environmental Matters.
Nuclear Insurance If there were an accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse financial effect on us. The primary contingencies that would result from an incident at Calvert Cliffs could include: "* physical damage to the plant, "* recoverability of replacement power costs, and "* our liability to third parties for property damage and bodily injury.15 We have insurance policies that cover these contingencies, but the policies have certain industry standard exclusions.
Furthermore, the costs that could result from a covered major accident or a covered extended outage at either of the Calvert Cliffs units could exceed our insurance coverage limits. Insurance for Calvert Cliffs and Third Party Claims For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual insurance company. If an outage at either of the two units at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 12 weeks, we have insurance coverage for replacement power costs up to $490.0 million per unit, provided by an industry mutual insurance company. This amount can be 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 $15.4 million.
In addition we, as well as others, could be charged for a portion of any third party claims associated with a nuclear incident at any commercial nuclear power plant in the country. At the date of this report, the limit for third party claims from a nuclear incident is $9.54 billion under the provisions of the Price Anderson Act. If third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $176.2 million per incident.
That amount would be payable at a rate of $20 million per year. Insurance for Worker Radiation Claims As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance to cover radiation injury claims of certain nuclear workers. On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations.
Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe both the old and new policies below. Nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy.All nuclear worker claims reported prior to January 1, 1998 are still covered by the old insurance policies.
Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies for the next eight years. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be assessed, with our share being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the Price Anderson Act (discussed in this section) would apply. Recoverability of Electric Fuel Costs Under the terms of the Restructuring Order, BGE's electric fuel rate clause was discontinued effective July 1, 2000. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred (included as an asset or liability on the Consolidated Balance Sheets and excluded from the Consolidated Statements of Income) under the electric fuel rate clause through June 30, 2000. We will collect this accumulated difference from customers over a twelve-month period beginning October 2000. California Power Purchase Agreements Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $297.6 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements.
Under these agreements, the projects supply electricity to utility companies at: " a fixed rate for capacity and energy for the first 10 years of the agreements, and " a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next available source of generation to service the demands on its system. 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 rates have had lower revenues under variable rates than they did under fixed rates. Once the remaining projects have transitioned to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates. We discuss these projects on page 26 of Management's Discussion and Analysis.
Other Nonregulated Businesses In September 2000, our real estate and senior-living facilities business converted 984,307 preferred shares of Corporate Office Properties Trust (COPT) into approximately 1.8 million common shares of COPT. We discuss the prior COPT transactions in Note 3 of our 1999 Annual Report on Form 10-K. We discuss our other nonregulated businesses' activities further in the Other Nonregulated Businesses section of Management's Discussion and Analysis on page 31. Related Party Transactions
-BGE Income Statement Under the Restructuring Order, BGE is providing standard offer service to customers at fixed rates over various time periods during the transition period, July 1, 2000 to June 30, 2006, for those customers that do not choose an alternate supplier.
Constellation Power Source is under contract to provide BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. The cost of BGE's purchased energy from 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.In addition, BGE receives charges from Constellation Energy for certain corporate functions.
Certain costs are directly assigned to BGE. We allocate other corporate function costs based on a total percentage of expected use by BGE. Management believes this method of allocation is reasonable and approximates the cost BGE would have incurred as an unaffiliated entity. These costs were $9.6 million for the quarter and $16.9 million for the nine months ending September 30, 2000. These costs were not material in 1999 due to the transfer of certain BGE employees to the holding company during that year. Balance Sheet As a result of the deregulation of electric generation, BGE transferred its generation assets to nonregulated affiliates of Constellation Energy effective July 1, 2000. In conjunction with this transfer, Constellation Power Source Generation, Inc. issued approximately
$366 million in unsecured promissory notes to BGE. Repayments of the notes by Constellation Power Source Generation, Inc. will be used exclusively to service current maturities of certain BGE long-term debt. As of September 30, 2000, $87 million of these notes are still outstanding and will mature on March 14, 2001. Amounts related to the corporate functions performed at the Constellation Energy holding company and to BGE's purchases to meet its standard offer service obligation resulted in intercompany accounts payable to Constellation Energy and affiliates of $197.2 million at September 30, 2000. These amounts were not material in 1999.17 Item 2. Management's Discussion Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction On April 30, 1999, Constellation Energy@ Group, Inc.  (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE) and Constellation Enterprises, Inc. Constellation Enterprises was previously owned by BGE. Constellation Energy's subsidiaries primarily include a domestic merchant energy business focused mostly on power marketing and merchant generation in North America, and BGE. This Quarterly Report on Form I0-Q is a combined report of Constellation Energy and BGE. The consolidated financial statements of Constellation Energy include the accounts of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises, Inc. and its subsidiaries, and Constellation Nuclear, LLC and its subsidiaries.
The consolidated financial statements of BGE include the accounts of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. We realigned our organization in response to the deregulation of electric generation.
In the first quarter of 2000, we combined our wholesale power marketing business with our domestic plant development and operations to form a domestic merchant energy business.
At the same time, we revised our operating segments to reflect those realignments as presented in the Notes to Consolidated Financial Statements on page 12. Several additional changes occurred in conjunction with the implementation of the Restructuring Order as described below. We discuss the deregulation of electric generation and the Restructuring Order in the Current Issues -Electric Competition section on page 20.  "* We formed two nonregulated subsidiaries
-Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation, Inc.  "* Effective July 1, 2000, BGE transferred its generation assets and related liabilities to these two new entities at book value.o Effective July 1, 2000, we formed a nonregulated holding company, Constellation Power Source Holdings, Inc., that includes the wholesale power marketing and risk management activities of Constellation Power Source,TM Inc., the domestic power projects of Constellation Investments,TM Inc. and Constellation Power,TM Inc., and subsidiaries, and the generating assets of Constellation Power Source Generation.
As a result of these changes, effective July 1, 2000, our domestic merchant energy business includes the operations of Constellation Power Source Holdings and the nuclear generation and consulting services of Constellation Nuclear, TM LLC. Also, effective July 1, 2000, the financial results of the electric generation portion of our business are included in the domestic merchant energy business.
Prior to that date, the financial results of electric generation were included in BGE's regulated electric business.
