ML18018B686
| ML18018B686 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 06/20/1984 |
| From: | CAROLINA POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML18018B685 | List: |
| References | |
| NUDOCS 8406250221 | |
| Download: ML18018B686 (124) | |
Text
BEFORE THE UNITED STATES NUCLEAR REGULATORY CO>MISSION DOCKET NO+50-400 In the Natter of Carolina Power 6 Light Company APPLICATION FOR LICENSES UNDER THE ATO>iIC ENERGY ACT OF 1954 AS DiENDED for SHEARON HARRIS NUCLEAR POWER PLANT (OPERATING LICENSE STAGE RiEND~1ENT) f 840625 00@00'DR A o pgR A I l pC t>>e h g 0 Operating License Stage Amendment as revised April 1984 CAROLINA POWER&LIGHT COMPANY BY: M.A.McDuffie, for Vice President Sworn to and subscribed before me this M day of , 1984.My commission expires:/0/0/gg Notary Public: gOTAq>:.~R OBL tC NORTH CAROLINA EASTERN MUNICIP4POSNYY,+'y~
POWER AGENCY~<ll llilBRR BY: Ralp W.Shaw, General Manager C)un~Sworn to and subscribed before me this~day of~l, 1984.My commission expires:/0/PT/g~Notary Public (9955HHH/pgp) g)L'C'g.<<0i 00)f'f~~(*~-0 0~p<g0 I 0 iv)0, 0~0'I'3'j>6.'i'0~,,i,'I it.agent",', 0 Operating License Stage Amendment as revised April 1984 CAROLINA POWER&LIGHT COMPANY APPLICATION FOR OPERATING LICENSE General Information 1 NAME OF APPLICANTS Carol'lna Power&Light Company (CP&L)North Carolina Eastern Municipal Power Agency (Power Agency)2~ADDRESS OF APPLICANTS CP&L P 0 Box 1551 411 Fayetteville Street Mall Raleigh, North Carolina 27602 Power Agency P.O.Box 95162 3117 Poplarwood Court Raleigh, North Carolina 27625 3~DESCRIPTION OF BUSINESS OF APPLICANTS CP&L is an electric utility engaged exclusively in the generation, purchase, transmission, distribution, and sale of electric energy.The territory served by CP&L, an area of approximately 30,000 square miles, includes a substantial portion of the Coastal Plain in North Carolina extending to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section in North Carolina and in South Carolina and an area in western North Carolina in and around the city of Asheville.
The estimated total population of the service area is approximately 3 million.As of December 31, 1983, CP&L furnished electric service to approximately 796,000 customers.
CP&L's facilities in Asheville and vicinity are connected with CP&L's system in other areas served by CP&L through the facilities of Duke Power Company, so that power may be transferred from or to the Asheville area through such interconnections.
There are also interconnections with the facilities of Appalachian Power Company, Tennessee Valley Authority, Virginia Electric and Power Company, South Carolina Electric&Gas Company, South Carolina Public Service Authority, and Yadkin, Inc.As of December 31, 1983, CP&L owned and operated nine steam electric generating plants with a maximum dependable capability of 7,518,000 KW, four hydroelectric plants with a net capability of 214,000 KN and internal combustion turbine generating units with a net capability of 1,018,000 KW.One 720,000 KV fossil fueled steam electric generating unit is scheduled for completion in 1991.Power Agency is a public body corporate and politic and an instrumentality of the state of North Carolina, incorporated under North Carolina statutes in December 1976.Power Agency was created to plan, develop, construct, and operate generation and transmission facilities.
Power Agency has been'ranted all of the powers necessary or convenient to carry out such purposes.Pursuant to a Purchase, Construction, and Ownership Agreement between gP&L and Power Agency dated July 30, 1981, Power Agency has acquired from CP&L undivided ownership interests in certain of CP&L's generating (9955HHH/pgp)
A I II I Operating License Stage Amendment as revised April 1984 facilities, including Shearon Harris Nuclear Power Plant (SHNPP)Unit 1.A Power Coordination Agreement between CP&L and Power Agency and agreements between Power Agency and Virginia Electric and Power Company provide Power Agency with backstand services, supplemental power, and transmission services.Power Agency has entered into contracts with thirty-two political subdivisions.
Pursuant to these contracts, Power Agency is to be the sole and exclusive bulk power supplier for each such political subdivision in excess of any allotment of federal power from Southeastern Power Administration or of the output of any resouxce such political subdivision may develop and install pursuant to the contractual arrangements between Power Agency and such political subdivision.
Each such political subdivision is obligated to take or pay for its entitlement share of power from any owned project, such as SHNPP Unit 1~The terms of said contracts are for the life of the project or so long as any of Power Agency's bonds issued to finance the project are outstanding, but not exceeding 50 years.4o LEGAL STATUS CP&L is a public service corporation formed under the laws of North Carolina in 1926.The names and addresses of CP&L's directors and principal officers, all of whom are ci.tizens of the United States, are as follows: Directors:
Sherwood H.Smith, Jr., Chairman, Raleigh, North Carolina Daniel D.Cameron, Sr., Wilmington, North Carolina Felton J.Capel, Southern Pines, North Carolina George H.V.Cecil, Asheville, North Carolina Charles W.Coker, Jr., Hartsville, South Carolina William ED Graham, Jr., Raleigh, North Carolina Hargaret T.Harper, Southport, North Carolina L.H.Harvin, Jr., Henderson, North'arolina Karl G.Hudson, Jr., Raleigh, North Carolina Edward G.Lilly, Jr., Raleigh, North Carolina John G.Hedlin, Jr., Winston-Salem, North Carolina A.C.Honk, Jr., Farmville, North Carolina Horace L.Tilghman, Jr,, Harion, South Carolina E.E.Utley, Raleigh, North Carolina Princi al Officers: Name Sherwood H.Smith, Jr.Position Chairman/President and Chief Executive Officer E.E.Utley Executive Vice President and Chief Operating Officer Edward G.Lilly, Jr.Executive Vice President and Chief Financial Officer (9955HHH/cfr) n II l A I H f7 lt d d lk I Operating License Stage Amendment as revised April 1984 William E.Graham, Jr.Charles D.Barham, Jr.Executive Vice President Senior Vice President and General Counsel James H.Davis, Jr.Lynn W.Eury Russell H.Lee H.A.HcDuffie Wilson W.Horgan J.L.Lancaster, Jr.L.T.Quarles Paul ST Bradshaw Senior Vice President Senior Vice President Senior Vice President Senior Vice President Senior Vice President Secretary Treasurer Vice President and Controller The address of the foregoing principal officers of CP&L is: Post Office Box 1551 411 Fayetteville Street Hall Raleigh, North Carolina 27602 Power Agency is a body corporate and politic and an instrumentality of the state of North Carolina created pursuant to the Joint Hunicipal Electric Power and Energy Act, Chapter 159B of the General Statutes, as amended, of North Carolina'he names and business addresses of Power Agency's Board of Commissioners, all of whom are citizens of the United States, are as follows: The Honorable Frederick E.Turnage, Chairman City of Rocky Hount Hr.Peter G.Vandenberg, Vice Chairman Laurinburg Hr.Charles O'H.Horne, Jr., Secretary-Treasurer City of Greenville Hr.Ralph W.Shaw, General Hanager Hr.Ronald Wicker Town of Apex Hr.Jordan C.Horne Town of Ayden Hr.Steven S.Weatherman Town of Belhaven Hr.Steven L.Harrell Town of Benson Hr.Charles R.Stewart Town of Clayton Hr.Willis Privott Town of Edenton (9955HHH/cfr) tih't~il'I I W~I I I t 3 W W l,lt J k IWW'I I 1 if'I h I tl 3 v~I'ltI r>h W It k I f 3 1 lt'f~~'f~, I 3 3 h t>j I f I I ff Il W t I>W 0 f I r>fJ r o R)h ft f I tt gf t'3'W Operating License Stage Amendment as revised April 1984 Nr.Joseph BE Anderson City of Elizabeth City Nr.Connie Price Town of Fremont Nr.J.A.Wooten, Jr.Town of Farmville Nr.W.P.Riley, Jr.Town of Hamilton Hr.E.A.Warren City of Greenville Hr.R.G.Anthony Town of Hobgood Hr.Jesse.Harris Town of Hertford Hr.Simon C.Sitterson, Jr.City of Kinston Hri Gene C.Hill Town of Hookerton Hr.Peter G.Vandenberg City of Laurinburg Hr.Edward B.Walters Town of LaGrange Nr.Harry L.Ivey City of Lumberton Hs.Lois Brown Wheless Town of Louisburg Nr.C.Vance Greeson Town of Pikeville Hr.Boyd C.Hyers City of New Bern Hr.Ralph S.Nobley Town of Robersonville Hr, John HcNeill Town of Red Springs Hr.Joe Edwards, Jr.Town of Selma Hr.Frederick E.Turnage City of Rocky Nount Hr.Hugh C.Talton Town of Smithfield Hr, N.0.HcDowell, Jr.Town of Scotland Neck Hr.J.Ray King Town of Tarboro Nr.W.Robert Thorsen City of Southport Hr.Rodney V.Byard Town of Wake Forest Nr.Abbott N.Sawyer City of Washington Nr.T.Bruce Boyette City of Wilson The office address of the Power Agency is: Post Office Box 95162 3117 Poplarwood Court Raleigh, North Carolina 27625 The applicants are not owned, controlled, or dominated by an alien, foreign corporation or foreign government.
The applicants make this application on their own behalf and are not acting as agent or representative of any other person.(9955HHH/cfr)
,'P f~h J 4 1 lf J It~4'I ,~~1'~'lf J 1 1'h J L J J~,t u 4 It rl 4~I~1,~ur 1 Jl I b 4 Pfr I hl I'l'h Iu I 8'l uu r ll I 4 I J~t II 1 h 4 ,hg I P I ul~I Pit M 1 4 Ig l I 4 W irr'I',I u 1 Operating License Stage Amendment as revised April 1984 5~CLASS AND PERIOD OF LICENSE APPLIED FOR AND USE TO WHICH FACILITIES WILL BE PUT The license applied for is a Class 103 Operating License pursuant to Section 103 of the Atomic Energy Act of 1954, as amended (the Act)and as defined by 10 CFR 50.22 for the operation of SHNPP Unit 1 for a period of forty (40)years'pplicants propose to build and operate one pressurized water nuclear reactor which will comprise a one~nit nuclear fueled steam electric generating plant to be constructed on an approximately 10,800-acre site in Wake and Chatham Counties, North Carolina'P&L will retain exclusive responsibility for the design, construction, and operation of SHNPP Unit 1.The unit is designed for operation at a net electrical output of approximately 900>iWe (design target rating).The corresponding thermal rating of the reactor is 2785 HWt.SHNPP Unit 1 is scheduled for commercial operation in March, 1986.Details concerning the plant and its site are contained in the Final Safety Analysis Report (FSAR)constituting a part of this Application.
The plant will be used for the commercial generation of electrical energy.Applicants request such additional source, special nuclear and byproduct material licenses as may be necessary or appropriate to the construction and operation of the plant, and authorization to store source, special nuclear, and byproduct material irradiated in the nuclear reactors licensed under DPR-23, DPR-62, and DPR-71 and subsequently transported to SHNPP Unit 1~6e FINANCIAL UALIFICATION OF APPLICANTS CP&L is an established New York Stock Exchange listed corporation with capital stock and retained earnings which totaled approximately
$2,087,244,000 at December 31, 1983, Quarterly dividends on Common Stock have been paid in each year since 1946, the year CP&L Common Stock became publicly held.All applicable dividends on Preferred and Preference stocks accruing since CP&L's incorporation in 1926 have been paid CP&L's Annual Report to Shareholders for the year ended December 31, 1983, is attached as Appendix A.A copy of CP&L's Annual Report to the Securities and Exchange Commission (Form 10-K)for the year ending December 31, 1983, is included as Appendix B The funds necessary to operate and shut down the facility will be derived from operating revenues associated with the sale of electricity produced by the plant.As a regulated public utility, CP&L has reasonable assurance that rates established to cover its cost of producing electricity will be sufficient to cover operating and decommissioning costs.The Joint Municipal Electric Power and Energy Act of the General Statutes of North Carolina, NCGS 159B-11(14) authorizes joint agencies"To fix, charge and collect rents, rates, fees and charges for electric power or energy and other services, facilities and commodities sold, furnished or supplied through any projects~" Under the Power Coordination Agreement and the Operating and Fuel Agreement between Power Agency and CP&L, Power Agency covenants to set rates adequate to cover all its costs.These obligations are embodied in the agreements between Power Agency and its Participants No regulatory approvals (9955HHH/cfr)
IP'I ,'<<<<A I P P)3w.I I" I 4 4 I V J;fP'I hl 4 l<<P I I Jl eh I, I ll I P N I I'!V P 4 I Pli ghlk Operating License Stage Amendment as revised April 1984 are required by Power Agency in setting rates to its Participants'he Participants, as municipalities of the state of North Carolina, have authority to establish their own retail rates for service to their customers.
In NCGS 159B-22, the state of North Carolina covenants and agrees that so long as any bonds of Power Agency are outstanding and unpaid, the state will not limit or alter the rights of any participant or of Power Agency to establish, maintain, revise, charge, and collect electric rates to fulfill the terms of any agreement for the project.Pursuant to its Agreements with CP&L, Power Agency will pay its proportionate share of all costs associated with the construction, operation, cancellation, or decommissioning of SHNPP Unit 1.Power Agency will include in its lionthly Project Power Costs, to be charged to its Participants, charges sufficient to enable Power Agency to meet its commitment to bear its share of such costs'ach Participant has agreed to pay its Participants'hare of such Monthly Project Power Costs.Each Participant has undertaken a"take or pay" commitment, thereby obligating each Participant to pay its share of I'ionthly Project Power Costs whether or not the jointly owned facilities, including SHNPP Unit 1, are completed, operable, operating, or decommissioned.
Power Agency has established a reserve for the costs of decommissioning of the jointly owned nuclear units.Financial Information concerning Power Agency is included as Appendix C.7~REGULATORY AGENCIES AND MEDIA CP&L's retail rates and services in North Carolina are subject to the regulatory jurisdiction of the North Carolina Utilities Commission, Dobbs Building, 430 N.Salisbury Street, Raleigh, North Carolina 27602.CP&L's retail rates and services in South Carolina are subject to the regulatory jurisdiction of the South Carolina Public Service Commission, P.O.Drawer 11649, Columbia, South Carolina 29211'P&L's wholesale rates and services are subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission, Washington, D.C.Power Agency is subject to the jurisdiction of the Local Government Commission of North Carolina, a division of the Department of State Treasurer which supervises the issuance of bonded indebtedness of all North Carolina units of local government, public authorities, and power agencies, and provides assistance in the area of fiscal management.
The following is a li.sting of the newspapers of general circulation in the Applicants'ervice area which are considered appropriate to give reasonable notice of the application to those persons who might have a potential interest in the facilities to be operated by the Applicants:
Ci.tizen Times Courier Tribune Daily Record Asheville, North Carolina Asheboro, North Carolina Dunn, North Carolina (9955HHH/cfr)
Ik MI.iht'," , I hM<)JM))VM tt'N n v~M h'M M")I M)V>w'Mt I)V M'I MM h MI I'v ll I a v I M h M I l MNI ,h)t t'I'V II, II M II I~I),l IIIN'l II M I Il P V Mt M'I'V V M I I'h r V V I Vl M' Operating License Stage Amendment as revised April 1984 Fayetteville Observer Fayetteville Times News-Argus Henderson Dispatch Daily News Kinston Daily Free Press Rob esonian Sun Journal News and Observer Raleigh Times Richmond County Journal Evening Telegram Sanford Herald Star-News Daily Times Florence Morning News Sumter Daily Item Fayetteville, North Carolina Fayetteville, North Carolina Goldsboro, North Carolina Henderson, North Carolina Jacksonville, North Carolina Kinston, North Carolina Lumberton, North Carolina New Bern, North Carolina Raleigh, North Carolina Raleigh, North Carolina Rockingham, North Carolina Rocky Mount, North Carolina Sanford, North Carolina Wilmington, North Carolina Wilson, North Carolina Florence, South Carolina Sumter, South Carolina 8.COMMUNICATIONS CP&L will be solely responsible for communications with NRC related to this application for SHNPP Unit 1.Accordingly, all communications to CP&L or Power Agency pertaining to this Application for SHNPP Unit 1 shall be sent to: Mr.M.A.McDuffie, Senior Vice President Carolina Power&Light Company Post Office Box 1551 411 Fayetteville Street Raleigh, North Carolina 27602 to: In addition, it is requested that one copy of each communication be sent Mr.Richard E.Jones Vice President and Senior Counsel Carolina Power&Light Company Post Office Box 1551 411 Fayetteville Street Raleigh, North Carolina 27602 Mr.George F.Trowbridge Shaw, Pittman, Potts, and Trowbridge 1800 M Street, NW Washing ton, DC 20036 Mr.W.G.Wemhoff Director-Engineering North Carolina Eastern Municipal Power Agency Post Office Box 95162 3117 Poplarwood Court Raleigh, North Carolina 27625 (9955HHH/pgp) i l' APPENDIX B SECURITIES AND EXCHANGE COMMISSION Washington, D.C.20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal ear ended 12/31/83 Commission file number 1-3382 CAROLINA POWER R LIGHT COMPANY Exact name of registrant as specified in its charter North Carolina State or other jurisdiction of incorporation or organization) 411 FayetteviQe Street Raleigh h North Carolina (Address of principal executive offices)56-0165465 I.R.S.Employer Identification No.)27602 Zip Code)919-836-6111 (Registrant's telephone number)SECURITIES REGISTERED PURSUANT TO SECTION 12(b)OF THE ACT: Name of each exchan e Title of each class Common Stock (Without Par Value)First Mortgage Bonds, 7-3/496 Series due 2002$2.675 Preference Stock, Series A (Without Par Value, Cumulative) on which registered New York Stock Exchange Pacific Stock Exchange New York Stock Exchange New York Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12()OF THE ACT Preferred Stock (Without Par Value Cumulative)
Title of Class)Indicate by check mark whether the registrant (1)has 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 (or for such shorter period that the registrant was required to file such reports), and (2)has been subject to such filing requirements for the past 90 days.Yes X.No
The aggregate market value of the voting stock held by non-affiliates at January 31, 1984, was$1,778,908,953.
Common Stock (Without Par Value)shares outstanding at February 29, 1984: 63,296,030.