BGE remains a regulated electric and gas public utility company with a service territory in the City of Baltimore and all or part often counties in Central Maryland.
Our other nonregulated businesses include the: "* Latin American power projects of Constellation Power, and subsidiaries, "* energy products and services of Constellation Energy Source,TM Inc., "* home products, commercial building systems, and residential and commercial electric and gas retail marketing of BGE Home Products & Services,TM Inc. and subsidiaries, "* general partnership, in which BGE is a partner, of District Chilled Water General Partnership (ComfortLink) that provides cooling services for commercial customers in Baltimore, "* financial investments of Constellation Investments, and "* real estate and senior-living facilities of Constellation Real Estate Group,TM Inc. As discussed in the Subsequent Event section of the Notes to Consolidated Financial Statements 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 Constellation Energy and its subsidiaries, collectively.
Reference in this report to the "utility business" is to BGE. In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including:
"* what factors affect our business, "o what our earnings and costs were in the periods presented, "* why earnings and costs changed between periods, "* where our earnings came from, "* how all of this affects our overall financial condition, "* what we expect our expenditures for capital projects to be in the future, and "* where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated Statements of Income on page 3, which present the results of our operations for the quarters and nine months ended September 30, 2000 and 1999. We analyze and explain the differences between periods in the specific line items of the Consolidated Statements of Income. Our analysis is important in making decisions about your investments in Constellation Energy and/or BGE. Also, this discussion and analysis is based on the operation of the electric generation portion of our utility business under rate regulation through June 30, 2000. Our electric business is changing as we have transferred our electric generation assets and related liabilities to nonregulated subsidiaries of Constellation Energy and we have entered into retail customer choice for electric generation effective July 1, 2000. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance.
Strategy The change toward customer choice will significantly impact our business.
In response to this change, we regularly evaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. Prior to July 1, 2000, the majority of our earnings were from BGE. Going forward, we expect to derive almost two-thirds of our earnings from our domestic merchant energy business.
While BGE will continue to be regulated and deliver electricity and natural gas through its core distribution business, our growth strategies center on the nonregulated domestic merchant energy business with the objective of providing new sources of earnings.
Currently, our domestic merchant energy business owns or controls 8,500 megawatts of generation.
We have 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 in the Mid-West and South regions are scheduled for completion in 2002 and beyond. By 2005, our domestic merchant energy business expects to own or control approximately 30,000 megawatts.
As discussed in the Subsequent Event section of the Notes to Consolidated Financial Statements on page 11, we announced several initiatives to advance our growth strategies.
These initiatives consist of: "* a plan to separate our domestic merchant energy business from our retail services business, "* an agreement with an affiliate of Goldman Sachs under which it will invest in our domestic merchant energy business, and "* a reduction in our common stock dividend effective April 2001. In addition, we decided to exit the Latin American portion of our business as a result of our concentration on domestic merchant energy. Currently, we are actively seeking a buyer for the Latin American portion of our business and expect to complete our exit strategy in 2001. We also might consider one or more of the following strategies:
"* 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 the growth of our domestic merchant energy business, various factors will affect our financial results in the future. These factors include, but are not limited to, operating our generation assets in a deregulated market without the benefit of a fuel rate adjustment clause, the timing and implications of deregulation in other regions where our domestic merchant energy business will operate, the loss of revenues due to customers choosing alternative suppliers, higher volatility of earnings and cash flows, and increased financial requirements of our domestic merchant energy business.
Please refer to the Forward-Looking Statements section on page 37 for additional factors.
Current Issues -Electric Competition Electric utilities are facing competition on various fronts, including:
* the construction of generating units to meet increased demand for electricity,
* the sale of electricity in bulk power markets,
* competing with alternative energy suppliers, and
* electric sales to retail customers.
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.
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 service for customers that do not select an alternative supplier.
In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE.  "* BGE's electric base rates were frozen through June 30, 2000.  "* BGE reduced 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 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.  "* BGE's electric fuel rate clause was discontinued effective July 1, 2000.  "* Electric delivery service rates are frozen for a four year period for commercial and industrial customers.
The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers. 
"* BGE will 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 decommissioning costs are included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their amortization schedules prior to July 1, 2000.  "* Effective July 1, 2000, BGE unbundled rates to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and 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 Note 4 of our 1999 Annual Report on Form 10-K, by $150 million pre-tax during the period July 1, 1999 June 30, 2000 to mitigate a portion of BGE's potentially stranded investments. 
"* Universal service is being provided for low-income customers without increasing their bills. BGE will provide its share of a statewide find totaling $34 million annually.
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, Accountingfor the Effects of Certain Types of Regulation for that portion of its business.
Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises
-A ccountingfor the Discontinuation ofFASB Statement No. 71 and Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing ofElectricity
-Issues Related to the Application of FASB Statements No. 71 and 101 for BGE's electric generation business.
BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated.
We describe the effect of applying these accounting requirements in Note 4 of our 1999 Annual Report on Form 10-K. Please refer to the Legal Proceedings section on page 36 for a discussion regarding appeals of the Restructuring Order. As a result of the deregulation of electric generation, the following occurred effective July 1, 2000: BGE transferred, at book value, its nuclear generating assets, its nuclear decommissioning trnst fuind, and related liabilities to Calvert Cliffs Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its fossil generating assets and related liabilities and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to Constellation Power Source Generation.
In total, these generating assets represent about 6,240 megawatts of generation capacity with a total net book value at June 30, 2000 of approximately
$2.4 billion." BGE assigned approximately
$47 million to Calvert Cliffs Nuclear Power Plant, Inc. and $231 million to Constellation Power Source Generation of tax exempt debt related to the transferred assets. Also, Constellation Power Source Generation issued approximately
$366 million in unsecured promissory notes to BGE. Repayments of the notes by Constellation Power Source Generation will be used exclusively to service the current maturities of certain BGE long-term debt.  " BGE transferred equity associated with the generating assets to Calvert Cliffs Nuclear Power Plant, Inc. and Constellation Power Source Generation, Inc. The fossil fuel and nuclear fuel inventories, materials and supplies, and certain purchased power contracts of BGE were also assumed by these subsidiaries.
Effective July 1, 2000, BGE provides standard offer service to customers at fixed rates over various time periods during the transition period for those customers that do not choose an alternate supplier.
In addition, the electric fuel rate was discontinued effective July 1, 2000. Constellation Power Source provides BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Thereafter, BGE will competitively bid the energy and capacity.
Constellation Power Source obtains the energy and capacity to supply BGE's standard offer service obligations from affiliates that own Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants, supplemented with energy purchased from the wholesale energy market as necessary.
Our domestic merchant energy business is affected by weather conditions in the different regions of North America. Typically, demand for electricity, and its price, is higher in the summer and the winter, when weather is more extreme. All regions of North America typically do not experience extreme weather conditions at the same time. To date, the majority of our generation is located in the PJM (Pennsylvania-New Jersey-Maryland)
Interconnection.
Accordingly, our financial results are 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 We also believe it is important to discuss factors that have a strong influence on the performance of our regulated electric and regulated gas businesses.
In addition to electric restructuring which was discussed earlier, regulation by the Maryland PSC, the weather, and other factors, including the condition of the economy in our service territory influence BGE's businesses.
Regulation by the Maryland PSC Under traditional rate regulation that continues after July 1,2000 for BGE's electric transmission and distribution, and gas businesses, the Maryland PSC determines the rates we can charge our customers.
Currently, BGE's rates consist primarily of a "base rate" and a "fuel rate." Base Rate The base rate is the rate the Maryland PSC allows BGE to charge its customers for the cost of providing them service, plus a profit. BGE has 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.
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.
Generally, rate increases improve our utility earnings because they allow us to collect more revenue. However, rate increases are normally granted based on historical 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. On June 19, 2000, the Maryland PSC authorized a $6.4 million annual increase in our gas base rates effective June 22, 2000. As a result of the Restructuring Order, BGE's residential electric base rates are frozen until 2006. Electric delivery service rates are frozen for a four-year period for commercial and industrial customers.
The generation and transmission components of rates are frozen for different time periods depending on the service options selected by those customers.
Fuel Rate Through June 30, 2000, we charged our electric customers separately for the fuel we used to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity.
We charged the actual cost of these items to the customer with no profit to us. If these fuel costs went up, the Maryland PSC permitted us to increase the fuel rate. Under the Restructuring Order, BGE's electric fuel rate was frozen until July 1, 2000, at which time the fuel rate clause was discontinued.
We deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate through June 30, 2000. In September 2000, the Maryland PSC approved the collection of the $54.6 million accumulated difference between our actual costs of fuel and energy and the amounts collected from customers that were deferred under the electric fuel rate clause through June 30, 2000. We will collect this accumulated difference from customers over a twelve-month period beginning October 2000. Effective July 1, 2000, earnings are affected by the changes in the cost of fuel and energy. 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 30 and in Note I of our 1999 Annual Report on Form 10-K. Weather Weather conditions can have a great impact on BGE's results for interim periods primarily due to the impact on sales volumes and commodity prices. This means that results for interim periods do not necessarily represent results to be expected for the year. Weather affects the demand for electricity and gas for our regulated businesses.
Very hot summers and very cold winters increase demand. Mild weather reduces demand. Residential sales for our regulated businesses are impacted more by weather than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. However, the Maryland PSC allows us to record a monthly adjustment to our regulated gas business revenues to eliminate the effect of abnormal weather patterns.
We discuss this further in the Weather Normalization section on page 30. 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. Cooling degree days result when the average daily actual temperature exceeds the 65 degree baseline.
Heating degree days result when the average daily actual temperature is less than the baseline.22 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.
We show the number of heating degree days in the quarter and nine months ended September 30, 2000 and 1999, and the percentage change in the number of degree days between these periods in the following table: Quarter Ended September 30 Nine Months Ended September 30 Current Issues -Gas Competition Currently, no regulation exists for the wholesale price of natural gas as a commodity, and the regulation of interstate transmission at the federal level has been reduced. All BGE gas customers have the option to purchase gas from other suppliers.
Current Issues -Calvert Cliffs License Extension On March 23, 2000, the Nuclear Regulatory Commission (NRC) approved a 20-year license extension for both units of Calvert Cliffs, extending the license for Unit 1 to 2034 and for Unit 2 to 2036.2000 Heating degree days ...........
142 Percent change from prior period .........Cooling degree days ...........
445 Percent change from prior period ........ (29.3)%_999 2000 1999 On April 11, 2000 the United States Court of Appeals for the District of Columbia Circuit, in National 75 2,959 2,981 Whistleblowers Center v. Nuclear Regulatory Commission and Baltimore Gas and Electric Company, (0.7)% upheld the NRC's denial of the Center's motion to intervene in BGE's license renewal proceeding.
The 629 714 832 NRC had denied the Center's motion to intervene for failing to file timely contentions.
The Center has filed a (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 electricity and gas in our regulated businesses.
These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of regulated electric and gas operations.
In those sections, we discuss how these and other factors affected electric and gas sales during the periods presented.
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.
Under the Restructuring Order, BGE's electric customers can become delivery service customers only and can purchase their electricity from other sources. We will collect a delivery service charge to recover the fixed costs for the service we provide. The remaining electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Order. Usage per customer refers to all other items impacting customer sales that cannot be measured separately.
These factors include the strength of the economy in our service territory.
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.Current Issues -Regional Transmission Organizations In December 1999, the FERC issued Order 2000, amending its regulations under the Federal Power Act to advance the formation of Regional Transmission Organizations (RTOs). The regulations require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in a RTO. FERC also identified the minimum characteristics and functions that a transmission entity must satisfy in order to be considered a RTO. According to the Order, a public utility that is a member of an existing transmission entity that has been approved by FERC as in conformance with the Independent System Operator (ISO) principles set forth in the FERC Order No. 888, such as BGE, through its membership in the PJM must make a filing no later than January 15, 2001. While not required until 2001, PJM and the joint transmission owners, including BGE, made the filing on October 11, 2000. That filing explained the extent to which PJM met the minimum characteristics and finctions of a RTO and explained its plans to conform to 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 89.3%
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 affecting them. We begin with a general overview, then separately discuss earnings for our operating segments.