DOCUMENTS INCORPORATED BY
REFERENCE:
Portions of the 1984 proxy statement are incorporated into Part III, Items 10, 11, 12 and 13 hereof.PART I ITEM 1.BUSINESS General 1)Carolina Power 4 Light Company (Company)is a public service corporation formed under the laws of North Carolina in 1926, and is engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina.The Company had 9,003 employees at December 31, 1983.The principal executive offices of the Company are located at 411 FayetteviQe Street, Raleigh, North Carolina 27602, telephone, 919-836-6111.
2)The territory served, an area of approximately 30,000 square miles, includes a substantial portion of the coastal plain in North Carolina extending to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section in North Carolina and in South Carolina, and an area in western North Carolina in and around the City of Asheville.
The estimated total population of the territory served is approximately 3 million.3)Electric service is rendered at retail in 219 communities, each having an estimated population of 500 or more, and wholesale service is currently supplied to one joint municipal power agency, 4 municipalities, 18 electric membership corporations and one private electric system.4)In 1981, the Company entered into certain agreements with North Carolina Eastern Municipal Power Agency (Power Agency), which is composed of former North Carolina municipal wholesale customers of the Company and Virginia Electric and Power Company.Pursuant to such agreements, Power Agency has acquired in a series of closings undivided ownership interests of 18.33%in Brunswick Units Nos.1 and 2, 12.94%in Roxboro Unit No.4 and 16.17%in Harris Unit No.1 and Mayo Units Nos.1 and 2 (collectively referred to as"Joint Facilities").The Company constructs and oper ates the Joint Facilities for Power Agency and provides transmission services, back-stand services and supplemental power as necessary to enable Power Agency to provide its participants with their total electric power requirements.
Power Agency's payment obligation with respect to cancellation costs for Harris Units Nos.2, 3 and 4 is 12.94%of such costs.5)At December 31, 1983, the Company was furnishing electric service to approximately 796,000 customers.
During 1983, 31.5%of operating revenues was derived from residential sales, 29.0%from industrial sales, 19.7%from commercial sales, 16.0%from wholesale sales and 3.8%from other sources.Of such operating revenues, approximately 83.6%was derived from North Carolina and approximately 16.4%from South Carolina.
6)For the twelve months ended December 31, 1983, average revenues per KWH sold to residential, commercial and industrial customers were 6.47 cents, 5.87 cents, and 4.69 cents, respectively.
Sales to residential customers were as follows: Year 1979~~~~~~~~~~~~t~1 980~~~~~o~~~~~~~~198 lo~~~~~~~~~~~~~1982'~~~~~~~~~~~~1983@~~~~~~~~~~~~~Average Annual KWH Use 11,785 12,558 12,087 11,663 11,889 Average Annual Bill$480.84 546.11 648.57 V22.26 V69.27 Revenue~er KWH 4.085 4.35 5.3V 6.19 6.47 7)The highest 60-minute net peak demand to date of 6,926 MW was reached on August 22,1983, during an unusually hot summer period.The Company's generating reserves based on instaQed capacity and scheduled firm purchases had been forecasted to be approximately 27%at the time of the peak demand.However, due to the unavailability of some generating capacity, actual reserves at the time of the peak were approximately 6%.8)Total system peak demand for 1981, 1982 and 1983 increased by 4.3%, 3.1%and 4.9%, respectively, as compared with the preceding year.Total system load factors, expressed as the ratio of the average load supplied to the peak load demand, for the years 1981-1983 were 57.7%, 55.7%, and 56.6%, respectively.
The Company presently forecasts summer reserves of 27.3%and 23.3%over anticipated system peak load for 1984 and 1985, respectively, based upon the rated Maximum Dependable Capacity of generating units in commercial operation (see"Generating Capability").It is anticipated, however, that some of the generating units included in arriving at these reserve figures will be unavailable as a result of scheduled outages or environmental and operating problems.See"Environmental Matters" and"Nuclear Matters".The above data include capability and load from Power Agency's portion of the Joint Facilities.
9)The Company is subject to regulation by the Federal Energy Regulatory Commission (PERC)with respect to licensing and operation of hydroelectric projects, rates for transmission and sale of electric energy at wholesale, the interconnection of facilities (other than emergency interconnection) and, to the extent the PERC determines, accounting policies and practices.
In addition, the Company is subject to regulation by the Nuclear Regulatory Commission (NRC)with respect to the construction and operation of nuclear reactors.With respect to retail service territory, retail rates, issuance of securities and other matters, the Company is subject to regulation in North Carolina by the North Carolina Utilities Commission (NCUC)and in South Carolina by the South Carolina Public Service Commission (SCPSC).The Company is also subject to regulation by federal, state and local authorities with respect to air qualitv, water quality, and disposal of liquid and solid wastes.See"Retail Rate Matters","Wholesale Rate Matters","Environmental Matters","Nuclear Matters" and"Nuclear Puel Supply".
Construction Program 1)During 1983 the Company expended approximately
$658 million for capital requirements.
In addition, the Company expended approximately
$67 million in 1983 for the early retirement of First Mortgage Bonds, 1196 Series, due*April 15, 1984.The Company's estimates of capital requirements for the three years 1984 through 1986, are set forth below.These estimates are subject to continuing review and adjustment.
1984 Estimated Capital Requirements (In Millions)1985 1986 Total Construction expenditures Nuclear fuel expenditures Less AFUDC (a)Net expenditures (b)Harris Units 2, 3, and 4 cancellation costs (c)Long-term debt and preferred stock retirement (d)Total$716 100 (112)704 46 2~752$571 68 (128)511 14 4$529$379 109 (52)436 14 5$455$1,666 277 (292)12651$1 736 (a)As prescribed in regulatory systems of accounts, an allowance for borrowed and other funds used to finance electric utility plant construction less applicable income taxes (AFUDC)is charged to the cost of plant (see Note 1(d)to Financial Statements in ITEM 8).(b)Reflects reductions of approximately
$80 million,$53 million and$41 million for 1984, 1985 and 1986, respectively, in net capital requirements resulting from Power Agency's projected payment of its proportionate share of capital expenditures related to the Mayo Plant, the Harris Plant, the Brunswick Plant and Roxboro Unit No.4 (see"Financing Program" and"Construction Program" below).(c)Reflects the Company's share of costs and charges expected to be incurred in connection with the cancellation of Harris Unit Nos.2, 3 and 4.(d)Excludes nuclear fuel continuous funding arrangements.
The above table reflects (i)the projected in-service date for Harris Unit No.1 in March 1986, and (ii)the projected inwervice date for Mayo Unit No.2 in March 1991.2)At the December 21, 1983 meeting of the Company's Board of Directors, the Board approved the immediate cancellation of Harris Unit No.2.The Company's share of the net cost for Harris Unit No.2 is expected to be approximately
$315 million,~including its investment to date, estimated cancellation costs and the payment to Power Agency discussed below.The Company will seek to amortize its costs over a ten-year period and recover those costs through rates.(See"Retail Rate Matters".)
The Board also approved a change in the scheduled in-service date of Mayo Unit No.2 from 1992 to 1991.
3)As a result of the cancellation of Harris Unit No.2, the Power Agency's ownership interest in the unit was reduced by 3.23%to 12.94%.In conjunction with the change in ownership interest, an amount was paid to Power Agency;this amount is included in the costs of cancellation set forth above in paragraph 1 of Construction Program.Power Agency's share of any costs of cancellation for Harris Unit No.2 is 12.94%.4)Approximately
$680 million reQecting the Company's share for construction of Harris Unit No.1 and Mayo Unit No.2 is included in the estimated 1984-1986 construction expenditures.
The estimated costs of these units reQect the projected in-service dates, estimated increases in the costs of labor, material and equipment, estimated AFUDC and the inclusion of all eligible Construction Work in Progress (CWIP)in the rate base in each jurisdiction for Harris Unit No.1.The continuation of all eligible CWIP in rate base for Harris Unit No.1 has been assumed in determining the level of capital requirements although the Company is unable to predict what level of CWIP, if any, will be included in rate base in the future.If CWIP were not included in rate base during the 1984-86 time period, the cost of Harris Unit No.1 would incr ease by a total of approximately 0216 million.5)The Company's current construction schedule for new generating units is as follows: Unit Design Target~Canacit Projected Tvee In-Service Date Estimated Cost (Millions)(a)
Harris No.1 Mayo No.2 900 MW V20 MW Nuclear Coal 1986 1991$2,546 VV8 (a)Includes costs expended to date, AFUDC and, with respect to Harris Unit No.1, inclusion of all eligible CWIP in rate base.Does not include (i)costs of land or (ii)reductions as a result of the sale of a 16.17%undivided ownership interest in these facilities to Power Agency.6)The Company's investment, including AFUDC and land costs, at December 31, 1983 for its 83.83%share of units under construction was (in thousands):
Harris Unit No.I..........................
M ayo Unit No.2..........................
T otal.................................
'1,438,723 13 166 61 451.6797)The current schedule for engineering, procurement, construction, and testing activities is intended to achieve commercial operation of Harris Unit No.1 in March 1986.Some of these engineering, procurement, construction, and testing activities are currently behind schedule.The Company believes the steps it is taking to accelerate activities in these areas should enable Harris Unit No.1 to begin commercial operation in March 1986.Should these steps be unsuccessful or should factors involving governmental, regulatory, design, procurement, construction, testing, and start-up uncertainties inherent in such major projects adversely affect the current schedule, it would be necessary to revise the scheduled commercial operation date and increase the estimated cost of Harris Unit No.l.8)Further changes in the above schedule and estimated construction expenditures may result from the Company's continuing review of its construction program, its financial position, its intensified conservation and load management program, general economic conditions, costs, projected load growth, licensing delays and other factors.9)The NCUC periodically holds hearings in which forecasts of future growth, the need for capacity additions for North Carolina and the reliability and safety of proposed plants are considered.
In December 1983, the NCUC issued its Order adopting an updated load forecast and plan for meeting long-range needs for electric generation facilities in North Carolina.The NCUC found that the Company's probable rate of growth in peak demand from 1982 through 1997 is in the range of 1.9%to 3.4%per year.The Company projects a 2.6%annual growth in peak demand for electricity through 1995.10)On November 3, 1983, the Conservation Council of North Carolina filed a complaint with the NCUC seeking revocation of the Certificate of Public Convenience and Necessity for the Harris Plant on the grounds that the plant is no longer needed.Although, based on the allegations and information in the Complaint, at this time the Company does not expect this proceeding to affect the construction schedule for Harris No.1, the Company cannot predict the outcome of this matter.Financin Pro am 1)The Company presently estimates that to meet capital requirements external funds of approximately
$550 million and$200 million in 1984 and 1985, respectively, will be needed from sales of long-term securities and from short-term borrowings.
Included in the above are approximately
$100 million and$90 million in 1984 and 1985, respectively, expected to be obtained from sales of common stock through its automatic dividend reinvestment plan, employee stock plans and customer stock ownership plan.The Company expects that it will have little or no external funds requirements in 1986.The remainder of the Company's capital requirements through 1986 are expected to come from internally generated funds.The Company may from time to time sell additional securities beyond what is needed to meet capital requirements.
The amounts and timing of the sales of securities will depend upon market conditions and the specific needs of the Company.2)The final Power Agency closing occurred on April 29, 1983 which increased to approximately
$639 million the total deposits made by Power Agency into a Trust in 1982 and 1983.The funds set aside in the Trust have been applied by the Trustee to purchase property for the Company.The total of payments for associated fuel inventories; fuel, construction and operating advances;and other costs billed pursuant to the agreements and paid at the closings directly to the Company totaled approximately
$34 million.The use of the funds in the Trust and Power Agency's contribution for ongoing construction reduced the Company's financing requirements by$299 million during 1983.Power Agency's contribution for ongoing construction and nuclear fuel is expected to reduce financing requirements by$174 million for the 1984-1986 period.
3)In January 1983, the Company filed a shelf registration statement with the Securities and Exchange Commission for$250 million in First Mortgage Bonds.In December 1983, the Company issued under such shelf registration
$100 million of First Mortgage Bonds, 12 7/8%Series, due December 1, 2013.The amounts and timing of further sales of bonds under the shelf registration will depend on market conditions and the specific needs of the Company.4)In March 1983, the Company participated in the issuance by the Industrial Facilities and Pollution Control Financing Authorities of Wake County and New Hanover County, North Carolina, of$48,485,000 and$5,970,000 principal amount, respectively, of Pollution Control Revenue Bonds, Adjustable Rate Option Bond Series 1983, due April 1, 2009.In connection therewith, the Company issued two series of its First Mortgage Bonds equal in principal amount to the respective issues of pollution control revenue bonds in order to provide funds sufficient to pay principal and interest on such pollution control revenue bonds.5)In December 1983, the Company participated in the issuance by Darlington County, South Carolina of$34,700,000 principal amount of Annual Tender Pollution Control Revenue Bonds, Series 1983, due November 1, 2010.In connection therewith, the Company issued a series of its First Mortgage Bonds equal in principal amount to and bearing interest at the same rate as the issue of pollution control revenue bonds in order to provide funds sufficient to pay principal and interest on such pollution control revenue bonds.6)See ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for further analysis and discussion of the Company's financing plans and capital resources and liquidity.
Retail Rate Matters 1)On February 21, 1984, the Company filed with the NCUC a request for a 12.6%increase in its retail rates (Docket No.E-2, Sub 481).The increase would provide an additional
$151.6 million in annual revenues based on the test year ending September 30, 1983.The requested rate of return on common equity is 16.5%based on a common equity ratio to total capitalization of 40.0%.The proposed overall rate of return is 12.52%.The request includes$29.5 million related to an increase to$695 million of CWIP in rate base for Harris Unit No.1 and$24.2 million to recover, by amortization over a 10-year period, the Company's investment in its cancelled Harris Unit No.2 which, as of December 31, 1983, was$263.7 million.The Company is unable to predict the outcome of this matter.2)On September 8, 1982, the Company filed a request (Docket No.82-328-E)with the SCPSC for a general rate increase of 19.96%which would increase retail rates by approximately'44.8 million annually.On September 28, 1983, the SCPSC issued its order granting a rate increase of$34.9 million, a 14.74%increase over existing tates, effective October 7, 1983.The SCPSC allowed the Company a rate of return on common equity of 14.50%after a penalty of.81%for plant operations.
The SCPSC also allowed the inclusion of$52.7 million of CWIP in rate base without an AFUDC offset.In a separate fuel adjustment proceeding; the SCPSC approved the same 1.725 cents per kwh fuel component as was previously in effect.
3)On February ll, 1983, the Company filed with the NCUC a request for a 14.93%increase in its retail rates (Docket No.E-2, Sub 461).The requested increase would have provided an additional
$164.9 million in annual revenues based on the test period ending September 30, 1982.On September 19, 1983, the NCUC issued its order granting a rate increase of$90.855 million, an 8.22%increase over existing rates.The NCUC allowed the Company a rate of return on common equity of 14.5%after a penalty of.75%for plant operations.
The NCUC also allowed the inclusion of$539.8 million of CWIP in rate base.The NCUC approved a base fuel component of 1.686 cents per kwh, an increase from the existing fuel component of 1.611 cents per kwh but below the requested fuel component of 1.818 cents per kwh.The Public Staff and the Attorney General of the State of North Carolina filed motions for reconsideration of the fuel component.
The Company filed a motion for reconsideration of the NCUC's requirement to credit to customers over a three-year period investment tax credits previously taken on property sold to Power Agency.On December 7, 1983 the NCUC issued its Order on the motions for reconsideration.
On reconsideration, the NCUC adopted the Company's position with respect to investment tax credits related to property sold to Power Agency that such credits be amortized back to the customer over the remaining life of the assets involved rather than over a three-year period.The NCUC did, however, order the Company to seek a ruling from the IRS so that the NCUC could determine the appropriate treatment in future rate cases.With respect to the fuel component, the NCUC reduced the original finding of 1.686 cents per kwh to 1.677 cents per kwh.The NCUC also required the Company to establish a deferred fuel expense account to accumulate any net overcollections of fuel costs.The NCUC will require the Company to refund to its customers any overcollections in the account in subsequent fuel proceedings and general rate cases.The NCUC did not provide for a true-up in the event of net undercollections of fuel costs.Because the revenue requirement impact of the two matters reconsidered essentially offset each other, the NCUC did not modify its original allowed rate incr ease of$90.8 million.4)There are currently pending before the NCUC two general rate proceedings (Docket Nos.E-2, Sub 391 and E-2, Sub 416)and three fuel clause proceedings (Docket Nos.E-2, Sub 402;E-2, Sub 411 and E-2, Sub 446)which have been remanded to the NCUC by the North Carolina Supreme Court and Court of Appeals.The remanded cases relate to NCUC orders issued between October 1980 and February 1982 which were appealed through the Courts by various parties to those proceedings.
In the fall of 1983, the Courts determined that the fuel clause statute, as it existed at the time of the proceedings in question, did not permit recovery of any portion of purchased power costs in a fuel clause proceeding and that the reasonableness and proper level of all fuel costs, including purchased power, should be reviewed in a general rate proceeding.
The NCUC was ordered to conduct a hearing in the nature of a general rate case to determine if rates during the periods covered by those proceedings were reasonable and proper and to adjust current rates as necessary to true-up any discrepancy.
The Company does not expect the remand to result in any material adjustment in rates.
0 5)Permanent retail rate increases since 1981 are as follows: Effective Date State Approximate Increase in Jurisdictional Revenues Granted Granted Re uested Annualized Increased Revenues Based On Test Year Level of Sales 5/1/81 12/15/81 6/1/82 9/24/82 9/19/83 b10/7/83 South Carolina North Carolina South Carolina North Carolina North Carolina South Carolina 11%13 14 al 8 15$27,500,000 151,432,000 40,341,000 173,700,000 164,913,000 44,040,000
$15,339,000 119,197,000 24,958,000 a8,784,000 90,855,000 34,900,000 Based upon rates in effect at the date of the order, rather than rates in effect at the date of the application.
bThe rates of return granted to the Company are as follows: North Carolina (test ear ended September 30, 1982)Ca ital Structure Ratio Cost Rate Weighted Cost Long-Term Debt Preferred Stock Common Equity Rate of Return 49.5%12.5 38.0 9.59%8.96 14.50 475 0 1.12 5.51 11.38%South Carolina (test ear ended December 31 1982)Ca ital Structure Long-Term Debt Preferred Stock Common Equity Rate of Return Ratio 47.63%13.04 39.33 Cost Rate 9.49%8.96 14.50 Weighted Cost 4.52%1.17 5.70 11.39%6)The average time lag between the filing of an application for a general rate increase and final commission action on such rate increase has been 7 months in North Carolina and 13 months in South Carolina.Legislation adopted in South Carolina in 1983 will reduce the time lag to approximately 6 months in that state.(See paragraph 9 below.)7)In June 1982, the North Carolina General Assembly revised the fuel clause procedure of the NCUC to require the NCUC to set base fuel costs in general rate cases and to authorize the NCUC to hold additional hearings no more frequently than once every 12 months to determine whether a rider should be added to base fuel rates to reQect increases or decreases in the cost of fuel and the fuel cost component of purchased power.The revision requires that any fuel adjustment which is allowed be based on fuel expenses prudently incurred under efficient management and economic operation.