Changes in fixed charges, income taxes, and other income are discussed in the aggregate for all segments in the Consolidated Nonoperating Income and Expenses section on page 32. Overview Total Earnings Per Share of Common Stock Quarter Ended Nine Months Ended September 30 September 30 2000 1999 2000 1999 Earnings before nonrecurring charges included in operations:
Domestic merchant energy .........................
Regulated electric ..........
Regulated gas .................
Other nonregulated
........
Total earnings per share before nonrecurring charges included in operations
...................
Nonrecurring charges included in operations:
Deregulation transition cost .........
TVSERP ......................
Hurricane Floyd expenses ................
Write-off of power project ..............
Write-down of financial investment
..............
Write-down of senior living facilities
........
Earnings per share .......$.87 $.14 .10 1.05 (.03) .04 (.06)$1.10 $34 .65 1.73 .12 .14 (.01) (.05).98 1.13 1.86 2.16 (.10) (.03)(.03)(.03)(.05) (.12) (.02) ( $.98 $.91 $1.73 $1 Earnings for the periods presented below reflect a significant shift in earnings from the regulated electric business to the domestic merchant energy business as a result of the transfer of BGE's electric generation assets to nonregulated subsidiaries on July 1, 2000 in accordance with the Restructuring Order. We discuss the Restructuring Order in more detail in Current Issues Electric Competition section on page 20.Quarter Ended September 30, 2000 Our total earnings for the quarter ended September 30, 2000 increased
$11.4 million, or $.07 per share, compared to the same period of 1999. However, our total earnings before nonrecurring charges decreased
$20.9 million or $. 15 per share mostly due to extremely mild summer weather in 2000. We also recognized
$26.0 million, or almost one-half, of the annual impact of a 6.5% annual residential rate reduction that was effective July 1, 2000. This decrease was partially offset by a $37.5 million deferral of electric revenues recorded in September 1999 associated with the deregulation of our electric generation business that had a negative impact in that year. We did not have a similar deferral in 2000. We also had higher earnings from our other nonregulated businesses in the third quarter of 2000 compared to the same period of 1999. In addition, we recorded the following nonrecurring charges in operations during the third quarter of 1999: 0 $4.9 million after-tax, or $.03 per share, of expenses related to Hurricane Floyd, .a $6.7 million after-tax, or $.05 per share, write-off of a geothermal power project,
* a $17.3 million after-tax, or $.12 per share, write down of a financial investment, and .a $3.4 million after-tax, or $.02 per share, write down of certain senior-living facilities.
In the following sections, we discuss our earnings by business segment in greater detail.Nine Months Ended September 30,2000 .05) Our total earnings for the nine months ended September 30, 2000 decreased
$27.7 million, or S. 19 per share, .14) compared to the same period of 1999. Our total earnings before nonrecurring charges decreased
$44.4 million or .02) $.30 per share mostly due to the $75.0 million, or $45.4 .92 million after-tax, amortization of the regulatory asset recorded for the reduction of BGE's generation plant during the first half of 2000 and the large impact of the 6.5% annual residential rate reduction reflected in the third quarter. This decrease was partially offset by the $37.5 million deferral of electric revenues in 1999. In addition, we recorded the following nonrecurring charges in operations:
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 during the first and second quarters of 2000 for BGE employees that elected to participate in a Targeted Voluntary Special Early Retirement Program (TVSERP), -$4.9 million after-tax, or S.03 per share, of expenses related to Hurricane Floyd in 1999,
* a $6.7 million after-tax, or S.05 per share, write-off of a geothermal power project in 1999,
* a $20.9 million after-tax, or $.14 per share, write down of a financial investment in 1999, and -a $3.4 million after-tax, or S.02 per share, write-down of certain senior-living facilities in 1999. Domestic Merchant Energy Business Our domestic merchant energy business engages primarily in power marketing and domestic power generation.
We describe these businesses in more detail in our 1999 Annual Report on Form 10-K in Item 1. Business -Diversified Businesses.
As discussed in the Current Issues -- Electric Competition section on page 20, our domestic merchant energy business was significantly impacted by the July 1, 2000 implementation of customer choice in Maryland.
At that time, BGE's generating assets became part of our nonregulated domestic merchant energy business, and Constellation Power Source began selling to BGE the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Constellation Power Source will obtain the energy and capacity to supply BGE's standard offer service obligations from affiliates that own Calvert Cliffs and BGE's former fossil plants, supplemented with energy purchased from the wholesale energy market as necessary.
Constellation Power Source will also manage our wholesale market price risk. Our earnings are exposed to the risks of the competitive wholesale electricity market to the extent that Constellation Power Source has to purchase energy and/or capacity to meet obligations to supply power to BGE at market prices or costs, respectively, which may approach or exceed BGE's standard offer service rates. If the price of obtaining energy in the wholesale market exceeds the fixed standard offer service price, our earnings would be adversely affected.
We are also affected by operational risk, that is, the risk that a generating plant will not be available to produce energy when the energy is required.
Imbalances in demand and supply can occur not only because of plant outages, but also because of transmission constraints, or extreme temperatures (hot or cold) causing demand to exceed available supply.We cannot estimate the impact of the increased financial risks associated with customer choice. However, these financial risks could have a material impact on our financial results.
In addition, effective July 1, 2000, under the terms of separate agreements, domestic merchant energy business revenues include 90% of the competitive transition charges BGE collects from its customers (CTC revenues) and the portion of its revenues providing for decommissioning costs. Earnings Quarter Ended Nine Months Ended September 30 September 30 2000 1999 2000 1999 (In millions, except per share amounts) Revenues ...........................
$495.6 $66.3 $628.9 $173.7 Operating expenses ...........
221.7 40.7 312.3 87.8 Depreciation and amortization
.................
38.6 1.5 41.9 3.6 Taxes other than income taxes ................
13.1 -13.1 Operating income ..............
$222.2 $24.1 $261.6 $82.3 Net income ........................
$130.9 $12.2 $150.2 $43.6 Earnings per share .............
$ .87 $ .09 $ 1.00 $ .29 Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements.
Revenues During the quarter ended September 30, 2000, domestic merchant energy revenues increased
$429.3 million compared to the same period of 1999 mostly because of: -a $373.2 million increase related to providing BGE the energy and capacity required to meet its standard offer service obligation effective July 1, 2000, and -a $59.3 million increase related to CTC and decommissioning revenues included in the domestic merchant energy business effective July 1, 2000. During the nine months ended September 30, 2000, domestic merchant energy revenues increased
$455.2 million compared to the same period of 1999 mostly because of the increase in revenues associated with the implementation of customer choice as discussed above and higher revenues from our power marketing and domestic generation businesses.
Power marketing revenues increased during the nine months ended September 30, 2000 compared to the same period of 1999 mostly because of higher transaction volumes. These higher volumes were offset partially by lower margins.25 Our domestic generation business revenues increased during the nine months ended September 30, 2000 compared to the same period of 1999 mostly because of the gain recognized on the termination of an operating arrangement and the sale of certain subsidiaries.
In April 2000, Constellation Operating Services, Inc. (COSI), a subsidiary of Constellation Power, Inc., ended its exclusive arrangement with Orion Power Holdings, Inc. to operate Orion's facilities.
Orion purchased from COSI the four subsidiary companies formed to operate power plants owned by Orion. This increase was offset partially by lower revenues associated with our California power purchase agreements discussed below. Mark-to-Market Accounting 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 more detail in Note I of our 1999 Annual Report on Form I 0-K. 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 "* the number and size of open commodity and derivative 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 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.
Assets and liabilities from energy trading activities (as shown in our Consolidated Balance Sheets beginning on page 4) increased at September 30, 2000 compared to December 31, 1999 because of business growth during the period. California Power Purchase Agreements 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.
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. At the date of this report, 12 projects had already transitioned to variable rates. The remaining two projects will transition in December 2000. 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 I of our 1999 Annual Report of Form 10-K. 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 the Notes to Consolidated Financial Statements on page 16. Operating Expenses During the quarter ended September 30, 2000, domestic merchant energy operating expenses increased
$181.0 million compared to the same period of 1999 mostly because of increases of $102.6 million in fuel costs and $79.2 million in operations and maintenance costs. These fuel and operations and maintenance costs were associated with the generation plants that were transferred from BGE effective July 1, 2000.26 During the nine months ended September 30, 2000, domestic merchant energy operating expenses increased
$224.5 million compared to the same period of 1999 mostly because of: the transfer of fuel, operations, and maintenance costs from BGE effective July 1, 2000, as discussed on page 26, a $10.2 million write-off ofa geothermal power project in August 1999 by our domestic power projects business.
This write-off occurred because the expected future cash flow from the project was less than the investment in the project due to the declining water temperature of the geothermal resource used by the plant for production,
* a $24.0 million deregulation transition cost in June 2000 to a third party incurred by our power marketing business to provide BGE's standard offer service requirements, and
* an increase in operating expenses at our power marketing business due to the growth of the business.
Depreciation and Amortization Expense Domestic merchant energy depreciation and amortization expense increased
$37.1 million for the quarter and $38.3 million for the nine months ended September 30, 2000 compared to the same periods of 1999 mostly because of $36.8 million of expenses associated with the generation plants that were transferred from BGE effective July 1, 2000. Taxes Other than Income Taxes During the quarter and nine months ended September 30, 2000, domestic merchant energy taxes other than income taxes increased
$13.1 million compared to the same periods of 1999 because of $12.9 million of taxes other than income taxes associated with the generation plants that were transferred from BGE effective July 1, 2000. Regulated Electric Business As previously discussed, our regulated electric business was significantly impacted by the July 1, 2000 implementation of customer choice. These changes include BGE's generating assets and related liabilities becoming part of our nonregulated domestic merchant energy business on that date.Earnings Quarter Ended Nine Months Ended September 30 September 30 2000 1999 2000 1999 (In millions, except per share amounts) Electric revenues .................
$598.4 $691.4 $1,688.4 $1,737.9 Electric fuel and purchased energy ...........
388.3 Operations and maintenance
...................
62.0 Depreciation and amortization
...................
52.0 Taxes other than income taxes ..................
30.5 Operating income ................
$65.6 Net income ..........................
$15.4 Earnings per share .............
$ .10 130.0 146.3 632.4 376.2 384.7 468.5 78.3 276.7 227.0 59.5 121.0 149.2 $277.3 $273.6 $517.0 $152.3 $93.2 $253.4 $1.02 $ .62 $1.70 Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements.
Electric Revenues The changes in electric revenues in 2000 compared to 1999 were caused by: Quarter Ended Nine Months Ended September 30 September 30 2000 vs. 1999 2000 vs. 1999 (In millions)Electric system sales volum es .............................
$(28.5) Rates ...................
(75.5) Total change in electric revenues from electric system sales .....................
(104.0) Interchange and other sales ........................
(24.9) O ther ...................................
35.9 Total change in electric revenues ...............
$(93.0)$4.5 (62.9) (58.4) (30.2) 39.1 $(49.5)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 2000 compared to 1999 were: Quarter Ended September 30 2000 vs. 1999 Residential
..............
Commercial
.............
Industrial
.................
(10.8)% 0.2 13.2 Nine Months Ended September 30 2000 vs. 1999 (0.7)% 3.8 4.1 27 During the quarter ended September 30, 2000, we sold less electricity to residential customers due to extremely mild summer weather. We sold about the same amount of electricity to commercial customers.
We sold more electricity to industrial customers mostly because usage by Bethlehem Steel (our largest customer) was higher in 2000 because of a 1999 shut down for a planned upgrade to their facilities that temporarily reduced their electricity consumption in that year. During the nine months ended September 30, 2000, we sold about the same amount of electricity to residential customers due to the extremely mild summer weather being substantially offset by warmer spring and early summer weather, an increased number of customers, and higher usage per customer.
We sold more electricity to commercial customers mostly due to higher usage per customer and an increased number of customers.
We sold more electricity to industrial customers due to the increase in usage by Bethlehem Steel, offset partially by lower usage by other industrial customers.