Prior to the revision, rates were adjusted three times a year to reflect actual changes in the cost of fuel and purchased power.The NCUC held hearings in 1983 in a rulemaking proceeding (Docket No.E-100, Sub 4V)to establish rules to implement the new fuel adjustment statute.The NCUC has proposed rules for comment which would require, review of fuel costs at leastonce every 12 months but set forth no specific methodology for calculating those costs.The North Carolina General Assembly also directed the NCUC to determine the need for the fuel clause procedure and to report its findings in the next legislative session.The NCUC established Docket iVo.E-100, Sub 48, for the purpose of investigating the need and justification for electric utility fuel charge adjustments.
A hearing was held in February 1984.The Company cannot predict the outcome of these matters.8)In June 1982, the North Carolina General Assembly also revised the procedure with respect to CWIP to permit the inclusion of CWIP in the rate base only to the extent the NCUC considers the inclusion to be in the public interest and necessary to the financial stability of the the utility.The NCUC has instituted a separate generic rulemaking proceeding (Docket No.M-100, Sub 95)with respect to the CWIP issue.The Company is unable to predict the outcome of this proceeding.
9)In 1983, the South Carolina General Assembly adopted legislation affecting electric utilities operating in South Carolina, including the following provisions:
1)The existence of the SCPSC was reauthor ized for six years.2)The SCPSC was directed to rule on proposed rate changes by electric utilities within six months of the filing of the proposed changes.This period may be extended an additional five days upon a showing by the SCPSC that they are unable to issue the order within the prescribed time due to circumstances beyond their reasonable control.3)The electric utility may not place into effect proposed changes in rates until the rates have been approved by the SCPSC.Failure of the SCPSC to act within the prescribed time shall constitute approval of the proposed rate changes by the SCPSC.4)The electric utility may put propos'ed rate changes in effect under bond pending appeal of a rate order issued by the SCPSC.5)The electric utility must give not less than thirty days advance notice of its intention to file proposed changes in its rates.6)The electric utility may not request a rate increase within twelve months of a prior filing for a rate increase.7)The fuel clause procedure which had been in effect pursuant to SCPSC rule was enacted without substantive change.10)The Company is continuing its intensive conservation and load management programs designed to reduce the 1995 summer peak demand by 1750 MW.Several portions of such programs have been implemented.
The Company cunently offers time-of-day rates to all of its retail customers, financial incentives for utility control of water heaters and air conditioners to residential customers in certain metropolitan areas on the Company system, loans to its residential customers at 6 percent interest to install insulation and a rate discount to residential customers who have minimized heat loss from their homes.The Company is actively pursuing cogeneration with its industrial customers and has rates available for the purchase of power from customer-owned facilities, as well as stand-by service for customers using their generation equipment to reduce load.
Wholesale Rate Matters 1)In June 1977, the Company filed an application (Docket No.ERVV-485)with the FERC for authority to increase rates for wholesale customers to produce an estimated$26 million annual increase over rates subsequently agreed to in the then pending (Docket No.ER76-495)rate case.These rates were placed into effect on December 29, 1977, subject to refund with interest, and remained in effect until superseded by new rates.In December 1980, the Company filed a Settlement Agreement in this case, which allowed the Company to retain approximately
$15 million annually of the requested increase, and, in January 1981, refunds with interest thereon were made in the amount of approximately
$29.5 million.The Settlement:
Agreement was approved by the FERC;however, under the terms of this agreement, several issues were reserved for decision by the FERC, including tax normalization and adjustment for spent nuclear fuel storage and disposal costs.The tax normalization issue has been decided in favor of the Company.With respect to the fuel adjustment issue, the Company's wholesale customers filed a complaint with the FERC in September 1977, charging that the Company was improperly applying the fuel adjustment clause by including the cost of nuclear fuel storage and disposal in the adjustment.
These customers requested relief from imposition of the charges and a refund of such amounts collected under the clause by the Company.In November 1981, a FERC order was issued which decided the September 1977 complaint in favor of the Company's wholesale customers.
The order also decided one of the reser ved issues fr om Docket No.ER77-485 in favor of the Company's wholesale customers.
The Company's motion for rehearing was denied.In August, 1982, the Company refunded$15.3 million to-its wholesale customers as a result of this proceeding.
The Company filed a Petition for Review with the United States Court of Appeals for the District of Columbia Circuit.On August 26, 1983 the United States Court of Appeals for the District of Columbia Circuit rendered its decision that the FERC had not adequately stated the reasons for its ruling in light of the record and remanded the case back to the FERC for further analysis and consideration.
On March 7, 1984 FERC issued a remand order reversing its previous disallowance of spent nuclear fuel storage and disposal costs in the Company's rates.Since the 30-day time for appeal of the March 7, 1984 remand order has not expired, the Company cannot predict the outcome of this matter.However, since refunds have already been made in these dockets, any adverse determination of this issue is not expected to have a significant impact on the Company's overall financial condition or results of operations.
2)In February 1979, the Court of Appeals for the District of Columbia Circuit remanded to the FERC for reconsideration Order 530B which had authorized compr ehensive interperiod tax allocation (normalization) for wholesale ratemaking.
The case considered by the Court was the review of a rulemaking procedure rather than a specific rate case.On remand, the FERC approved a rule in February 1982 requiring normalization (Order No.144-A).That rule was appealed to the Court by a group of municipal and cooperative electric systems.In addition, certain wholesale customers of the Company appealed to the same Court the FERC's approval of tax normalization in connection with one of the Company's rate cases.On May 31, 1983, the United States Court of Appeals for the District of Columbia Circuit upheld the FERC rule requir ing tax normalization and the application of such rule in connection with one of the Company's wholesale rate cases.The United States Court of Appeals for the District of Columbia Circuit denied the Petition for Rehearing filed by a group of municipal and cooperative electrical systems on July 15, 1983.No party filed a timely appeal.3)During 1982 the FERC approved settlement agreements between the Company and its wholesale customers with respect to rate increase requests of$30.8 million and
$30.5 million filed in April 1980 (Docket No.ER80-344)and June 1981 (Docket No.ER81-538), respectively.
Pursuant to these settlement agreements the Company was granted rate increases of$23 million and$19.8 million, respectively.
Both settlement agreements left open the tax normalization and spent nuclear fuel adjustment issues.The tax normalization issue was decided in favor of the Company.On March 7, 1984 FERC issued a remand order reversing its previous disallowance of spent nuclear fuel storage and disposal costs in the Company's rates.Since the 30-day time for appeal of the March 7, 1984 remand order has not expired, the Company cannot predict the outcome of this matter.However, any adverse determination of this issue is not expected to have a significant impact on the Company's overall financial condition or results of operations.
4)On September 26, 1983, the Company filed an application (Docket No.ER83-765)with the FERC for authority to increase rates for wholesale customers by 14.5%to pro'duce an additional
$30.7 million annually.The increase is requested to become effective in two phases: Phase I-$19.0 million or 9.0%increase effective on November 26, 1983;and Phase II-$11.7 million or 5.5%increase effective November 27, 1983.The requested rate of return on common equity is 15.5%based on a common equity ratio to total capitalization of 39.94%.The proposed overall rate of return is 12.11%.The request proposes the inclusion of a total of$70 million of CWIP in the wholesale rate base.The FERC has authorized the Phase I por tion of the Company's proposed wholesale rate increase to be effective November 27, 1983, subject to refund.The FERC suspended the Phase II portion for five months to become effective on April 27, 1984, subject to refund.A hearing is scheduled to begin on June 11, 1984.The Company is unable to predict the outcome of this matter."12-Generatin Ca abiTitv 1)The Company's major installed generating facilities are shown in the table below: Plant Location Asheville (Skyland, N.C.)Net 1983 Maximum Station Fuel Cost(a)Unit Year Primary Dependable Generation(a)
(1983 Avg.Nc.Installed Peel~Ca acit MW H Mills/K WH)1 1S64 Coal 198 MW 2,377,595 17.62 2 1971 Coal 194 MW Cape Fear (Moncure, N.C.)H.F.Lee (Goldsboro, NC)5 1956 Coal 143 MW 6 1958 Coal 173 MW 1 1952 Coal V9 MW 2 1951 Coal V6 MW 3 1962 Coal 252 MW 1,046,342 1,488,115 18.53 19.46 H.B.Robinson 1 1960 Coal 174 MW (Hartsville, S.C.)2 1S71 Nuclear 665 MW 578,475 3,347,522 19.28 4.57 Roxboro (Roxboro, N.C.)L.Y.Sutton (Wilmington, N.C.)1 1966 Coal 385 MW 2 1968 Coal 670 MW 3 1973 Coal V07 M$U 4 1980 Coal 700 MW (b)1 1954 Coal 9V MW 2 1955 Coal 106 MW 3 1972 Coal 410 MW 13,233,756 (c)1,593,982 20.11 2).V9 Brunswick 1 19VV Nuclear 790 MW (b)4,426,995 (c)(Southport,¹C.)2 1975 Nuclear 790 MW (b)Mayo 1 1983 Coal V05 MW (b)3,111,583 (c)(Roxboro, N.C.)4.76 21.08 (a)Excluding internal combustion turbines and heat recovery units.(b)Facilities are jointly owned by the Company and Power Agency, and the capacity shown includes Power Agency's share.(c)Excludes 445,977 MWH for Roxboro Unit No.4, 600,521 MWH for Mayo Unit No.1 and 897,618 MWH for Brunswick Units representing Power Agency's share of Net Station Generation.
2)The remainder of the Company's capabiTity is composed of 53 smaller fossil, hydro and internal combustion turbine units ranging in size from a.5 MW hydro unit to a V8 MW coal-fired unit.In addition, the Company has short-term agreements for the temporarv purchase of power.See"Interconnections With Other Systems t 3)On August 17, 1973, the Company filed an application with the Federal Power Commission (now the Federal Energy Regulatory Commission) for new 50-year licenses for its Walters Hydroelectric Plant.North Carolina Electric Membership Corporation (NCEMC)filed a competing application on August 24, 1974.ElectriCities of North Carolina intervened in both proceedings.
On August 5, 1981, ElectriCities withdrew its interventions.
The Company and NCEMC on January 25, 1982, jointly requested FERC to hold the pending proceedings in abeyance until further notification from the applicants.
An order was entered by FERC on February 4, 1982, staying the proceedings until August 2, 1982.Since that time, orders further staying the proceedings through August 1, 1984 have been issued by FERC.The Company has continued to operate the Walters Hydroelectric Plant under licenses issued from year to year.4)The Company maintains all of its properties in good operating condition in accordance with sound management practices.
The average life expectancy for ratemaking and accounting purposes of the Company's generating facilities (excluding internal combustion turbine units)is 35 years for fossil units installed prior to 1966, 30 years for fossil units installed thereafter and 25 years for nuclear units.Of the total installed generating capability of 8,750 MW, 60%is coal, 26%is nuclear, 2%is hydro and 12%is fired by other fuels including No.2 oil, natural gas and pr opane.5)Total System generation (including Power Agency's share)by energy source for the years 1981 through 1984 is set forth below: 1981 1982 1983 1984*Coal Nuclear Hydro Other 69%29 1 1 75%23 2 72%25 2 1 80%17 2 1*Estimated Environmental Matters 1)To comply with state and federal environmental laws and regulations the Company has included in its construction program approximately
$103 million for Mayo Unit No.2 and approximately
$10 million for Harris Unit No.l.In addition, approximately
$38 miQion is estimated to be required during 1984 to 1986 for necessary modifications to comply with pollution control laws and regulations at the Company's existing facilities.
Those costs which are expected to be incurred during 1984 to)986 are included under"Construction Program." 2)Several proposals on acid deposition have been introduced in the United States Congress.Some of the proposals being considered could result in increasing costs for low sulfur coal and/or in a requirement to add costly sulfur dioxide remova)equipment to existing plants or plants under construction.
The Company cannot predict the outcome of this matter.3)Pursuant to regulations adopted by the United States Environmental Protection Agency (ZPA)under the Clean Air Act and by agencies of North Carolina and South Carolina under similar state statutory authority, fossil generating units are subject to stringent emission limitations and other requirements, primarily for the control of particulate matter and sulfur dioxide.These regulations are subject to periodic review and approval by the EPA.The EPA has also promulgated"Standards of Performance for New Stationary Sources" which establish specific emission limitations for particulates, sulfur dioxide and nitrogen oxides emitted from power plants on which construction commenced after August 1971 including the Mayo Units and, pursuant to the EPA's interpr etation of applicable regulations, Roxboro Unit No.4.Compliance with these new source standards of performance for sulfur dioxide of 1.2 Ibs/MBTU in North Carolina and South Carolina requires coal with an average sulfur content of approximately 0.7%at 12,000 BTU's per pound.The Company has the necessary coal contracts to meet these standards of performance for Roxboro Unit No.4 and the Mayo Units.Even more stringent limitations are applicable to fossil plants commencing construction subsequent to September 18, 1978.Compliance with the latter regulations will require the installation of sulfur dioxide removal equipment on future fossil plants and may requir e the installation of such equipment on Mayo Unit No.2, as well as compliance with more stringent NOx and particulate emission limitations due to changes in its projected in-service date.New power plants including Mayo Units 1 and 2 are also subject to stringent emission regulations relating to the prevention of significant deterioration (PSD)of air quality.If the PSD permit to construct Mayo Unit No.2 is at any time found to have expired due to changes in its in-service date, a new PSD permit would be requir ed which could require sulfur removal equipment as best available control technology.
The Company believes that its PSD permit is valid at the present time.However, if construction is deemed to have been suspended for more than 18 months, an extension pursuant to the PSD regulations may be required.The Company cannot predict the outcome of this matter.4)Emissions of particulate matter from fossil plants in North Carolina must meet two standards.
One standard controls visible emissions by limiting the opacity of emissions from the plant stack.The other standard limits the pounds of particulate matter actually emitted.In order to achieve compliance with particulate emission limitations by existing units, electrostatic precipitators have been installed at all of the Company's coal-fired units (except Cape Fear Units Nos.3 and 4 which are not currently utilized).
5)On January 13, 1983, the North Carolina Envir onmental Management Commission (EMC)adopted new particulate emission standards for fossil plants that (1)modified unit specific instantaneous maximum allowable mass emission rates for each existing generating unit and (2)introduced stringent additional annual emission limits on particulate matter emitted.The annual emission limits are expressed in tons of particulate matter and must be met on a rolling 365-day basis.The Company anticipates that it will be able to comply with the maximum allowable instantaneous emission limitations.
However, the Company has advised the Division of Environmental Management (DEM)that Roxboro Units Nos.1 and 3, Neatherspoon Unit No.3 and Cape Fear Unit No.6 would be unable to meet their plant specific annual emission limits at current emission levels.In the event the Company is unable to comply with the new limitations, it is uncertain what action, if any, the State may take.At its February 1984 meeting, the EMC temporarily deferred any enforcement action and the Company has executed a Special Order by Consent which 1)suspends the annual particulate emission limits for the units identified above until the EMC completes a full review of the regulation and 2)specifies schedules of tests and evaluations for these four units through December 1984 which will provide further information on precipitator performance.
The Order will be presented to the EMC for approval at its April 1984 meeting.The EMC has previously stated that it intends to review the new annual emission limitations after they"15-have been in effect for a period of time and additional data has been gathered on the ability of utility boilers to comply.Adjustments in the standards may be considered.
The annual limit may be made more stringent, and limitations may be imposed during start-up and shut-down periods now excluded from regulation.
The Company cannot predict what impact additional limitations would have on the Company but they could be significant.
The Company cannot predict the outcome of this matter.6)By notice dated December 21, 1983, EPA has proposed disapproval of that portion of the North Carolina State Implementation Plan (SIP)adopted on January 13, 1983 governing startups, shutdowns, and malfunctions of air emitting sources.If, following receipt of public comments, the EPA finally disapproves that portion of the SIP, the Company may be in technical violation of federal emission standards for particulates during startups and shutdowns.
Emission standards cannot be met by large utility boilers during startup and shutdown periods because electrostatic precipitators cannot be energized when the temperature of combustion gases is below dew point without adversely affecting precipitator performance.
7)The Company meets the current North Carolina sulfur dioxide emission limitation of 2.3 lbs/MBTU at its existing plants by burning coal with an average sulfur content of 1.4%or less at approximately 12,500 BTU's per pound.Environmental standards for sulfur dioxide of 3.5 lbs/MBTU in South Carolina can be met by burning coal with an average sulfur content of 2.1%or less at approximately 12,000 BTU's per pound.In the event the regulatory agencies having jurisdiction object to the Company's practice of using coal of differing quality to achieve overall compliance with sulfur dioxide emission limitations, the Company's fuel costs could increase substantially.
If the Company is unable to purchase coal of sufficient quality in the future to comply with sulfur dioxide emission limitations, significant additional costs could be incurred for instaQation of sulfur dioxide removal equipment.
8)The Pederal Clean Water Act prohibits the discharge of pollutants (including heat)except pursuant to the terms and conditions of National Pollutant Discharge Elimination System (NPDES)permits issued by the Administrator of the EPA or the Administrator of approved state programs.Timely permit applications were filed for all of the Company's generating plants and permits for all operating plants were ultimately issued.Although many of these permits expired in the first half of 1980, either renewal permits have been issued or the expired permits have been extended by the timely filing of renewal applications which stay the expiration of the permits.In July 1982 initial NPDES permits were issued for the Harris and Mayo Plants.The renewal NPDES permit for the Robinson Plant was issued and became effective on December 1, 1983.The Brunswick Plant has been issued a renewal NPDES permit.The Brunswick Plant renewal permit requires a reduction of plant intake of circulating water during certain periods of the year in lieu of the installation of cooling towers which were previously required.This reduction of circulating water flow reduces the heat removal capability of the condensers and thus will, during certain seasonal environmental conditions, limit the power level of each unit.Actual hourly power level reductions are estimated to range between 0%and 5%of full power, which could result in an average annual loss of approximately 2%of net capability.