Rates Prior to July 1,2000, our rates primarily consisted of an electric base rate and an electric fuel rate. Effective July 1, 2000, BGE discontinued its electric fuel rate and unbundled its rates to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and taxes. In addition, BGE's rates were frozen in total except for the implementation of a residential base rate reduction totaling approximately
$54 million annually.
Under the terms of the intercompany agreements whereby BGE obtains the energy and capacity to meet its standard offer service obligation, 90% of the CTC revenues BGE collects and the portion of its revenues providing for decommissioning costs, are included in revenues of the domestic merchant energy business effective July 1, 2000. During the quarter ended September 30, 2000, rate revenues decreased compared to the same period of 1999 mostly because we recognized
$26.0 million, or almost one-half of the 6.5% annual residential rate reduction, and $59.3 million of CTC and decommissioning revenues are included in the domestic merchant energy business.
During the nine months ended September 30, 2000, rate revenues decreased
$62.9 million compared to the same periods of 1999 as a result of the rate reduction and transfer of revenues discussed above, offset partially by higher rate revenues during the first half of 2000. Interchange and Other Sales "Interchange and other sales" are sales in the PJM energy market and to others. The PJM is an ISO that also operates a regional power pool with members that include many wholesale market participants, as well as BGE, and other utility companies.
Prior to the implementation of customer choice, BGE sold energy to PJM members and to others after it had satisfied the demand for electricity in its own system. Effective July 1, 2000, BGE no longer engages in interchange sales and these activities are included in our domestic merchant energy business which results in the decrease in interchange and other sales for the quarter and nine months ended September 30,2000 compared to the same periods of 1999. In addition, BGE had lower interchange and other sales during the first half of 2000 when increased demand for system sales reduced the amount of energy it had available for off-system sales. Other During the quarter and nine months ended September 30, 2000, other revenues increased compared to the same periods of 1999 mostly because of a $37.5 million deferral of electric revenues recorded in September 1999, which had a negative impact in that year. This deferral was recorded on the basis that as of September 30, 1999 these revenues were subject to refund pending the approval of the Restructuring Order by the Maryland PSC at that time. Electric Fuel and Purchased Energy Expenses Quarter Ended Nine Months Ended September 30 September 30 2000 1999 2000 1999 (In millions)
Actual costs ...............
$388.3 $191.8 $642.1 $454.7 Net deferral of costs under electric fuel rate clause .............
Total electric fuel and purchased energy-(61.8) (9.7) (78.5)expenses ................
$388.3 $130.0 $632.4 $376.2 Actual Costs During the quarter and nine months ended September 30, 2000, our actual costs of fuel and purchased energy were higher compared to the same periods of 1999 mostly because of the implementation of customer choice. As discussed in the Current Issues -- Electric Competition section on page 20, effective July 1, 2000, BGE transferred its generating assets to, and began purchasing substantially all of the energy and capacity required to provide electricity to standard offer service customers from, nonregulated affiliates of Constellation Energy. For the quarter and nine months ended September 30, 2000, the cost of energy BGE purchased from nonregulated affiliates of Constellation Energy was $373.2 million. The higher amnount paid for purchased energy is offset by lower operations and maintenance, depreciation, taxes, and other costs at BGE as a result of no longer owning and operating the transferred electric generation plants.28 Prior to July 1, 2000, BGE's purchased fuel and energy costs only included actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others. Electric Fuel Rate Clause Prior to July 1, 2000, we deferred the difference between our actual costs of fuel and energy and what we collected from customers under the fuel rate in a given period. Effective July 1, 2000, the fuel rate clause was discontinued under the terms of the Restructuring Order. During the quarter and nine months ended September 30, 2000, the net deferral of costs under the electric fuel rate clause decreased compared to the same periods of 1999 due to the discontinuation of the fuel rate clause effective July 1, 2000. We discuss the accumulated difference between our actual costs and what we collected through June 30, 2000 in the Recoverability of Electric Fuel Costs section of the Notes to Consolidated Financial Statements on page 16. Electric Operations and Maintenance Expenses During the quarter ended September 30, 2000, regulated electric operations and maintenance expenses decreased
$84.3 million compared to 1999 mostly because effective July 1, 2000, $79.2 million of costs were no longer incurred by this business segment. These costs were associated with the electric generation assets that were transferred to the domestic merchant energy business.
In addition, 1999 operations and maintenance expenses include approximately
$7.5 million of costs associated Hurricane Floyd that had a negative impact in that quarter.
During the nine months ended September 30, 2000, regulated electric operations and maintenance expenses decreased
$83.8 million compared to 1999 mostly due to the absence of $79.2 million of costs associated with the transfer of the electric generation assets. Also, 1999 operations and maintenance expenses include costs associated with Hurricane Floyd and a major winter ice storm earlier that year. This decrease is partially offset by the $7.0 million of expense recognized in 2000 for electric business employees that elected to participate in the TVSERP. Electric Depreciation and Amortization Expense During the quarter ended September 30, 2000, regulated electric depreciation and amortization expense decreased
$26.3 million compared to 1999 mostly because of the absence of $36.8 million of depreciation and amortization expense associated with the transfer of the generation assets to the domestic merchant energy business.
This was partially offset by higher amortization expense associated with our electric generation regulatory assets.During the nine months ended September 30, 2000, regulated electric depreciation and amortization expense increased
$49.7 million compared to 1999 mostly because of the $75.0 million amortization of the regulatory asset for the reduction in generation plant provided for in the Restructuring Order and higher amortization associated with other generation regulatory assets. This was partially offset by the absence of $36.8 million of depreciation and amortization expense associated with the transfer of the generation assets. Electric Taxes Other Than Income Taxes Regulated electric taxes other than income taxes decreased
$29.0 million for the quarter and $28.2 million for the nine months ended September 30, 2000 compared to the same periods of 1999. This was mostly due to comprehensive changes to the tax laws under the Electric Customer Choice and Competition Act of 1999. The comprehensive tax law changes are discussed further in Note 4 of our 1999 Annual Report on Form 10-K. In addition, regulated electric taxes other than income taxes reflect the absence of $12.9 million of taxes other than income taxes associated with the generation assets that were transferred to the domestic merchant energy business effective July 1, 2000. Regulated Gas Business Earnings Quarter Ended Nine Months Ended September 30 September 30 2000 1999 2000 1999 (In millions, except per share amounts)Gas revenues ........................