At times when the Company's system demand reaches within 200 MW of available generating
'resources, flow restrictions can be suspended allowing full power operation.
9)Except as noted herein, the Company does not anticipate additional significant costs for compliance with environmental laws and regulations, although additional costs
could be incurred as a result of changes in or more stringent enforcement of existing federal and state laws and regulations or in the event it is found that modifications now planned to meet the requirements of environmental laws and regulations fail to provide the anticipated degree of control.Nuclear Matters 1)The electric utility industry in general has been experiencing problems in a number of areas relating to the construction and operation of nuclear plants including the effects of inQation upon the cost of operations and upon construction costs;increased costs and licensing delays related to compliance with changing regulatory requirements; efforts to delay or prevent construction of nuclear generating and related facilities and to preclude or limit the use of existing facilities; uncertainties regarding the availability of reprocessing and storage facilities for spent nuclear fuel;and substantially increased capital outlays and longer construction periods required for larger, more complex generating facilities.
The Company is currently experiencing these problems in varying.degrees.oi 2)In connection with information resulting from the incident at the Three Mile Island Unit No.2 located near Harrisburg, Pennsylvania, the Company has implemented and continues to implement changes to systems and procedures at its nuclear plants.The NRC has issued many post-Three Mile Island safety requirements.
The scheduled completion dates for many of the early requirements were extended by the NRC beyond 1981 because of problems in procuring adequate equipment and NRC revision of some of the requirements.
Implementation schedules for certain of the new NRC requirements, which deal with the habitability of control rooms during radioactive or toxic chemical releases, increased requirements for emergency response facilities and data systems, training program improvements and design reviews of nuclear plant control rooms, now extend beyond 1984 and have been included in the estimated construction expenditures under"Construction Program"..3)The Company's Robinson Unit No.2, a pressurized'ater reactor, has experienced deterioration of steam generator tubes as have other similar units.The deterioration has resulted in leaks which have required outages for inspection and plugging of tubes.The Company had planned to replace the Robinson steam generators in 1984 and 1985.Robinson Unit No.2 was removed from service on January 26, 1984 due to steam generator tube leaks.Inspections and tests indicated that tube corrosion had reached the point where continued operation of the unit prior to replacement of the steam generators was not feasible.The steam generator replacement outage for Robinson Unit No.2 began on February 6, 1984.The unit is currently expected to be out of service until January 1985.The NRC has issued a license amendment authorizing the replacement.
Capital expenditures during 1984 and 1985 for the replacement of the steam generators and associated equipment are estimated to be approximately
$93 million (including AFUDC), which has been included in the Company's estimated 1984-1986 construction expenditures.
The total cost of the replacement is estimated to be appr oximately$134 million.4)Although the Harris Unit under construction is also a pressurized water reactor, it is of a later design and the Company intends to incorporate improvements in the design of the steam generators.
These improvements will reduce the likelihood that the problem experienced at Robinson Unit No.2 will occur at the Harris Plant.Steam generators similar to those to be used in the Harris Plant have, however, experienced vibration problems which are currently being studied by the vendor.Modifications intended to minimize these problems have been made to the Harris steam generators.
5)The NRC has asked the Company and other utilities which own pressurized water reactors, such as the Company's Robinson Unit No.2, for information on the ability of the reactor pressure vessels to withstand the effects of thermal shock.Thermal shock is a condition which results from the introduction of cold water into a hot pressurized reactor vessel.If the fracture toughness of the vessel has been reduced sufficiently by extensive irradiation, cracking could result from thermal shock.The NRC believes that older reactor pressure vessels can withstand thermal shock at the present time, but believes that continued operation at full power could reduce the vessel toughness to unacceptable levels before retirement of these plants.The Company's analysis indicated that the Robinson Unit will approach the NRC screening criteria around 1993 based upon the Company's current outage schedule.In December 1983, the NRC advised the Company that it concurred with the analysis that the Robinson Unit No.2 would not reach the NRC screening criteria prior to 1993.Plant specific analysis was also undertaken by the Company to determine if the unit can exceed or avoid reaching the NRC screening criteria without plant modifications and to define the nature of any modifications that may be required prior to the end of the operating life of the Unit to avoid the risk of reactor pressure vessel cracking from thermal shock.The results of plant specific analyses indicate that with planned fuel modifications the unit can operate to the expiration of the operating license (2007)without reaching the NRC screening criteria.The Company presented the results of the plant specific analysis in a report to the NRC in 1983 and requested NRC concurrence with the report.The NRC is in the process of reviewing the Company's report.The Company cannot predict the outcome of this matter.The Company is also participating in separate plant specific research programs on the effects of thermal shock sponsored by the NRC and the Electric Power Resear ch Institute.
6)Westinghouse units similar to Robinson Unit No.2 have experienced stress corrosion cracks in low-pressure turbine disks.In 1978, four disks at Robinson Unit No.2 were found to have stress corrosion cracks and were replaced.The Company performed an inspection of all remaining Robinson Unit No.2 low-pressure disks in 1980 and no cracks were found.The Company will monitor the turbine in the future for any recurrence of the cracking problem.A turbine missile analysis was performed for Robinson Unit No.2 when the plant was licensed and is summarized in the Final Safety Analysis Report for the Unit.Findings by the turbine manufacturer indicate that the initial missile analysis on this Unit did not account for stress corrosion cracking and the nonsymmetrical impact of disk fragments that could change the analysis results.The Company is awaiting NRC approval of the turbine manufacturer's analysis methodology before proceeding with further evaluations.
7)An NRC order authorizing an increase in power from 2200 to 2300 MW(t)at Robinson Unit No.2, which found the unit acceptable environmentally, is subject to review regarding radon releases.The Company is unable to predict what effect, if any, this matter may have on the operation of Robinson Unit No.2.8)General Electric Company has informed the Company that stress corrosion cracks in low-pressure turbine disks have been found in three General Electric turbines similar to the Brunswick Units Nos.1 and 2 turbines.Inspection of the Brunswick Unit No.2 turbine was completed in June 1982, in conjunction with the scheduled maintenance outage.The inspection of the Brunswick Unit No.1 turbine was completed in March 1983 during a scheduled refueling and maintenance ou ag.p'e.No re airs were required as a'ks h uld result of these inspections; however, the inspection results indicate te that the disks s o be monitored by future inspections.
9)The Company has been required by the NRC to modify the augmented off-gas B k Plant.The system provides a reduction in releases of e au mented off as iadioactive gases to the environment.
The modifications to the augmen e-g B'U't No 1 were completed during the scheduled refueling and uta e which ended in August 1983.In December 1983, the NRC gran e the Company's request to defer the final modifications to the aug maintenance outage w ic en e~~~au mented off as system g at Brunswick Unit No.2 until the spring of 1984.The Company plans to make these final modifications to Brunswick Unit No.2 during the scheduled maintenance outage which began in March 1984.10)The Company is in the process of replacing the condenser tubes in the Brunswick Units to reduce the potential for tube leaks which interfere with the chemistry limits in the primary system.Replacement of the condenser tubes on Brunswick Unit No.1 was completed in the spring of 1983.Replacement of the Brunswick Unit No.2 condenser tubes is currently planned during the scheduled maintenance outage which began in March 1984.b 2 1981 the NRC published final regulations establishing interim ll)On Decem er,, e 1 nts ursuant to requiremen re a e o ts 1 ted to hydrogen contio)at operating nuclear power plants p h'the Company is required to make certain modifications to the Brunswick Units.The Company has sought review of the regulations y e wic e o b the United States Court of Appeals for the Fourth Circuit.Pursuant to the Company's request for exemption, the i granted the Company relief to June 1984 from the schedule provisions of the interim ts The Company has filed with the NRC a request for exemption from the requiremen
.e technical requirements of the regulations.
The Company cannot p ot redict the outcome of these proceedings.
12 y, e)In Jul 1982 the Company committed to the NRC to'investigate and review its technical specification surveillance requirements at the Bruns management control systems applicable thereto.The administrative procedures for the Brunswick Plant requ re y i i d b its pre-startup commitments to the NRC and surveiQance re corn leted requiremen an req i ts d uiied valve testing of containment isolation valves were comp e to the NRC b 1982 Th Company has also made post-startup commitments to th with respect to long-term corrective actions which it will undertake to assur y e timel compliance with technical specification surveillance requirements.
)1982 the NRC notified the Company that the large diameter reactor recirculation system piping in boiling water reactor units such as the Brunswick n U its has the potential to crack as a result of intergranular stress corrosion and required an t'f such piping at boiling water reactoi'nits undergoing a iefueling swick Unit No.l.or extended outage prior to January 31, 1983, which included Brunswic ni i o.d Brunswick Unit No.1 during the spring of 1983.Additional ober 1983 recirculation piping inspec't'nspections wete performed on Brunswick Unit No.1 in Octo er durin~a scheduled outage.wo o d t Two of the six welds inspected were found to have indications of cracking and were repaire.d The NRC has required that an evaluation be pei foi med to assess the adequacy of the recirculation piping weld inspections performed on Brunswick 1 1983'ight of the subsequent upgrade in inspection qualification requirements.
Por ions o p t f the Brunswick Unit No.2 piping were inspected in February 1983, and no cracks were found.In November 1983, inspections were conducted on Brunswick Unit No.2's recirculation piping welds.The results of the inspection showed nineteen welds with indications of cracking.The Company elected to repair eight welds.It was determined that the indications of ci'acking in the iemaining eleven welds were minor and that repair could be safely deferred until the scheduled maintenance outage currently in progress.In December 1983, the NRC approved the Company's actions with regard to the nineteen welds.The NRC issued an order allowing Brunswick Unit No.2 to return to full power operations.
The Company has committed to perform~additional inspections of limited scope on Brunswick Unit No.2 during the 1984 refueling outage and on Brunswick Unit No.1 in November 1984.The NRC has neithei'ccepted t d the e plans at this time.Based on recent industry experience with respect to stress corrosion cracking in recirculation piping and the NRC position a we overlay repairs are acceptable only for the short-term, the Company has purchased replacement piping for one unit and initiated other preparations to per form the replacement.
The extent to which piping may require replacement will depend upon future inspection results.Full recirculation system replacement, if required, could require approximately nine months of outage time per unit and is expected to cost approx>ma e y mi t 1$36 llion per unit.(See also"Nuclear Matters", paragraph 16 below for discussion of outage schedule.)
The Company cannot predict the outcome o f these matters.14)The Company has pending before the NRC petitions for exemptions for the B k Pl nt and Robinson Unit No.2 from certain of the requirements of the NRC's fire protection regulations.
With respect to the Brunswick Plant, in u y runswic an an Jul 1983 the ilRC d certain of the exemptions which the Company had requested and denied the grante cer ain o e remaining requests.With the NRC's concurrence, the Company is n w p n is now erformin~an ana ysis o eve op 1'd clop alternative measures to those originally proposed which the Company v ex ects to can take in order to meet the requirements of the regulations.
The Company expec submit the results of its analysis in May 1984 for NRC review and approval.With respect to Robinson Unit No.2, in November 1983, the NRC granted certain of the exemptions the Company had requested.
Two of the Company's exemption iequests with respect to Robinson Unit No.2 are still pending.15)In June 1981, the Company petitioned for hearings on NRC orders which required upgrading the environmental qualification of electrical equipment in the Company's nuclear units by June 30, 1982.The NRC suspended the June 30, 1982 deadline pending promulgation of regulations.
The suspension of the June 30, 1982 deadline was challenged in the United States Court of Appeals for the District of Columbia Circuit, and the Company intervened in that proceeding.
In January 1983, the NRC promulgated regulations pursuant to which the deadline for each unit was change to the end of the second refueling outage after March 31, 1982 or by March 31, 1985, whichevei is earlier.Petitions for review of these regulations have been filed in the Court of Appeals for the District of Columbia Circuit.As a result of the promulgation by the NRC of regulations changing the deadline, the Company withdrew its June 1981 petition.The Court of Appeals for the District of Columbia Circuit has remanded on procedural grounds to the NRC the NRC's regulation suspending the June 30, 1982 deadline for equipment qualification which the NRC issued pending promulgation of the final rule.In March 1984, in response to the Court's decision, the NRC issued for public comment a new proposed rule by which it would suspend the June 30, 1982 deadline.The C lans to complete equipment qualification modifications on Brunswick Unit No.1 during an outage cuirently scheduled to begin in the spring o ompany p ans o c of 1985.Based on the current regulatory requirements, completion of equipment qualification modifications is required during the Brunswick Unit No.2 scheduled outage which began in March 1984.The Company plans to seek regulatory relief to extend the completion date for Brunswick Unit No.2 t'o November 1985 as a minimum, and possibly to the spring of 1986.Requests for deferral to the spring of 1986 would be based on coordinating equipment qualification work with recirculation pipe replacement.
If regulatory relief is not granted, Brunswick Unit No.2 would be delayed in returning to service from the March 1984 outage.In addition, if regulatory relief to extend the completion to the spring of 1986 is requested and not granted, an earlier than currently planned outage would be required for Brunswick Unit No.2.The Company cannot predict the outcome of the request for schedule relief.16)The Company's nuclear units will be periodically removed from service to accommodate certain major modifications, normal refueling and maintenance and other activities.
Currently, Brunswick Unit No.1 is scheduled for eleven weeks of outage time in 1984 for maintenance, tests, and recirculation piping inspections, and an outage of approximately 46 weeks duration, beginning in the spring of 1985 for refueling, modifications r elated to the environmental qualification of electrical equipment, maintenance, and replacement of the recirculation piping, if required.No additional outages are currently planned for Brunswick Unit No.1 in 1986.In March 1984, Brunswick Unit No.2 began a scheduled outage of approximately 36 weeks for condenser tube replacement, replacement of the augmented off~as system, refueling, and other maintenance activities.
Currently, no outage is scheduled for Brunswick Unit No.2 in 1985.Brunswick Unit No.2 is scheduled for an outage of approximately 46 weeks, beginning in the spring of 1986, for refueling, modifications related to the environmental qualification of electrical equipment, maintenance, and replacement of the recir culation piping, if required.If the NRC does not grant the Company's request for schedule relief for completing equipment qualification work beyond November 1985, it may be necessary to schedule an outage for Brunswick Unit No.2 in 1985.Robinson Unit No.2 is currently out of service for steam generator replacement, refueling, and other maintenance and modifications.
The unit is currently expected to be out of service until January 1985.Robinson Unit No.2 is scheduled for a refueling and maintenance outage of approximately 15 weeks in early 1986.Capital expenditures for modifications at the nuclear units during the 1984-1986 period including replacement of the Robinson Unit No.2 steam generator and including replacement of the Brunswick Plant recirculation piping, if required, are expected to total approximately
$403 million (including AFUDC).These scheduled outages, including estimated costs, outage durations and activities planned, are based upon the NRC granting the Company's planned request for relief from the current regulatory schedule for modifications related to the environmental qualification of electrical equipment at the Brunswick Plant and are subject to continuing review and revision due to additional or revised regulatory requirements or other changing conditions or circumstances.
The nuclear units may also experience unscheduled outages from time to time due to circumstances or conditions the Company is unable to predict at this time.If additional regulatory requirements are imposed or the NRC does not concur in the Company's proposed modifications or scheduling of such proposed modifications, the schedule may be changed and/or required outage time and estimated expenditures may be increased.
17)In January 1978, a construction permit was issued by the NRC for the construction of the Harris Plant.The construction permit is subject to further review by the Atomic Safety and Licensing Appeal Board (ASLAB)in conjunction with an industry-wide review of the environmental effects of radon releases associated with the nuclear fuel cycle.The Company filed with the NRC an amended application for operating
licenses for Harris Units Nos.1 and 2.Due to the cancellation of Harris Unit No.2, however, the Company plans to file in early 1984 an amended application for an operating license for Harris Unit No.1 only.Interventions in the operating license proceeding have been allowed and the case is being vigorously contested.
The hearing will be conducted in phases with environmental and security issues scheduled to be heard in June 1984;management.
capability and safety issues in September and October 1984;and emergency planning issues in February 1985.At present approximately twenty-one issues are scheduled to be litigated in these hearings.The Company expects that the intervenors will seek to litigate numerous emergency planning issues and that they will raise other issues during the course of the proceeding.
The NRC Staff has issued a Final Environmental Statement (FES)on the environmental considerations associated with the application for an operating license for the Harris Plant.In the FES, the NRC staff concluded that, from the standpoint of environmental effects and subject to certain ongoing environmental monitoring requirements once the Plant becomes operational, the operating license should be issued.The FES represents conclusions based on environmental matters only and does not constitute the final licensing action.The NRC Staff has issued its Safety Evaluation Report (SER)for the Harris Plant.The SER identified a number of issues which have to be reviewed or resolved.The NRC Staff has determined that upon favorable resolution of these issues, it will be able to conclude that the Harris Plant can be operated by the Company without endangering the health and safety of the public.The Advisory Committee on Reactor Safeguards (ACRS)sent a letter in January 1984 to the NRC stating that the ACRS found no reason to believe that the issues identified in the SER will be especially difficult to resolve.The ACRS further stated that, if due regard is given to the items mentioned in the letter, and subject to satisfactory completion of construction,.staffing and preoperational testing, there is reasonable assurance that the Harris Plant can be operated at full power without undue risk to the health and safety of the public.The Company is unable to predict the outcome of these licensing pr oceedings.
18)In October 1983, the NRC issued notification to the Atomic Safety and Licensing Boards reviewing applications for operating licenses at a number of plants, including the Company's Harris Plant, of problems with emergency diesel generators manufactured by Transamerican Delaval (TDI)and proposed for use at such plants.TDI diesel generators have experienced a number of equipment failures at several nuclear sites which have made the reliability of these diesel generators suspect.The Company is working with a number of other utilities in attempting to resolve the problems associated with these diesel generators.
If these problems are not resolved in a timely manner, the scheduled in-service date of Harris Unit No.1 could be adversely affected.The Company cannot predict the outcome of this matter.The emergency diesel generators for the Company's Brunswick Units and Robinson Unit No.2 are manufactured by companies other than TDI.19)In January 1983, the President signed into law the Nuclear Waste Policy Act which provides the framework for development by the federal government of interim storage and permanent disposal facilities for radioactive waste materials.
The Act promotes increased usage of interim storage at existing nuclear plants.The Company will continue to maximize the usage of spent fuel storage capability within its own facilities-for as long as feasible.Assuming normal operating and refueling schedules, sufficient space is currently available to operate the Brunswick Units through 1984 and Robinson Unit No.2 through 1987 with full core discharge capability.