$90.1 Gas purchased for resale ...... 48.2 Operations and maintenance
....................
Depreciation and am ortization
....................
Taxes other than income taxes ...................
Operating income (loss) ....... Net income (loss) .................
Earnings per share ................
26.2 11.3 5.0 $(0.6) S(4.6) S(.03)$62.9 $377.8 $340. I 21.3 192.0 156.4 20.8 73.1 69.1 10.2 35.5 34.4 4.6 $6.0 $(0.7)25.0 25.2 $52.2 $55.0 $18.1 $21.5 $.12 $.14 Above amounts include intercompany transactions eliminated in our Consolidated Financial Statements.
All BGE customers have the option to purchase gas from other suppliers.
To date, customer choice has not had a material effect on our, and BGE's, financial results.29 Gas Revenues The changes in gas revenues in 2000 compared to 1999 were caused by: Quarter Ended Nine Months September 30 September 30 2000 vs. 1999 2000 vs. 1999 (In millions)Gas system sales volumes ..........................
Base rates ..................................
Weather normalization
..............
Gas cost adjustments
.................
Total change in gas revenues from gas system sales ...............
Off-system sales .........................
O ther ..........................................
Total change in gas revenues ...........................
$3.9 0.7 (1.9) 8.8 11.5 164$11.5 0.2 (5.4) (4.4) 1.9 36 1 (0.7) (0.3)$27.2$ 37.7 Gas System Sales Volumes The percentage changes in our gas 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
...........................
3.0% Commercial
..........................
17.6 Industrial
..............................
3.4 1.5% 7.5 4.2 During the quarter ended September 30, 2000, we sold more gas to residential customers compared to the same period of 1999 due mostly to an increased number of customers.
We sold more gas to commercial customers mostly because of higher usage per customer offset partially by fewer customers.
We sold more gas to industrial customers mostly because of an increase in the number of customers.
During the nine months ended September 30, 2000, we sold more gas to residential and commercial customers compared to the saone period of 1999 due to higher usage per customer and an increased number of customers.
This was partially offset by milder winter weather. We sold more gas to industrial customers mostly because of higher usage by Bethlehem Steel and other industrial customers, and an increased number of customers.
Base Rates During the quarter and nine months ended September 30, 2000, base rate revenues increased slightly compared to the same periods of 1999 mostly because on June 19, 2000, the Maryland PSC authorized a S6.4 million annual increase in our base rates effective June 22, 2000.Weather Normalization The Maryland PSC allows us to record a monthly adjustment to our gas revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues are based on weather that is considered "normal" for the month and, therefore, are not 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 as described in Note I of our 1999 Annual Report on Form 10-K. 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.
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.
During the quarter ended September 30, 2000, gas cost adjustment revenues increased compared to the same period of 1999 mostly because we sold gas at a higher price. During the nine months ended September 30,2000, gas cost adjustment revenues decreased compared to the same period of 1999 mostly because we sold less gas to non-delivery service customers.
This was partially offset by a higher price of gas sold. 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.
During the quarter and nine months ended September 30, 2000, revenues from off-system gas sales increased compared to the same periods of 1999 mostly because we sold more gas off-system at a higher price.30 Gas Purchased For Resale Expenses 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.
During the quarter and nine months ended September 30, 2000, our gas costs increased compared to the same periods of 1999 mostly because we bought more gas for off-system sales and all of the gas purchased was at a higher price. Gas Operations and Maintenance Expenses During the quarter and nine months ended September 30, 2000, gas operations and maintenance expenses increased compared to the same periods of 1999 mostly because of timing of corporate administrative and general expenses allocated to our business segments.
Gas Depreciation and Amortization Expense During the quarter and nine months ended September 30, 2000, gas depreciation and amortization expense was about the same compared to the same periods of 1999. Other Nonregulated Businesses Earnings Quarter Ended Nine Months Ended September 30 September 30 2000 1999 2000 1999 (In millions, except per share amounts) Revenues ............................
$187.7 $207.1 $557.4 $635.1 Operating exoenses ...............
156.2 233.0 496.7 637.1 Depreciation and am ortization
......................
5.8 2.8 Taxes other than income taxes .....................
1.0 1.0 Operating income (loss) ........ $24.7 $(29.7) Net income (loss) ..................
S5.7 $(27.7) Earnings per share ................
S.04 S(.20)$(2.3) $(31.6) $(.0) $(.21)Above amounts inchlde intercompany transactions eliminated in our Consolidated Financial Statements.
During the quarter ended September 30, 2000, earnings from our other nonregulated businesses increased compared to the same period of 1999 mostly because of higher earnings from our financial investments business.
Our financial investments business had higher earnings due to an increase in its market performance and a 1999 write-down of a financial investment that had a negative impact in that year. In addition, our energy products and services business had higher gross margins from its gas trading activities.
During the nine months ended September 30, 2000, earnings from our other nonregulated businesses increased compared to the same period of 1999 mostly because of higher earnings from our financial investments and energy products and services businesses.
In addition, in 1999, we wrote-down a financial investment and certain senior-living facilities, which had negative impacts in that year. These increases were partially offset by lower earnings from our Latin American business primarily due to increased operating expenses in Guatemala.
In December 1999, we decided to exit the Latin American portion of our power projects business as part of our strategy to improve our competitive position.
We discuss our strategy further in the Strategy section on page 19. In June 1999, our financial investments business wrote down its investment in Capital Re stock by $3.6 million after-tax, or $.02 per share. In September 1999, our financial investments business wrote-down the investment by an additional
$17.3 million after-tax, or S. 12 per share. These write-downs were recorded to reflect the valuation for the exchange of its shares of common stock in Capital Re for common stock of ACE Limited during these periods. This exchange is discussed further in our 1999 Annual Report on Form 10-K. In September 1999, our real estate and senior-living facilities business wrote-down certain senior-living facilities by S3.4 million after-tax, or &.02 per share, related to the announcement of the sale of those facilities.
Most of Constellation Real Estate Group's real estate and 16.6 9.0 senior-living projects are in the Baltimore-Washington corridor.