The Company is in the process of increasing the spent fuel storage capacity at these plants.The modification to the Robinson Unit No.2 spent fuel storage facilities was completed in November 1983.In December 1983, the NRC approved the Company's request to increase the spent fuel storage capacity at the Brunswick Plant.The Brunswick Plant modifications are scheduled to be completed in 1985.Such modifications will permit operations until the early 1990s.By the time additional storage is required, the Harris Plant spent fuel storage facilities are expected to be licensed and may provide storage space for spent fuel generated on the Company system through the 1990's.As required by the Act, the Company entered into a contract with the Department of Energy (DOE)for disposal of spent nuclear fuel.The contract includes a provision requiring the Company to make payments to the DOE for disposal costs.The Company's liability for disposal of nuclear fuel wastes attributable to generation through April 6, 1983 is$97.7 million, of which Power Agency's share is approximately
$9.7 million.As of December 31, 1983 the Company had coQected through customer rates and included in a reserve for disposal of nuclear fuel approximately
$58.7 million of its$88 million net obligations.
Pursuant to the regulations, the Company has until June of 1985 to select among the several different payment options.Disposal costs incurred after April 6, 1983 are based upon actual nuclear generation and are paid on a quarterly basis.These costs are expected to be approximately
$10 million annually based on the present level of operations and the present disposal fee per KNH of nuclear generation.(Disposal fees may be reviewed annually by the DOE and adjusted, if necessary.)
The Company's disposal costs are'xpected to increase when Harris Unit No.1 becomes operational.
Because of contingencies in the Act, the Company cannot predict at this time whether the federal government will be able to provide interim storage or permanent disposal repositories for spent fuel and/or high level radioactive waste materials.
20)On March 13, 1984, the NRC Staff proposed a$30,000 civil penalty against the Company for alleged violation of NRC requirements at the Robinson Plant.The penalty was proposed for alleged failure of a Company employee and a contractor employee to follow certain technical specifications requirements and radiological and administrative controls upon entering a high radiation area.The alleged violation could have-but did not-result in a worker being exposed to radiation in excess of permissible limits.The NRC Staff reduced the amount of the proposed fine by 25%to$30,000 because of the Company's prompt reporting and investigation of the event and its decisive action to prevent a recurrence.
The Company has 30 days from the date of the notice in which to respond.21)The Company may incur increased construction and operating expenditures as a result of the foregoing matters and, during periods when any of the Company's nuclear units are shut down, system power resources could become inadequate.
Fossil Fuel Suo 1 1)The Company has intermediate and long-term agreements from which it expects to receive approximately 77%of its coal requirements in 1984.Over the next ten years, the Company expects to receive approximately 73%of its coal requirements from intermediate and long-term agreements.
These agreements have expiration dates ranging from 1984 to 2006.During 1982 and 1983, the Company obtained approximately 98%(9,400,000 tons)and 88%(9,024,000 tons), respectively, of its coal requirements from intermediate and long-term agreements.
The Company purchased approximately 629,000 tons of coal in the spot market during 1982 and 958,000 tons during 1983.The Company's contract coal purchase prices during 1983 ranged from approximately
$30.20 to$46.15 per ton (F.O.B.mine).During 1983, the Company's spot market purchase prices ranged from approximately.$
18.51 to$24.92 per ton (F.O.B.mine).
2)The average cost to the Company of coal burned for the years shown is as follows: Year 8/ton 5'Million BTU 1979 1980 1981 1982 1983 33.64 38.75 42.55 47.22 47.89 138 157 173 192 192 3)During 1983, the Company maintained from 69 to 94 days supply of coal, based on anticipated burn rate.4)In 1974, the Company entered into agreements with Pickands Mather R Company (PM), a firm engaged in owning, operating and managing mineral properties, to develop two adjacent deep coal mines in Pike County, Kentucky, with an aggregate capacity of two million tons of coal per year.Studies made on behalf of the Company and PM in 19?4 and 1975 by Paul Weir Company Incorporated, Chicago, Illinois, independent mining consultants, estimated that the property contained not less than 43.6 million tons of mineable and recoverable coal with an average of 12,800 BTU's per pound and an average sulfur content of 0.58%.The Company and PM formed Leslie Coal Mining Company (Leslie)and McInnes Coal Mining Company (Mcinnes), both 80%owned subsidiaries of the Company, to develop the two mines.The Company entered into coal pur chase contracts with each subsidiary for 80Fo of the production until the economically mineable coal reserves are exhausted.
PM contracted to receive the remaining 20%of production.
In 1983, the Company charged$49.9 million to other operation expense for possible losses on its investment in the mines.On November 29, 1983, the Company acquired the 20 percent interests of PM in Leslie and McInnes.Operations at the mines have been suspended since February 1983 because of reduced demand for coal in the utility and industrial markets.At the present time, the Company is pursuing a course of~action to sell the mines.5)Fossil fuels, including natural gas, oil and coal, have been, or are purported to be, subject to allocation by the Department of Energy under various federal laws and executive orders.Although supplies to date have been adequate, such an allocation program could affect the ability of the Company to satisfy its requirements for oil and gas used as fuel in internal combustion turbine units, oil used as fuel for startup, regulation and testing of coal-fired units and for coal and oil used as boiler fuel.6)The Company uses No.2 oil primarily for its internal combustion turbine units for emergency backup and peaking purposes.The Company burned approximately
9.9 million
and 13.5 million gallons of No.2 oil during 1982 and 1983, respectively.
The Company has fuel oil supply contracts for its normal requirements.
In the event base-load capacity is unavailable during periods of high demand, the Company may increase the use of its internal combustion turbine units, thereby increasing oil consumption.
The Company intends to meet any additional requirements for fuel oil through additional contract purchases or purchases in the spot market.There can be no assurance that adequate supplies of oil will be available to meet the Company's requirements.
To reduce the Companys vulnerability to dislocations in the oil market, seven internal combustion turbine units with a generating capacity of 364 MW have been converted to burn either propane or No.2 oil.In addition, twelve internal combustion turbine units with a generating capacity of 425 MW can burn natural gas when available.
Over the last-24" five years, No.2 oil accounted for 3.1%of the Company's total fuel cost.In 1983, No.2 oil accounted for 2.1%of total fuel costs.7)The availability and cost of fossil fuel could be adversely affected by energy legislation enacted by Congress, coal allocation, the failure of coal production to meet demand, labor unrest, and the production, pricing and embargo policies of foreign countries.
Nuclear Fuel Su 1 1)The nuclear fuel cycle requires the mining and milling of uranium ore to provide uranium concentrate (U308), the conversion of U308 to uranium hexafluoride (UFg), enrichment of the UF6 and fabrication of the enriched uranium into fuel assemblies.
The Company has on hand or has contracted for raw materials and services for Robinson Unit No.2 and the Brunswick and Harris Units through the years shown below: Unit Estimated in-service Date Raw Materials and Services Uranium Conversion Enrichment Fabrication Robinson No.2 Brunswick No.1 Brunswick No.2 Harris No.1 1986 1990 1989 1990 1990 1987 1987 1987 1987 2002 2002 2002 2002 1989 1993 1988 1986*In commercial operation.
2)These contracts are expected to supply the necessary nuclear fuel to operate Robinson Unit No.2 through 1988, Brunswick Unit No.1 through 1988, Brunswick Unit No.2 through'1988 and Harris Unit No.1 through 1987.The Company expects to meet its U308 requirements through the years shown above from inventory on hand and amounts received under contract.Additional supplies of U308 are currently available in the uranium spot market.The Company does not expect to have difficulty obtaining U308 and the services necessary for its conversion, enrichment and fabrication into nuclear fuel for years later than those shown above.3)For a discussion of the Company's plans with respect to spent fuel storage, see"Nuclear Matters".Interconnections With Other S stems 1)The Company's facilities in Asheville and vicinity are integrated into the total system through the facilities of Duke Power Company (Duke)via interconnection agreements that permit transfer of power to and from the Asheville area.The Company also has interconnections with the Tennessee Valley Authority (TVA), Virginia Electric and Power Company (VEPCO), South Carolina Electric and Gas Company (SCERG), South Carolina Public Sevice Authority (SCPSA)and Yadkin, Inc.Major interconnections include 230 kV ties with SCERG and SCPSA and both 230 kV and 500 kV ties with Duke and VEPCO.2)The Company has interchange agreements with Appalachian Power Company (APCO), Duke, SCPSA, SCERG, TVA and VEPCO which provide for the purchase of power for daily, weekly, monthly or longer periods.Purchases under these agreements may be made due to changes in the in-service dates of new generating units, outages at existing units, or for other reasons.3)The Company has also reached an agreement with the City of Fayetteville, North Carolina to supply partial requirements service and standby service in case of emergency outage of the City's eight 20 MN internal combustion turbine units, of which f'eing used by the City for peak shaving purposes.The agreement also makes ive are capacity from these units available to the Company, subject to certam condi i ns,'t'o when they are not being operated to meet the City's peak shaving requirements.
4)The Virginia-Carolinas Subregion of the Southeastern Electric Reliability C il is made up of the Company, Duke, SCERG, SCPSA and VEPCO plus the Southeastern Power Administration and Yadkin, Inc.Contractual arrangements am amon~the members in the activities of area, regional and national electric reliability organizations, including the Southeastern Electric Reliability Council and the North American Electric Reliability Council, promotes electric service reliability.
Com etition and Franchises Generally, in municipalities and other areas where the Company provides electric service, no other utility renders such service.The Company is a regulated public utility.The Company holds all necessary franchises to operate in the municipalities and other areas it serves.Other Matters 1)In August 1977, North Carolina Electric Membership Corporation (NCEMC)and 16 of its 18 members who receive wholesale service from the Company filed an antitrust action, in the United States District Court in Greensboro, North Carolina, seeking damages of not less than$50.4 million, before trebling, and injunctive relief requir ing the Company to provide wheeling services to NCEMC and to deal with NCEMC in respect of certain other power services.The Company has denied the charges contained in the NCEMC's complaint.
In the opinion of General Counsel of the Company, the contentions of NCEMC and its members in this litigation are without merit, and the Company should ultimately prevail.In March 1982, a two-year stay order was entered in this proceeding.
The Company and NCEMC have begun negotiations for a possible purchase of a portion of the Company's electric generating capacity by NCEMC.If a sale is concluded, the complaint in this proceeding will be dismissed with prejudice.
By consent order, the stay has been extended to June 2, 1984.The Company cannot predict the outcome of this matter.
Operating Statistics 1983 Year Ended December 31.1982 1981 1980 1979 Electric energy suooly (miiUioas of kilowatt-hours) 5 (miUions of kilowatt-hours) 5 Generated-aet stat(on outputs Stcam Eosdl.Stcam nudcar.6~Hydro.Internal combustion rutbincs..............
Total gencrared.
Purchased aad nct interchange..............
Total cncrgy supplr (Company sharc)......
Power Agency's ownership share............
Total combined system energy supPI......
hvcragc Eossil fud cost per mdlion ILTII (cents)..~.~Arcrage nuckar fuel cost per million STU (cease)~.~Average coul fuel cost (fossil and nudeat)pcr miUion STLI (cents).Hectric energy saks (miUions oE kilowatt-hours jt Rcsidcntial.
Commercial Induserid.
Govemtnent and municipal................
Total general business.................
Sdca for resale: Standard race schedules Power Agency participants..............
Other Power Agency contract re51ulremcnts
........Total electric energy sales..............
Com p any uses.)oases and unaccounted Eot....~...Total energy supply (Company hare)......
Number of cunomcrs(accounts as oE cad of period): Rcsidcntial.
Commercial Industrid.
Government and municipd....,~~.~~~~~~~~Total gcacral business.............
~~~~Resdc.Total customers~~~~23,799 7.775 816 35 32,425 357 3" 75" 1.529 23.079 6.876 735 23 30.113 1.119 31.332 361 196.2 42.L 194.8 35.8 156.1 L55.4 8.010 5,546 LOJLO 768 24.S34 7.647 5.341 9,520 753 23 261 4.455 1.896 30.885 1.897 3'52 1.129 4.253 1.840 30.483 1.349 31.832 680.581 110 J41 4,046 919 795.887 33 795.920 660.850 106.287 4.010 847 171.994 33 772.027 3>.311 32.193 22.372 9 J44 437 117 32.270 80 32.350 22.299 8,955 680 224 32.158 25 32.183 178.5 37.2 163.0 35.7 135.1 124.9 7,746 5.072 9,968 823 23.609 7.870 4.935 9.791 864 23.460'9 C93 4.285 X56I 4.261 30,487 1.863 32.350 30.282 1.901 3r 183 647.491 632.209 104.9 L9 103.994 3.942 3.794 1.111 1.581 757.469 741.578 55.55 757.524 74 1,633 18.336 10.802 1,019 146 30,303 (3)30JOO 141.8 35.4 100.8 7.195 4.590 9.609 917 2XSLL 2.363 3.994 28.668 1.632 30.300 617.393 102.198 3.625 1.>47 724.963 54 125.011 Operating revenues (ia mUlions)5 Rcsidcntial.
Commercial Industrid.
Governrncnt aad municipal.........
~.~~~~~Total general business......
~~~~~~.~~~~Sdes for resale Toed from energy sdcs.~~~.~~~~~~~~~~~Miscellaneous
.Toed operating revenues..
~~~~~.~~~~~~~Peak demand of Urm load (thousaads of kilowatts) t Total combined system.....
~~.~~~~~~~~~~~Less Power Agency portion Company coca!peak demand............
Less sales to Power Agency and Participants.....
Company net peak demand.......:.....
Total capability at end of period (thousands of kUowatts):
Fossil plants Nudear plants.Hydro plants Purchased Toed combined system capabUlty...........
Less Power Agency owned portion..~~~~.~~~Add capabUIty purchased from Power Aecncy..Totd Company portion.~~~.~~.~~~~~~~5 518 325 479 41 1J63 263 1.626 21 5 1.6>7 474 302 434 39 1.249 275 1J24 14 1.538 5 416 250 386 36 1.088 245 1.333 ll 5 I J44 5 6.926 304 6.622 449 6.173 6.602 637 5.965 6.402 6 402 6.291 5.561 2.245 v 245 214 214 75 75 5.519 2.245 214 75 8.825 494 75 8.406 8.095 262 7.833 8.053 6.602 6.402 Orr 342 196 297 30 865 202 1.067 9 1.076 6.139 69139 6.139 5.519 2,245 214 75 8.053 5 293 172 268 09 762 156 918 8 5 926 5.907 5.907 5.907 4.869 2.245 214 128 7.456~,"fN of purcr5s ses t>y the Com ps53y 5'rem Power Ase59ey.~tt5e I982 peak o5>wrsr>S before Power>Ste55cy clo5552S on AprSI 21.1982.
Service Area CPM.Service Area~RRk Mapo Walt/r's Rhal Ashhville Jacksonville Weat herspoon~Sutt n Robinson~-WilnIington
~L And Florence Qg I PAI El RI lCF ARFA~FREER'IR neF B un~wick~Rt FIXW~A M%'I FAR 5l IIIEIR AMIMR IEAll M ImAIII r MKIFAR FIEF I C IINWt4F~FOAEIL EIIE Darlington aaa S.C.Sumter Columbia*Rox oro~Henderson N.C.~ape~a*Raleigh Fear r~.~L~ee Charlotte,'oldsboro~T.C~+Southern Pines%P Bl MoreheaIl Cit Blewett ITEM 2.PROPERTIES For a description of the Company's major generating units, see ITEM 1-"Generating Capability".
See ITEN 1-"Service Area" for a general outline system map, showing the Company's service area and the location of generating facilities and district offices.At December 31, 1983, the Company had 5,351 pole miles of transmission lines including 168 miles of 500 KV and 2,444 miles of 230 KV lines, and distribution lines of approximately 36,240 pole miles of overhead lines and approximately 2,604 miles of underground lines.Distribution and transmission substations in service had a transformer capacity of about 29,698,000 KVA in 2,327 transformers.
Distribution line transformers numbered 334,452 with an aggregate 11,844,200 KVA capacity.The properties of the Company are subject to the lien of its Mortgage and Deed of Trust.Otherwise, the Company has good and marketable title with minor exceptions, restrictions and reservations in conveyances, and defects, which are of the nature ordinarily found in properties of similar character and magnitude, to its principal plants and important units, except certain rights-of-way over private property on which are located transmission and distribution lines, title to which can be perfected by condemnation proceedings.
Plant Accounts-During the period January 1, 1979 through December 31, 1983, there was added to the Company's utility plant accounts (including nuclear fuel)$3,273,221,000, there was retired$185,678,000 of property other than for the Power Agency sale, there were retirement and other reductions of$543,157,000 related to the Power Agency sale and there were transfers to other accounts and adjustments for a net decrease of$381,226,000, resulting in net additions during the period of$2,163,160,000 or an increase of approximately 62.9%ITEM 3.LEGAL PROCEEDINGS Legal and regulatory proceedings are included in the discussion of the Company's business in ITEM I end incorporated by reference herein.ITEM 4.SUBMISSION OF i%'IATTERS TO A VOTE OF SECURITY HOLDERS 1983.No matters were submitted to a vote of security holders in the fourth quarter of EXECUTIVE OFFICERS OF THE REGISTRANT Information on executive officers is set forth in ITEiN 10(b)and incorporated by ref erence herein.
Part II ITEM 5.MARKET FOR THE REGISTRANT'S COMMON E UITY AND RELATED SHAREHOLDER MATTERS The Company's Common Stock is listed on the New York and Pacific Stock Exchanges.
The high and low sales prices per share for the periods indicated, as reported as composite transactions in The$Uall Street Journal, and dividends paid are as follows: 1982 First Quarter Second Quarter Third Quarter Fourth Quarter 1983 First Quarter Second Quarter Third Quarter Fourth Quarter~Hi h$23 22 3/4 22 3/4 21 7/8~Hi h$23 22 7/8 23 3/4 25 1/8 Low$19 1/2 19 5/8 19 18 7/8 Low$20 5/8 21 1/2 20 3/8 21 1/2 Dividends Paid$.60.60.60.60 Dividends Paid$.60.60.60.63 As of February 29, 1984, the Company had 103,189 holders of record of Common Stock.ITEM 6.SELECTED FINANCIAL DATA For the Year Ended December 31 1983 1982 1981 1980 1979 (In Thousands, Except Per Share Figures)Operating revenues Net income Earnings for common stock Earnings per common share Dividends declared per common share Total assets$1,647,183 239,269 194,664$3.21$2.46$5~293,606$1,538,165 227,147 182,542$3.17$2.40$4,9S0,9SS$1,343,558 203,597 160,937$3.06$2.32$4,715,835$1,075,604 161,388 925,910 153,244 126,747 124,981$2.73$3.06$2.20$2.05$4,241,607$3,647,913 Capitalization:
Common stock and retained earnings Preference stock Preferred stock-redemption not required Preferred stock-redemption required Long-term debt, net (a)$1,586,441 47,900$1,462,165 47,900$1,364,692 47,900$1~233~368$1~045~150 47,900 47,900 238,118 238,118 238,118 238,118 238,118 214,785 214,743 214,700 175t100 100~000 1,713,467 1,507,690 lt931i672 1~955i824 1<929<448 N,,>>, N.,$46,479,000,$64,122,000 and$21,849,000 for the years 1979-1983, respectively.
I ITEM 7.MANAGEMENT'8 DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION The following discussion and analysis should be considered in conjunction with the relevant sections of ITEM 1 Selected Financial Data in ITEM 6 and the Company's financial statements appearing in ITEM 8.LIQUIDITY AND CAPITAL RESOURCES The Company's current construction program normally requires expenditures which are greater than funds generated internally.
Sales of long-term securities and short-term borrowings are used to meet needs in excess of such internally generated funds.(See"Construction Program" and"Financing Program" in ITEM 1 for a summary of capital requirements for 1984 through 1986.)Capital resources for 1981-1983, summarized and restated from the"Statements of Source and Use of Financial Resources" in ITEM 8 to show dividends as a reduction in available resources, were provided as follows: (in millions)Total 1983 1982 1981 Operations (less dividends)
Sale of gene.ating units Financings Total$912.6 664.1 318.1$398.1 79.3 236.5$241.9 584.8 136.7 82.394.8 8713.9$963.4$272.6 444.9 8717.5 and utilized as follows: Gr oss property additions and nuclear fuel Retirement of long-term debt Power Agency trust fund remaining Other working capital incr ease (decrease), etc.100.3 33.5$1,948.0$708.6 346.5 125.7 (153.9)$654.7$584.7 160.0 60.8 153.9 (5.2)72.0 Total 82 394.8 8713.9 8963.4 871'l.5 The increase (decrease) in capital resources from operations, as compared with the preceding year, resulted from the following changes (in millions):
Net Income Dividends Deferred income taxes and investment tax credits Depr eciation and amortization Provision for coal mine losses Deferred income taxes credited to property accounts 1983$12.1 (11.5)66.9 27.8 49.9 11.0 1982$23.6 (17.3)(23.5)(8.8)(4.7)1981$42.2 (26.7)52.5 24.2 (3.7)Net increase (decrease) in resources from operations
$156.2$(30.7)$88.5 The increase in resources from operations in 1983 resulted principally from (1)a return to a more normal level of deferred income taxes and investment tax credits from a year earlier when additional tax payments related to the sale of facilities were made which reduced the net deferred income tax provisions in 1982, (2)the net non-cash charges against income in 1983 related to provisions for possible coal mine investment losses offset by amortization of the gain from the sale of generating facilities and (3)increased depreciation and amortization charges consistent with increased plant in service and amortizable canceled project investment.
Internally generated funds from depreciation and amortization will increase significantly when the Harris Unit No.1 is placed into commercial operation in 1986, and to the extent that the investment in the canceled Harris Unit No.2 is amortized (see Note 6 to Financial Statements).
The relative amounts of resources obtained from financing activities have been as follows: 1983 1982 1981 Common and preferr ed stocks First mor tgage bonds Long-term notes Commercial paper backed by long-term credit facility Nuclear fuel financing arrangements Short-ter m transactions 33.9%71.4 (24.1)(4.4)4.2 23.2 (74.8)29.2 9.4 7.6 39.4%30.3%87.1 5.5 44.1 18.0 100.0%100.0%100.0%Total financings were (in millions):
$236.5$136.7.$444.9 During 1983, the amount of financing activities continued at a reduced level, compared to 1981 and previous years, because of the$153.9 million available from 1982 Power Agency sale closings plus an additional
$79.3 million in 1983.Issuances of common stock under the various plans increased in 1983 (See Note 3 to Financial Statements) primarily due to the increased interest in the dividend reinvestment program and an issuance of shares for employees under the ESOP program.The cancellation of Harris Unit No.2 has reduced significantly the capital requirements for 1985 and later years.Capital requirements for construction and nuclear fuel in 1984 and future years reflect significant reductions because of Power Agency's ownership inter ests.Increased inclusion by regulatory authorities of construction investment in the rate base reduces the amount of construction expenditures because less AFUDC is required to be capitalized (see Note 1(d)to Financial Statements).
The Company presently has on file with the Securities and Exchange Commission a shelf registration statement under which the Company can issue up to$150 million of additional First Mortgage Bonds (Shelf Bonds).The amount and timing of future sales of these and other securities will depend primarily upon market conditions and the needs of the Company.
The Company's ability to issue additional shares of preferred stock or First Mortgage Bonds is subject to earnings and other tests.Based upon unfunded property additions and retired bonds at December 31, 1983 and assuming the issuance of$150 million of Shelf Bonds, the Company could issue approximately
$1.4 billion in additional First Mortgage Bonds.After the issuance of the Shelf Bonds (at an assumed rate of 13%)under the Company's Charter earnings test, at December 31, 1983, the Company could have issued approximately
3.6 million
additional shares of preferred stock (at an assumed price of$100 per share and an$11.00 annual dividend rate).The 8 million authorized, but unissued, preference stock shares are not subject to an earnings test.The Company currently expects to elect by June 30, 1985 to defer payments of the$88 million accrued liability for nuclear fuel disposal costs (see Note 8(e)to Financial Statements).
The Company has the option until June of 1985 to pay the accrued amount at that time without interest, to elect to pay in quarterly installments with interest over a future ten-year period, or to pay ih one lump sum with interest in the late 1990s.Short-term liauidit: Customer receivables on the books at year-end represent an average of less than 20 days billings.At December 31, 1983, the Company had firm, unused bank lines of credit totaling$206.7 million and a$130 million irrevocable revolving credit facility supporting outstanding commercial paper of$73 million in addition to$57 million of pollution control First Mortgage Bonds that are redeemable annually at the option of the holder (annual tender bonds).In connection with those annual tender bonds, the Company has contracted for remarketing in the event of tender for repurchase.
The obligations supported by the$130 million revolving credit facility are classified as long-term debt on the balance sheet.Proceeds from the issuance of the Series F pollution control bonds totaling$32.1 million are held in trust pending use for qualif ying expenditures.
At December 31, 1983, the Company had unused investment tax credits of$109 million and a tax loss carryforward of approximately
$81 million that can be used to reduce federal income tax payments in 1984, or later years if not used in 1984..RESULTS OF OPERATIONS Operatin revenues increased during 1983 and 1982 principally because of: (1)general rate increases that produced$70.6 million more in 1983 as compared with 1982 and$140.5 million more in 1982 than in 1981, (2)fuel cost adjustment billings that decreased$21.0 million in 1983 from 1982 levels while increasing
$34.3 million in 1982 over 1981 levels, and (3)a 1.3 percent overall increase in energy sales in 1983.The 1983 increases in energy sales includes the net effect of a 5.4 percent increase in retail and regular wholesale customer energy sales and a 36.1 percent decrease in Power Agency related sales, which fluctuate with output levels of the jointly-owned generating units as well as customer demands.0 eratin expenses reflect increased costs of fuel due to greater generation of electricity in 1983 to serve increased customer needs and to replace a portion of the more expensive purchased and interchange power costs that occurred in the prior year.Generation from the coal-fired Mayo Unit No.1 that was placed into commercial operation on'arch 1, 1983 was responsible for a substantial portion of the increased output.Also, nuclear fuel expense increased as the Company experienced increased nuclear power plant availability in 1983 as compared with 1982.The provision in 1983 for possible coal mine investment losses of$49.9 million increased operating expenses-33"
and is related to investment in coal mining subsidiaries (see Note 2 to Financial Statements).
Maintenance expense, which declined in 1983, reflects a one-time credit of$15.7 million in order to capitalize certain replacements of property items at generating plants that were expensed in prior years, principally 1982 and also reflects on overall decrease at generating plants from levels in recent years.Generally, operating expenses increased, especially depreciation, due to Mayo Unit No.1 being placed into commercial operation in early 1983.Other Income declined due to a decrease in the allowance for other funds used during construction, reflecting reduced investments in construction, principally because the Mayo Unit No.1 was placed into commercial operation.
Other income also declined because of expenses of operation of the Company's coal mining subsidiaries.
Income tax credits decreased principally because of lower capitalized interest charges.Offsetting these decreases in part is amortization of a portion of the gain from sale of generating facilities to the Power Agency.ll 1982 and 1983.The allowance for borrowed funds used during construction, net of deferred income tax effects, decreased in 1983 because of reduced investments in construction.
Furthermore,.
the inclusion of construction investments in the rate base decreased the allowance for borrowed and other funds by$39.5 million in 1983,$43.4 million in 1982 and$21.9 million in 1981.(See iVote 1(d)to Financial Statements).
Net income and earnin s: In summary, while earnings for 1983, 1982 and 1981 have increased from year to year, earnings have been adversely affected by continuing inflation, high levels of operation expenses and other cost incr eases not fully reflected in approved revenue levels.Interest rates and levels of inflation were lower in 1983 and had less adverse impact on earnings in 1983 than in recent years.The charge to operations for possible investment losses applicable to the coal mine subsidiaries adversely affected 1983 results.Increased energy sales because of colder weather and an upturn in economic activity contributed favo'rably to earnings in 1983.The quality of earnings has improved somewhat because of less AFUDC and more compensating revenue, as increased amounts of constr uction investment have been allowed in the rate base.Earnings per share of common stock have been adversely affected by the increased number of shares outstanding.
IMPACTS OF INFLATION See Supplemental Inflation Adjusted Data in ITEM 8 for the estimated effects of changing prices on income on the basis prescribed by the Financial Accounting Standards Board.
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The following financial statements, supplementary data and financial statement schedules are included herein: Auditors'pinion Financial Statements:
Balance Sheets as of December 31, 1983 and 1982 Statements of Income for the Years Ended December 31, 1983, 1982, and 1981 Statements of Retained Earnings for the Years Ended December 31, 1983, 1982 and 1981 Statements of Source and Use of Financial Resources for the Years Ended December 31, 1983, 1982 and 1981 Schedules of Capitalization as of December 31, 1983 and 1982 Notes to Financial Statements Summary of Quarterly Financial Data Supplemental Inflation Adjusted Data Financial Statement Schedules for Years Ended December 31, 1983, 1982 and 1981: V-Utility Plant VI-Accumulated Provision for Depreciation and Amortization of Electric Utility Plant VIII-Reserves IX-Shor t-term Borrowing X-Supplementary Income Statement Information
~Pa e 36 37-38 39 39 40 41-42 43-47 48-50 51-53 54-56 57-59 60 61 All other schedules are omitted as they are either not required, not applicable, or the information is otherwise provided.
Moiite HBskins-8eils Auditorsr Coinicn Ca~lina Power E Light Co??zeny'-
2000 Center Plaza Building Post Office Box 2778 Raleigh.North Carolina 27602 (919)8284716 Cable DEHANDS~~t;e have eza~ined uhe i~w~cial s~atezents and suppleg nta't f<<wzci~1 statement sch+ules of C~ml'w Power I?Tight Company 1'sted in the accorqanyi<<ng table of conten"s.Cur ex~-,~<<tions were vade i<<naccorc~~ce wit"?ge..erally accepted auditing stand"-m and, accordir@y, included such tests of the accounting records and such other auaiting procecures as we considered necessary in the c<<"cumstances.
Px discussea in I'tote 6, the Co., arg nucle~generating u?~t and intends re~tory jur<<sdictions Co recover GutcolN of this lifter ca zlot has canc led plans for construct<<on of a to reauest per..'ssion in each oz<<ts its costs.lated uo such un"t.ne pr sently b d ter..~wed.
Tr.Our opin<<on, sub;Iect to th e=fects on the f&~cial stat.;ants of such adjust...K~
s)i~a."?y)as,.<<"lt have be."?recuir d had-.he outco.-..e of uncerta<<"?t J r fe~"o in he re~~g oa~<Qh b n.oti".1 cia 1 stateg~j<ts
>~f~+Q to above pr sent fa: rly the i<mr.cial pos<<t<<on o th Cc;,-a~'t december 31, 1983 and 1982 and-.h results o~<<us operations and the source and use of its f~<<z.c<<ial resou es:or each of the Chr e yea"s i<<niche period ended Dece~ier 31, 198-in ccn=o=-.,=:-'y with gen ray acceoted accounting"rinc<<ples ac@lied cn a ccns'-ent'=asia.Kso, in ou".Opmhon, subject to the cu"lification r f r d to above such supp'cmental fi?ancial statement schedul s, wnen cons"dered in~lat<<on Co the bas<<c"inancial statements, present Mly in all materi<<al spe ts the informtion shown ther in.Ãe have also pr viously e~ed, in accordance tr'th.n.-ally accepted a;diting standa<s, the balance sheets and schedules cf capital'zation as of Eecember~l, 1983., 1980 wd 3.979, and the related state~rr.nts of income j g~re-8"?eQ arnings anQ source and us of f~~.c~r sou.ces for-.e yeP s enae" D ceo>er 31, 1980 and 1981 (none of which are presented herein)"e exQressed un M1if<<e opi.<<ons on th se f~c~<<~sta e,;B~1ts'oweve
=we were to re'ssue o"" oo~on on these statements c"rentlv, it~~a u a.N~~v't'Q 0 Qual ed Lvg" arl;to the arece~<<g paragraoh.
Ln our oo<~'on, subject?'o the oual<<cation refe~~d to above, the se'ected'or each of the ive years<<n the per<<od ended D2ceqjoer>>, lct'y, aDcear<<,-Page 30, is fa'"lJ pr sented~z all material?respects in~" aticr to"-:".e'"Wzncial stateŽnts rom t"<<ch<<t has been Qer've=.~~:ter.4Q.Zy 1 g 1 98 It Balance Sheets.Carolina Power 8c Light Company December 31, 1983 and 1982 1983 (tn itious.".~a)1982 Electric Utility Plant: Elec'.ric utility plant other than nuclear fuel: In service.Held for future use Construcnon work in progress.Total Less accumulated depreciation Net.I luclear tuel.Less accumulated amortization
.Net.Electric utility plant.net S3.629.625, 12.902 1.697.551 5.340.078 884.250 4.455.828 264.802 149,424 115.378 4.571.206 S3.019.141 10.350 1.994.906 5.024.397 792.013 4.232.384 231.518 131.280 100.238 4.332.622 Current Assets: Ccsh cnd temporary ccsh investments Accounts receivable.
net Power Agency Trust Fund Matenals and supplies: Fuel Other.Deter:ed fuel cost Current portion of deferred income taxes Prepa~ents.etc Total current assets 9.214 97.651 101.893 25,338 6.186 16.967 9.162 266.411 8.028 75.140 153.89 I 121.896 29.495 5.070 16.948 20.636 431.104 Other Assets: Uncmortized canceled project costs: Hams Unit No.2 (Note 6)Hams Units Nos.3 fznd 4 (Note 8[f)).Unrecovered nuclear tuel disposal costs (Note 8[e])..Investment in coal-mining subsidicnes (Note 2)......Miscellaneous other property and investments
.......Unamortized debt expense Other deferred debits Total other assets.263.733 121A60 29.267 2 22.348 3,467 15,712 455.989 124.587 I 9.620 I 8.5o0 3.230 21.232 187,229 Total S5.293.606 S4.950955~I e notes to!inancial staiernen',s.
'alanl-e Sheets Carolina Power 8c Light Company December 31, 1983 and 1982 abilities 1983 (In:l20VSar CS i 1982 Capitalization (see Schedules of Capitalization):
Common stock.Common stock subscribed Retained earnings Preference stock.Preterred stock-redemption not required.............
Preferred stock-redemption required.net.............
Long-term debt (excluding current matunties}, net.....Total ccpitalization (excluding current matunties of long-term debt}.S1.151,323 2.205 432,913 47,900 238.118 214.785 L909.823 3.997.067 S 1.071.863 l.528 388.774 47.900 238.118 2!4 743 1.891.702 3.854.628 Current Liabilities:
Long-term debt due within one year Notes payable: Bank demand notes.Other (pnncipally commercial paper)...Accounts payable: Construction contract retentions Other Customers'eposits Tcxes accrued interest accrued...,....................
Dividends declared Other Total current liabilf ties 21.849 82.703 5.370 126.055 7.905 41.782 42.378 58.833 4.319 391.194 l 3.CCO 19 n4n f 3.725:59 pl0Q , p~4 v v 68.467~4%~N l,w'4'4.769 4.C05 395."ov Deferred Credits and Other Lfahfffffes:
Accumulated deferred income taxes: Hams Units Nos.2.3 and 4.Gain on sale of facilities (Note 7).Other.net.Total cccumulated deferred income taxes..Accumulated deferred investment tax credits...Uncmortized gain on sale of facilities (Note 7)..Other.Total deferred credits and other liabilities...
134.702 (98.125)494.424 531.201 174.112 128.104 71.928 905.345 35.885 (94.080)447.926 389.731 180.700 117.348 22 494 700.674 Commitments and Contingencfes (Notes 2.6.7 and 8)Tote!S5.293.606 84.c50.955 e notes io fmcnc:al statements.
Statexnents of Income Carolina Power&Light Company For the Years Ended December 3l.1983 1982 1981'.!n Thn~nds Except ic.-.t."~Per Rcw)S1.647.183 S 1.538.165 S 1.343.558 Operating Revenues (Note 9)Operating Expenses: Operation:
Fuel for generation Deferred tuel costs Purchased and tnterchange power.net......Other (Note 2)Matntenance
.Deprectation ard amortization (Note I).......Taxes other than on!ncome Income tax expense (Note 5).Total operating expenses.Operating income Other Income: Allowarce for other funds used during construction
.Income tax credits (Note 5)Amornzed ga!n on sale of facilities (Note 7).........Other!ncome (deductions).
net (Note 2)............
Total other income..............
Income Before Interest Charges.Interest Charges: Long-term debt Other Allowance for borrowed funds used dunng structtonwredit (Note 5)cor Net Income Net interest charges.Preferred and Preference Stock Dividend Re~ements.......Earnings for Common Stock.........