The area has had a surplus of available land in 3.0 2.8 recent years and as a result these projects have been 41.1 $(13.8) 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 and senior-living operations has not been enough to make the monthly loan payments on some of these projects.
Cash shortfalls have been covered by cash obtained from the cash flows of, or additional borrowings by, other nonregulated subsidiaries.
31 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 and senior-living projects.
If we were to decide to sell our projects, we could have write-downs.
In addition, if we were to sell our projects in the current market, we would have losses which could be material, although the amount of the losses is hard to predict. Depending on market conditions, we could also have material losses on any future sales. Our current real estate and senior-living strategy is to hold each project until we can realize a reasonable value for it. Under accounting rules, we are required to write down the value of a 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 cash flow from the project is less than the investment in the project.Consolidated Nonoperating Income and Expenses Fixed Charges During the quarter and nine months ended September 30, 2000, fixed charges increased compared to the same periods of 1999 mostly because we had more debt outstanding.
Income Taxes During the quarter and nine months ended September 30, 2000, our total income taxes increased compared to the same periods of 1999 mostly because we had higher taxable income from our nonregulated businesses and an increase in state and local taxes as a result of comprehensive changes to these laws. This increase was partially offset by lower taxable income at BGE. We discuss the comprehensive tax law changes in Note 4 of our 1999 Annual Report on Form 1 O-K.Financial Condition Cash Flows Cash provided by (used in): Operating Activities Investing Activities Financing Activities Nine Months Ended September 30 2000 1999 (In millions)
$588.8 $483.5 (728.4) (441.8) 97.3 (159.0)During the nine months ended September 30, 2000, we generated more cash from operations compared to the same period in 1999 mostly because of changes in working capital requirements.
During the nine months ended September 30, 2000, we used more cash for investing activities compared to the same period in 1999 mostly due to an increase in investments in new generation facilities.
In addition, our real estate and senior-living facilities business received less cash compared to the same period of 1999, due to the sale of a project in 1999. We did not have a similar sale in 2000.During the nine months ended September 30, 2000, we had more cash from financing activities compared to the same period of 1999 mostly because we issued more long-term debt and common stock. This was partially offset by repayment of our long-term debt that matured.
Security Ratings Independent credit-rating agencies rate Constellation Energy and BGE's fixed-income securities.
The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities.
These ratings affect how much it will cost each company to sell these securities.
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 Moody's & Poors Investors Fii Rating Group Service 1B1 Constellation Energy Unsecured Debt BGE Mortgage Bonds Unsecured Debt Trust Originated Preferred Securities and Preference Stock A-AA A A3 A] A2 tch CA A A+ A A-A-32"a2" Capital Resources Our business requires a great deal of capital. Our estimated annual amounts for the years 2000 through 2002, are shown in the table below. 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. Capital requirements for 2000 through 2002 include estimates of funding for existing and anticipated projects.
We continuously review and modify those estimates.
Actual requirements may vary from the estimates included in the table below because of a number of factors including:
"* 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.
Our estimates are also subject to additional factors.
Please see the Forward-Looking Statements section on page 37. Effective July 1, 2000, all of BGE's generation assets were transferred to nonregulated subsidiaries of Constellation Energy. The discussion and table for capital requirements below include these generation assets as part of the utility's 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 (In millions)Nonregulated Capital Requirements:
Investment requirements:
Domestic Merchant Energy Other Total investment requirements Retirement of long-term debt Total nonregulated capital requirements Utility Capital Requirements:
Construction expenditures (excluding AFC): Regulated Electric:
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
$ 803
* 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
$110 million for electric generation and nuclear fuel formerly part of BGE's regulated electric business.33 Capital Requirements Domestic Merchant Energy Business Our domestic merchant energy business will require additional funding for growing its power marketing business and developing and acquiring power projects.
Our domestic merchant energy business investment requirements include the planned construction of 1,100 megawatts of peaking capacity in the Mid-Atlantic/Mid West region by the summer of 2001 and an additional 4,300 megawatts of peaking and combined cycle production facilities scheduled for completion in 2002 and beyond in the Mid-West and South regions. Longer range, our plans are to own or control approximately 30,000 megawatts of generation capacity by 2005. For further information see the Strategy section on page 19. Electric Generation Electric construction expenditures for our regulated electric business include improvements to generating plants and costs for replacing the steam generators at Calvert Cliffs through June 30, 2000. Thereafter, these expenditures are reflected in our domestic merchant energy business.
In March 2000, we received the license extension from the NRC that extends our operating licenses to 2034 for Unit 1 and 2036 for Unit 2 as discussed in the Current Issues Calvert Cliffs License Extension section on page 23. If we do not replace the steam generators, we will not be able to operate these units through our operating licenses period. We expect the steam generator replacement to occur during the 2002 refueling outage for Unit I and during the 2003 refueling outage for Unit 2. We estimate these Calvert Cliffs' costs to be:$ 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.
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.
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
$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.
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.
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.
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.
Some of the information is about costs that may be material.
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.
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.
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.
Besides BGE, Constellation Energy Group, Constellation Nuclear and Calvert Cliffs Nuclear Power Plant are also named defendants.
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.
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.
Besides Constellation Energy, BGE and Constellation Holdings, Inc. are also named defendants.
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.
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.
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).
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.
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.
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.
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.
On May 24, 2000, the Circuit Court dismissed both the Trigen and Sweetheart Cup appeals.
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.
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.
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,
* 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, including the outcome of MAPSA's appeal,
* 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,
* higher volatility of earnings and cash flows,
* increased financial requirements of our nonregulated subsidiaries,
* 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.
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.
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.
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.
CONSTELLATION ENERGY GROUP, INC.  (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:
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 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 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));
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) NRC minimum requirement for Unit I and 82% of Unit 2 (millions)
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));
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)
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 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) $87 IRatio of U.S. Assets to Guarantee Amount 71.7 Exhibit 14 10 CFR § 50.75 (c) CALCULATION WORKSHEETS Unit 1 NRC Minimum Decommissioning Requirement Calculation Thermal Power (MWt) BWR Formula Base 1986 Cost (1986$) 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)
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]
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.
: 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)}}

Latest revision as of 01:59, 17 January 2025

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)
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