517.625 (1,115)18.583 285,671 137.383 148,342 114.295 162.443 1,383.227 263.956 94.927 31.078 11A22 (4.945)132A82 396A38 171.448 17.551 (31.830)157,169 239,269 44.605 S 194.664 473.509 1.423 50.226 233.147 167.458 126.355 104.300 133.622 1.290.040 248.125 98.353 38.472 13.919 15O.744 398.869 180.986 34.00!(43.265)17 I.722 227.147 44.605 S 182.542 459.591 523 19.388 174.084 I 25.876 I IOA09 97.288 118.996 1.106.155 237.403 92.508 35.846 8.593 I 36.947 374.350 177 98 I 31.201 (38A29)170.753 203.597 42."60 S 160.937 Average Common Shares Outstanding
.Earnings Per Common Share.See notes to financial statements.
Statements of Retained.Zarnings-For the Years Ended December 31, S 60.645 57.539 S 3.17 S 3.06 Balance at Beginning of Year Net Income Total Deduct: Cash dividends declared: Preferred and Preference Stock at stated rates (Note I)Common Stock (at annual rate of S2Ab a share in 1983.S2.40 in 1982 and S2.32 in 1981).............
Total cash dividends declared Capital stock dtscount and expense Total deductions ance at End of Year.See notes to financtal statements.
1983 S 388.774 239,269 628.043 44.605 150.423 195,028 102 195.130 S 432.913 1982 (tn thousands)
S 345.353 227.147 572.500 44.6O5 138.878 l83A83 243 183.726 S 388.774 1981 S 309.819 203.597 513.416 123.578 167.638 425 168.063 S 345.353
" Stafexnents of Source and Use of Financial Resources Carolina Power 8c Light Company For the Years Ended December 31, 1983 1982 (In Thousands) 1981 ource of Financial Resources:
Current resources provided from operations:
Net income....................................,....
Items not requiring (providing) current resources:
Depreciation and amortization
.Amortized gain on sale of facilities
.................
Provision for possible coal-mine investment losses...Noncurrent deferred income taxes.net.............
Investment tax credit adjustments.
net...............
Other funds portion of AFUDC Total current resources provided from operations Sale of generating facilities Total current resources.Additions to plant accounts representing capitalization of other portion, less deferred income taxes on borrowed funds portion of AFUDC Total resources provided excluding financings S 239.269 180.565 (11.422)49.868 172.341 (6.589)(94.927)529.105 79.301 608.406 64.056 672.462 S 227,147 141.334 I0.391 88,493~98.383)369.012 584.801 953.813 56A05 1.010.218 S 203.597 150.105 I50.940 (28.569)~92.888)383.565 383.565 8.23)938.798 Financings:
First mortgage bonds.Preferred stock Common stock-Public offerings Common stock-Plans (Note 3)Other long-term notes.Commercial paper backed by long-term credit facility.Nuclear tuel trust and lease obligations
............
Decrease in temporary cash investments plus increase in short-term notes payable........Total resources provided from financings
......Total.168.767 80.077 42 (57.015)(10.409)54.993 236A55 S 908.917 119.038 53.852 60.270 5.731 (I02.195)I36.696 S l.146.914 24.248 39.458 59.6I6 35.931 80.000 130.CCO 41.954 33.705 4aa.9!2 S 883.708 Use of Financial Resources:
Gross property additiots.
excluding nuclear fuel'Nuclear fuel additions' Canceled projeca expenditures Dividends for the year.Repayment of first mortgage bonds.Repayment of other long.term debt.Repayment of nuclear fuel lease obligation
.......Net increase (decrease) in the following working capital components:
Power Agency trust fund.Accounts receivable.
net.Materials and supplies Accounts payable Reserve tor retund of revenues Other.net 88scellaneous.
net.Total S 660.130 48.488 20.710 195.028 123.346 2.333 (153.891)22.511 (24.160)(7.861)499 15.389 6,395 S 908.917 S 638.284 16A50 15.355 183.a 83 20.000 140.064 153.891 4,284 13.968 (10A82)24.094 (25,687)(26.790)S1.146.914 S 548.508 36.223 166.238 15.000 45.827 8.019 19.930 56.943 (16.799)(11.002)I 4.82!S 883.708'Includes amounts capitalized as allowance for funds used duxfng construction.
net of related defeired income taxes.notes io financial statements.
Sch.edules of Capitalizcrhon--
Carolina Power&Light Company December 31, 1983 and 1982 1983 1982 (In Thousands)
COMMON STOCK EQUITY (Note 3): Common stock without par value.authonzed.
100.000.000 shares.Outstanding 62 484.959 shares at December 31.1983 and 58.835.176 shares at December 31.1982 Subscnbed Retained earnings.limited in payment as dividends under cenain circumstances under the Company's charter, however.none restncted at December 31.1983...Total common stock equity$1.151.323 2.205 432913 5 I,584.441$1.071.863 1.528 388.774 S I.462.!65 PREFERENCE AND PREFERRED STOCK.without par value.cumulanve (Note 3): At December 31.1983 Redemption Price Shares Outstanding Preference stock.cuthonzed l0.000.000 shares (ent:tied to$25 a share plus accumukned dividends in the event ot hquidction.
in preterence only to common stock)-S2,675 Senes A S 2650 2 CCOOGO 5 47.900$4 cCO.Preferred stock (a)-redempnon not required: SS Preterred Stock-authonzed.
300.000 shares...,..Senal Preterred Stock(b)$420 Senes..5.44 Senes.910 Senes.795 Senes.772 Senes.8.48 Senes.Sl IOCO 102.GO 101 GO 10300 104 00 104 00 105 00 237 259 I GO,GGO 250.GCO 300.000 3M.COO 500.GGO 450.000$24.376 10.000 25.000 30.000 35.000 49.425, 64.317"4 3"6 IG.CCG"S.CCO 30.000 35.0CO 49,425 64.317 Total-redemption not required 2.387.259 5 238.118 5 238.118 Preferred stock (a)-redemption required (c): Senal Preferred Stock (b)-Sl I 16$enes.1400$enes.Preferred Stock A.authonzed.
5.000.000 shares S745 Senes.8.75 Senes.9 25 Senes.................
..........
900 Senes.Vnamcmzed discount.Total-redempnon required SI I I 16 114 GO 104 00 107 23 104 50 (c)5CO.GCO SC0.000 180,000 17:.GOO 2.!=.000$40.000 40.000 50.000 50.000 18.000 17.500 (715)5 214.785 S 40.CCO 40.000 MCCO 50.CGO!8.CCO 17.MO 5 21>>43 lal Entitled lo 3100 a share plus accumulated dlvtdends ln the evenl ol llauldatton.(b)Authonzed.
20.000.000 shares in total.(c)Minimum sinking fund requirements (at$100 per share plus accumulated dividends) commence in 1984 for the$7v45 Series.at 20 000 shares per year in 1985 for the$8 75 Series at 20 000 shares per year and increasing in the year 2000 to 40 000 shares annually: in 1986 for the$11.16 Senes at 12 000 shares per yean in 1987 for the$14 00 Senes at 16 000 shares per year and in 1990.Ior the$9 OOSenes.all 175 000 shares are to be redeemed.With respect to the$9.25 Senes.the Company must offer to redeem annually.on March I of each year egtnnfng in 1988.any or all shares outstanding.
Mimmum smking fund requirements for the next five years aggregate:
1984.S2.000.000; 285.$4.000.000; 1986.$5.200.000.
1987.$6.800.000 and 1988.$6.800.000.
e notes to fmancial slaterrerts
LONG-TERM DEBT (a): First n:ongage bonds.pnncipcl amounts: Other than Pollunon Control Senes: Matunng 1983 through 1993: I I%.due Apnl 15.1984 (redeemed IOIS-83).f491%.due Apnl l.1987 4g)L due March I.1988 4i'A.due Apnl I.1990 4i!%due November I.1991 I I 2 L due December l.1992 Marunng 1994 Ihrougn 1998-4m%to 6iA.Matunrg l999 through 2003-7<to Sill.Matunng 2C04 through 2008-SH%to 934%.Matunng 2009 through.2013-IO'ri%, to l2'8%.1983 5 125.000 20.000 25.000 25.000 100.000 140.000 525.000 325.000 325.000 1982 (tn Ihoi)scow)
S 67.346 125.!Xo 20.GCO 25.0CO 25.GGO'QOCCO 140.GGO 525.GCO 325.000 225.000 Pollution Control Senes: A 8%.due 2001-2009 (pnnctpal amount less proceeds held by Trustee: 1982.SI.900)..B.7.4%due IO 1-83 (pnnci pal amount less proces held by Trustee l 982.S12.227)....C.7 A due 10-1-83.D.(5.65%, to 4/I/84)due 4-1-2009 F (5.65%to 4/I/84)due 4-1-2009 F.(7.0%to I I/I/S4)due 11-1-2010 (pnncipcl cmount less proceeds held by Trustee 1983.S32.!40).Total liat rnortage bonds.pnnctpal amounts.63.000 48.485(b)5.970(b)61.IOO 37.J73 6.CGO 2.560(b)1.730.015 I.c82.2lc Other Icrg.term debt: Nuclear tuel trust obligations (vancbie rctes.!0.47%avercge effective interest~~5~~cost at 12-3I.83: 9.56%at l2-31-82).............................
~.~~., 86r%Guarcnteed Notes (Finance 8V,V,)due 2.15-89 (Ncte I (bi}Carolina Pipeline (Vanable mterest rate-I I.5%at 12-31.82)Ccmmetcial paper backed by Iong.term credit facflity to 9-24.86 (9?OS'verage et!ective interest rate at 12-31-83.8.6N ct l2-31-82)Misce J'aneous promissory notes Totcl long.tenn debt.pnncipal amounts Unamortized discount and premium net Total long-term debt.including current maturities Less long-tenn debt due wtthfn one year.Nuclear tuel trust obligattons
.?i48%PcllutiOn COntral BOndS.due 10-1-83 Carolina Pipeline due 10 l-83.Total long-tenn debt.excluding cutrent matunhes.TOTAL CAPITALIZATION (exc!uding c~nt matunties of long.term debt}80.215 60.000 72.985 107 1.943.322.1.080.406 shares under the Employee Stock Ownersi..ip Plea (ESOP)and I.444.432 shares under the Customer.lock Ownership Plcn (CSOP)(I)Other Policies.Other property and investments are.cted pnrcipally at cost.less accumulated depreciction where applicable.
Materials and supplies inventones are stated at average cost.The Company maintains an cllowcnce tor doubtful accounts receivable (1983.S2 477.COO: 1982.S1.757.000).
Bond premium.discount cnd expense are amortized over the life of the related debt.2.Investment in Coal-Mining Subsidiaries On November 29.1983.the Company acquired the rerrain:ng 20 percent interests fn its two coal-m:ning subsidianes.
Leslie Coal Mining Company{Leslie)and Mclnnes Coal Mining Company (Mclnnes).
At December 31.1983.l.eslie's and Mclnnes'otal assets were approximately SI31 million.The Company has gucranteed their obligations of approximately S 108.5 rmllion The Company ourchased coal from the subsidiaries tor S2).843.000.
S48.178.000 and S37.314.mm dunng 1983.1982 crd 1981.respectively.
representing Ihe costs of production for the mines Dunng 1982.the Company wrote off the ccc"mulated excess ot costs of produc'.ion over fair market vclue of ts coal purchases that had Leen previously deferred.In 1983 the Companychcrged S49.868.000 to other opera:.on expense tor possible losses on its irvestments in'he..;:nes.The subsidiares suspendec produc!ion in the first quc.".e.ot 1983 and the Company hcs stree then recorded other!rcome the carrying charges and other experses of@prox:mately Sl.300.000 oer month, The Company"rre..iiy pica~to sell the propemes.Pickands Mather fk ompcny, the previous mtrority owner.continues to...cncge and operate the mir.es 4.Notes Payable and Lines of Credit At December 31.1983.the Company had tirm.urused lines of credit with varous tinanc:ci insiitutiors totaling S206.690.000 including necessary cmounts to back up the outstanding current liability portion of commercial paper: and, in connection with these lines of credit.is required to maintain average compensating balances in various banks of S952.500 and pay commitment tees of approximately S61.000 per month.Such lines ot credit are reviewed periodically.
at which time they may be renewed or canceled.
5.Income Taxes The provisions for income tax expense are composed of the following (in thousands):
Year Ended December 31.1983 1982 1981 Included in operahng expenses: Currently payable taxes-Federal-State Deterred taxes.net-Federal-Stcrte Investment tax cred:t ad,'ustments.
net.Total S 7.316 (106)142.887 19.137 (6.791)162.443 S 29.055 18.933 913 (1.939)86.660 I 33.622 S 52.732{427)808 4 14.237 (28.400)t tB.WO Included in other tncome (a)Ileduchon in currently payable taxes-Federal
.-State....Detened taxes-Federal (a)-State (a)Investtnent tax credit adtustments.
net Total Total income tax expense (9.791)(813)(18.238)(2337)101 (31.078)5131.365(a)
(1.088)(1.524)(35.514)(2.179)1.833 (38.472)S 95 150(a)(58.026>(!.037)26.720 (3.334)(lo9)(35.846)S 83.150(a)(a)Deferred income tax provisions totaling SM 871000 tor 1983.S4 1948 000 tor l982 and s37 277000 for l98 I related to the tax effects ot the allowance tor bonowed funds charged io fhe cost of plant are reflected in ihe statements of income as a reduction in the Allowance tor Bonowed Funds Used Dunng Constfucnon
~Credit.Provisions for net deferred income taxes related to the following (in thousands):
Differences between book depreciation ard amortizahon and tax deduaions lor p.o petty costs,'rewperahonal tax deductions (taxes and other costs capitalized.
etc.)-ongtnattng dilferences
.Nuclear fuel disposal costs.Aocelerated depreciation and other propeny cost differences.
Ortgtnattors
.Reversals....
Deferred recognition ot gain on sale of generahng tact tihes.net.Unbilled revenues.net Deferred tax gain on sale ot tacilities.
net Provision for possible refund ol revenues.net Utihzation ol subsidianes tax losses.Canceled protect costs.net Tax loss cartytofward Miscellaneous other timing differences.
ret Total prov'store lor deterred income taxes.ret..S 11.091(b)41.874 62.374 (32990)'4.201)1.770 16.660 (17)8.347 93 432 (39 659'17.(32>
SI 4 lA49 59 131 (37 753)43.IOO(c)(94.080)(19.729)62.160 11.54o 5.87!(14.!00)5 902 0.439 49'F73"4'o2}S(38.719)4 O13 SI 18 477 S 11.863(b)S 8.515(b)(19 466)526 (b)Excludes deferred tax provisions relating to tax effects ot bonowed funds capftattzed (see (a)above)(c)Rectassuicatfon ot detail tor onginatfons and reversals lor l98l is not practical.
A reconciliation of the Company's effective income tax rate (compuled by dividing total income lax expense, including amounts reflected as a reduction inAFUDcon borrowed funds.by prelaz income)to the statutory'ederal income taz rate follows: Year Ended December 31, 1983 1982 1981 Effective income lax rate'ihe effects of including ARJDC on other funds in pretax income Effective income lax rate.excluding AFUDC on other tunds from prelax income.State income taxes.net ol federal income lax benefit Other differences.
net Statutory lederal income tax rale 12.5 52.9 (3.4)(3.5)37.6%14.0 51.6 (3.8)(1 8)46.(8 37,2L 14.8 52.0 (3.3)(2 7)46.(P4 6.Hafzis Unit No.2 In December 19S3.the Company canceled further construction on Harris Unit No.2.a 900.000 kilowatt nuclear generating unit planned for completion in 1990.The Company's share of the estimated final investment in the jointly owned canceled unit is S315 million.The Company is seelang regulatory permission to wnte off the costs over a period of ten years and to recover such costs through rates..Joint Ownership of Generating Facilities The North Carolina Eastern Municipal Power Agency (Power Agency).which members include a majonty of the Company's previous municipalwholesale customers.
has acquired undivided ownership interests in certain generating facilities of the Company.The Company and Power Agency are entitled to shares of the generating capability and output of each unit equal to their respective ownership interests.
Each also pays its ownership share.on a current basis.of additional construction costs.tuel inventory purchases and operating expenses for each unit.Power Agency's payment obligation with respect to cancellation costs for Hams Units Nos.2.3 and 4 fs 12.94 percent of such costs.At December 31, 1983.the Company's ownership interests and investments in the jointly owned generating facilities were as follows (dollars in millions):
Plant or Unit (Type Fuel)Company fnvestment Megawatt Ownership Plant Under capabrllty Inleresl ln service consaucnon Mayo Plant (Coat)1 A40" Hams Plam (Nuclear)900" Brunswick Plant (Nuclear)Roxboro Unl!No.4 (Coal)83.83%83.83%1.580 8 1.67%700 87.06'b S4205 S 13.2 1.438.7 7296 100.9 186.7 nol include nuclear tueL costs.srgn target capabrilry.
At December 31.1983, the Company had generated but, not utilized investment tax credits totaling approximately S109 million (including SIO millfon of ESOP credits).The Company also generated a tax loss carryforward estimated at S81 million in 1983 and expected to be utilized in 1984.The Company does not maintain its accumulated depreciation accounts on a separate unit basis ancL therefore, amounts applicable to the Mayo Plant, Brunswick Plant and Roxboro Unit No.4 are not shown above.The Company's share of expenses for the jointly owned units is included in the appropriate expense category in the statements of income.The total gain from the sale of the generating facilities to the Power Agency was S323 milifon net of income taxes and is being amortized to other income over three years beginning October l.1983.In connection with the sale of these facilities.
the Company is obligated to purchase portions (generally starting at 50 percent)of the Power Agency's ownership capacity cnd energy ior the Mayo and Hams uluts.commencing with commercial operation of each unit and declining ratably during the following fifteen-year penod.The minimum payments applicable to Mayo Unit No.I and Hams Unit No.I are presently estimated at S5.561.000.
S5.168,000, S35,2S5,000.
S38.588.000.
and S35,786.000.
for the years 1984 through 1988.respectively, and S210, 195.000 ior the period 1989 through 2000.representing total estimated future minimum payments of S330.583.000 for such capacity.Variable costs of such purchases are primanly tuel costs.maintenance and other operation expenses for the respective units.Contractual purchases from Mayo Unft No.I commenced on iis commercial operation date.March l.1983, and totaled S14800.000 for 1983.8.Commitments and Contingencies (a)Construction and Nuclear Fuel.The Company has incurred substantial commitments inconnectionwith itscon-struction program.Construction expenditures ere estimated to be S1.7 billion and nuclear fuel expenditures S278 million for 1984 through 1986 in connection with that program (b)Leases.Rental commitments for operating leases and for unrecorded capital leases at December 31.1983 cre not material with respect to the Company's financial position or results ot operations.(c)Insurance.
The Company is a member of Nuclear Mutual Limited (NML).established to provide insurance coverage against property damage to insured's nuclear generating facilities.
The Company is insured thereunder for S500 mtilion at the Brunswick Plant and S500 million at the Robinson Plant.The Company cufTently would be subIect to maximum relrospecuve prerruum cssessments of cppmxl-mately S65 million in the event losses at insured factltttes
~.exceed premiums.reserves.reinsurance and other NML resources.
which are at present more than S300 mil!ton.The Compar.y is also a member of Nuclear Electrc'nsurcnce Limited (NEIL).initially established to provide nsurcnce coverage cgains: incremental costs of reclace-ment power resulting!rem prolonaed accider.tal out"ges of inembers'uclear generating units The Company is insured thereunder for S2.500.000 per week for 12 months (staning 26 weeks after the outage)and for Sl.250.000 per week for!he next 12 months for each operating nuclear aenerating unit.NE!L also provides decontamination and excess property insurance for nuclear generating facilities The Company is insured thereunder for S435 million excess ot 5500 mt!lion at both its Brunswick and Robinson plants.The Company currently would be subject to retrospective premium assessments of up to approximctely S23 million with respect to the incrementcl replacement power costs coverage and S!5 million with respeci to the decontamina-tion cnd excess property coverage in the event covered expenses at insured facilities exceed premium reserves.reinsurance and other NEIL resources.
The Company's public liability for a nuclear incident is protected up to the maximum limit on pub!ic liability claims pursuant to the Pnce-Anderson Act.which is S580 million for ecch occurrence.
through conventional insurance pooh cnd through an industry retrospective assessment program.In the event that public hability claims from an insured nuclear incident exceed the pnmary tinancicl protection provided by the insurance pools.which is currently S160 million.the Company would be sublect to a pro rata cssessment of up to a maximum of S15 million with respect to cny single nuclear inc:dent and cn aggregate maximum of S30 million within any ca!endar year~~(d)Claims.There are certain claims pending cgainst'he Compcny!n lhe opinion of the Company.Iiabihties.
!f ny.ansing!rom these claims would not have a matenal ettect on the tinanc:cl position or results of operations ct the Company (e)Nuclear Fuel Disposal Cost.The inc!ear"..'cste Policy Act of 1982 esi bltshes that the lederai aover."..en'.is responsible for the d.'scosal o!spent nuclecr tue!cn"'.nc: the owi.ers anc ope.=:oa ot ruclecr aenerctmg f'ac:!:ties will make pa trments to cover those costs.At Dece...ber
': 983.the net remcining cccumulcted provisicns rcr'.he esto..=,ea costs ot such dtsposai ccsts tncuneed through Apn!6.1983 ere S29.267.000 less than!he required pxyrr en'.s or 588 mtI!tcn Amounts attributcb!e to wholesale customers!otating approximctely SIO mtilton.previously rea"red to be refunded.may be recovered in proceedtn-o ceto.e'.."ie FERC.The Company expects to prospective!v increcse:!s charges to operattoris for tuel expense over c recscn"c.'e period ot time for lhis change in the esnmaied ccs'.s ters~"en'.tuel disposal The Com"any must sele,"y.'une 3 from one of several payment optic".~tor ine ccsis mc-..e" through Apnl b.1983.Costs incurred therec"er.e pc:d quarterly.(f)Hanis Units Nos.3 and 4.In Decemcer!"8: '"--Company eliminated these u..its!rom..s cc."s:."-.:";.program.Pursucnt to regulctory authcr:z=iions.
the Company begat.amortizing in Ju!y 1922 the ccsis associated with these units and is recoverng the cos'.s throuah revenues Amounts amortized io operciing expenses totaled S13.251.000 in 1983 and S6.95a.000 m 1982 9.Other Rate Matters Operating revenues increased S70.616.GGO in 1983 over 1982 cnd S140.548,000 in 1982 over 1981, ct:ncutccle to general rate increcses placed in!o ettec'i s:r.ce 1980~so iiicluded in revenues.representing tuel cost billings ccove c base cost of fuel (as defined for ecci: rc'.en:ck:na lunsdic!ion).is S40 617 GCO lor 1983.Sb).o45 GGO ior 1982 cnd S27.327.000 for 1981 Summary of Quarterly Financial Data (Composite Transactions-Reported Prices Traded on the New York and Pacific Stock Exchanges)
First Second Third Fourth aurarer uruaaer uruaaer Quarter (Amount tn thoutandr ezaept tOr per rhaie data)1982 Operating Revenues.........""" Operaimg!ncome
......"".""" Net tncoine.Earnings Per Common Share.......Dividend Paid Per Common Share..Common Stock Pnce Per Ware: High Low.S405.559 90.!34 8!ASS!.24.60 23!9&S359,935 44.750 46 JO 22'!9'-t S402.342 57.768 55.232 76.60 22't 19 S370.329 55.473 n2 7'tn 60 2!:r!8:1 1983 Operating Revenues..............
Operaung!rcoine
................
Net Income.Eammgs Per Common Share......Dividend Paid Per Con mon Share.Coinmon Stock Price Per Share." High.Low.S416.638 8!.359 78A60!.13 ,60 23 20..$36!,370 49.853 44A38.55 60 22/0 21 7 5449.720 69.540 60.182 80 60 23'i 20-'t S420A55 63.204 56 189 72 63 25~21".
Supplemental Inflation Adjusted Data (Unaudited)
The data.as reported in the pnmary financial statements.
are based on actual.nominal.historical costs.However.dunng penods of significant cl.anges in general price levels.that nominal dollar information becomes distorted and fails to rellect real economic costs or value.The-onvenhonal basis does not account for the event of;flation.i.e,.
variations over time in the purchasing power or alue of the dollar.In an effort to provide financial information about the elfects of changing pnce levels.the Financial Accour.ting Standards Board issued Statement No.33.Financial Reporting and Changing Prices.in September 1979 This statement requires most larger companies to disclose (among other things)certain significant historical cost data in constant dollars represented by the average level dunng the year of the Consumer Price index for all Urban Consumers (CPI-U)and current cost information concerning the measurement of assets and the expiration of asset values.The constant dollar information on the following pages'eflects the nominal hlstoricat costs and prices restated by applying the CPI-U in conformity with Statement No.33.The current cost information on the following pages.etlects changes in specific pnces of plant from the date the plant was acquired to the present and differs from constant dollar amounts to the extent that specific prices have increased more or less rapidly than pnces in general.The current cost of property.plant and equipment.
which includes land.land nghts.Intangible plant.property held for tuture use and construction-work-in progress.represents the esnrnated cost of replacing existing plant assets and was determined pnmanly by indexing the surviving plant by the Handy-Whitman fndex of Public Utility Construction Costs.The current cost of nuclear fuel was determined by recent voice pnces, The current year's provision for depreciation rd amortization was determmed by applying!he mpanys depreciation and amortization rates to the dexed'current cost an:ounts Under ratemaking practices established by regulatory commissions.
the Company can recover through revenues only the onginal cos!(htstoncat costfnomiral dollars)deprec:ation.
Therefore.
the increase m the dollar amount for the cost of plant (stated in either htstoncat cost/constant dollars or current cost)over the onginat cost is deemed rot presently recoverable and.therefore.
must be reflected as a"reduction in assets to net recoverable cost." To further rellect the economics of regulation.
the reduction in asset"cost" is offset to the extent that the plant iis ffnanced from sources that have a fixed.or contractural.
rate of return and claim against assets of the Company.Under present ratemaking practices.
the Company can recover through revenues the contractual rate of return for such capital and.therefore.
is able to effectively recover the fnflation impact (purchasing power gain or loss)on such capital to the extent reflected iii the annual cost rate, Any holding gain associated with such capital (moretcry liabilities) fs therefore, not realizable and is ar.offset agatra the"reduction in assets to net recoverable cost.-The treatment given herein to the holding gains on monetary liabilities recognizes that prices charged by the Con.pcny are designed to recover for such capital no more than any inflation costs factored mto the contractual annual cost rate.Thus.the purchasing power adjustment to the tangible assets.which is not realizable and is wntten off.cs well as'.he increased operating expenses.resu!ts in no fi.".ancial!oss;o the owners of the Company (the common shareholders) lo the extent of the leverage financing.
This information should be mewed as an esnmate ct the approximate effects of inflancn.rather than a precise measure.The statement of mcome.adlusted for changmg pnces reflects adjustments only with respect to electrc utility plant-the area of the Company most affected by intlation.
All other items are considered to have been etteciively tr nsacted at average I983 once levels.and theretore.
ao not require adlustment Statement of Tacome from Continuing Operations Adjusted for Changing Prices for the Year Ended December 31, 1983 As Reported in the Primary Statements Constant Dollar Average 1983 Dollars Current Cost Average 1983 Dollars Operating revenues (In Thousands)
S1.647.183 S1.647.183 S1.647.183 Operating expenses: Operation and maintenance:
Fuel for generation Other.Depreciation and amortization Taxes other than on income.Income tax expense Total operating expenses 517.625 440.522 148.342 114.29S 162A43 1.383.227 524.411 440.522 251.059 114.29S 162A43 1A92.730 534ABB 440.522 257.747 114.295 162A43 1.509.495 Operating income Other income-net 263.956 132.482 154.453 132.482 137.688 132.482 Income before interest charges..Net interest charges..Income from continuing operations (excluding reduction to net recoverable cost)396.438 157.169 286.935 157.1o9 270.170 157.169 S 239.269 S 129.766'113.C01 Other adjustments to reQect the effects of changing prices: Increase in specific prices (current cost)of property.plant and equipment held during the year"....~.....
~....Increase (reduction) in assets to net recoverable cost S (48.233)S 63 908 154.692 Effect of increase in general price level..........,.
Excess of increase in general price level over increase ln specific prices atter reduction to net recoverable cost~250.0oB}S (31.458)Adjustment for purchasmg power loss by net monetary liabilities
..........
S 112.342 S 112.342'tncludrng the reducrron in assets lo nel recoverable cost.rncome rrom conrrnuing operalrons would have been sst,533,"Ar December 3l.1983 currenr cosr ol properry.plant and eaurpmenr.
nel ol accumulated deprecrauon was Sr}.798.429.
wrule histoncal ccst or ner cost recoverable through deprecrarton was$4.521.205.
Five Year Comparison of Se1ected Financial Data Adjusted for Effects of Changing PxicesYear Ended December 31, 1983 l982 1981 1980 1979 (In Millions of Average 1983 Dollars, Except for Per Share Amounts)Operating revenues 81.647.2 S l.587.7 S I A71.9 S 1.300.5 S1.270.8 Historical cost information adjusted for general fnQatton: Income from continuing operations (excluding reduction in assets to net recoverable cost)Income from continuing operations per common share (after preferred stock dividend requirements and excluding reduction in assets to net recoverable cost)Net assets at year-end at net recoverable cost 5 129.8 S 120.5 S I I 7.3 S 92.4 S I 28 3 S 1.40 S l.29 S 1.34 S I 08 S 2 20 S1.559.7 Sl.492.2 S1.446.7 Sl.424 3 S'I.=o 6 Current cost information:
Income from continuing operations (excluding reduction in assets to net recoverable cost)Income from continuing operations per common share (after preferred stock dividend requirements and excluding reductton in assets to net recoverable cost)Net assets at year-end at net recoverable cost S 113.0 S 102.2 S 104.7 S 79 7 S 1130 S 1.13 S 098 S 1.10 S 0.82 S 1.82 S1.559.7 S 1A92.2 S 1.446,7 S IA24.3 S1.356 6 General information:
Adjustment for purchastng power loss by net monetary liabilities Cash divtdends declared per common share Market pnce per common share at year-end CPI-U-average-year wnd$2A6 S 2A8 S 2.54 2.66 S 2 82 S 21.63 298.4 303.5 S 21.94 289 I 292A S 21.47 272,4 281.5 S~094 S 2482 2468 2i74 258 4 2299 S 112.3 S I I6.9 S 266.9 S 368A S 373 9 CAROLINA PO..LIGIIT COHPANY SCHESfLE V-UTILITY PLANT For the Year Ended Decelaher 31, 1983 COLUHM A Classification Electric utility plant other then nuclear f'uel (at original cost): In Service: Intangible plant (Note 1)Production plant Transmission plant Distribution plant General plant COLUHN 8 Balance at Beginning of'eriod$177,329 1, 737,423,357 445,247,587 739 8 1 87~396 90 817 674 COLQfN C I Add it ions ot Cost$521 9 491 5911 94,492,331 66,854,702 11 290 363 COLUHN D Retirements
$14, 794, 742 1,744,221 9,442,922 3 290 190 COLON E Other Changes-Debits/Credits
$5484348825 cr 2,661,619 143,043 2 812 cr.COLUHN F Balance at Close of Period$177,329 2818986859701 540,657,316 796,742,219 98 815 035 Electric utility plant in service 3,012~853~343 694 9 I 29~307 29, 272,075 51,632,975 cr, 3862680778600 Electric plant acquisition adjustment Held for future use Electric plant purchased or sold Construction work in progress 1,790,714 10,350,091 4,496,639 1 994 905 675 2, 551,907 2,551,907 484968639 32 054 196 cr.cr.1,757,399 265 300 843 cr.3,548,113 12,901,998 0 1 697 550 636 Total electric utility plant other than nuclear fuel Nuclear fuel (at original cost)Total electric utility plant including nuclear fuel 5,024,396,462 660,130,379 29,272,075 315,176,419 cr.5834080788347 231 518 038 48 407 041 8 368 347 6 836 0!i3 cr.264 II01 489$5 255 914 5llti$708 618 220$37 640 422$322 012 462 cr.$5 604 879 836$6380448427 cr.253,711,533 cr.1,757,399 Ill 858 cr.'$315 176 419 cr.NOTES l.In conformity with the system of'ccounts prescribed by reyslatory authority, intangible assets are included in utility plant, the amount thereof being set forth above, and Schedule VII is oaitted.2.The net change in Column E represents the following:
Electric utility plant other than nuclear fuel: Original coot of property sold to Power Agency Transfer of Harris Unit No.2 to Deferred Debits Electric Plant acquisition adjustment
-VEPCO Transfer between utility and non-utility property, etc.Total Nuclear fuel: Original cost of property sold or subsequently transferred to Power Agency, and adjustments related thereto Hiscellaneous adjustment" Tbtal$888429755 cr.2 II06 712 6,nx6;nrem~~~
CAflO If II (<(L ICIII CO)IPANY SCIIEDIII.f:
V-IITILITY PLNII for the Yea<En(fed I)ecomf>er 3l, 1982 coLNN A CauSe 0 COI.IRIN C I COLIIHN D COLIIHN E COLO)IN f Classification flalance at Beginning of I Period h<fdi t ions ol Coot I I IIetirements Oafance at Other Changes-Close of Debits>>'Credits I Period Electric utility plant other than nuclear fuel (at original cost.): In Service: Intangible plant (Note I)Production plant Transmission plant Distr ihut ion plant.Ceneral plant, i77,329 1,017,27 5,020 405,009,391 684,800,709 70 025 241 Electric utility plant, in service 2,985,447,770
$45,216,509 41,206, 349 59,512,354 15 063 690 161,070,902
$5,709,74O 1,201,296 0,122,692'1 724 810 16,030,538
$119,270,432 cr.73,143 2,916,945 1 346 447 cr.ii7,634,791 cr.l77,329 1,737,423,357 445,247,507 739,107,396 90 817 674 3)012)053)343 Electric plant acquisition adjustment field for future use Electric plant purchased or col624 3,002,336 1 854 176 007>73,210 1,414,303 474 917 76?531,506 93,751 cr.334 188 899 cr.1,790,714 10,350,091 4,496,639 1 994 905 675 Total electric utility plant otf>er than nuclear fuel Nuclear fuel (at original cost)Tol,ai electric utility plant including r>uc]ear f<<el 4)054)336)745 254 477 419 630)204,190 1(450 n,nc 16)830)530 451,305,935 cr.19 U7 429 20 272 A36 cr.5,024,396,462 231 510 038.$5 1A(l 014 164$654 734 274$35 975,967$471 657 971 cr.$5 255 914 500 (Note 2)NOIIS 21$450)943)059 cr.442 076 cr.$45(305 9'll cr.I nial In conformity with the system of accounts prescribed l>y ren<rlatury authority, intanolhie assets are included in ut.ility plant, the amount thereof beinn set forth above, and Schedule Vl I is o<r>f t ted.The nct chan<le in Col<<r(>n E ref>resents the following:
Elecl.ric ulilify planL other thon nuclear f'uel: Orlrfinal coal of'roperty soirf to Power Arfency'f roost or holwoen utility o>>>I non-uliliI y properf y)elc.N<>cfear I'uo I: Oriqir>of coal of properly".old or suhsequenLly trro<sferre<I I.o f'ower h<)er>cy);>r>d o<f just>>ants relatenous arf j<>ortmonl.s Total$20)325)607 cr.53 571$7(l 272 ((Ai cr.
CAttOI.Ubf'It&LICIll COHPANY SCftfl)llt.t V-UflLITY PLANT f'r t,he Year Ended Dccenhrrr 31, 1981 COLUHN A COLUfe 0 I COLttHN C COLUHN D COL tlHN E I COI.IIHN F Classification Balance at, I 8eqinning of I Arlditinns I Period I at Cost I Retirements Balance at, Other Changes-I Close nf'ebits/Credits I Periort Electric utility plant other thon nuclear fuel (at original cost): In Service: Intangihie plant (Note 1)Production plant Transmission plant Dist ribut ior$plant Ceneral plant 177,329 1$775$613$683 375,072,239 645,726,714 66 505 674 f 39,439,450 31,934,619 51,366,379 13 403 077 347,223 cr.f 1,874,664 2,631,888 714,421 9$357 9600 2 9054 9704 cr.I 770,999 192 511 cr.177,329 198l7$275$020 40S,089,391 604,080,789 70 025 241 Eiectric ut.i I ity plant in service 2,863,175,639 136,1439525 1394139264 458,130 cr.2,98S,447,770 Electric plerrt acquisition adjrrstmcnt Held for future use I iectric plant prrrctrased or sold Construction work in proqress 1,259,208 1D,035,644 I 616 5I2,736 254,030 390029336 4fl9,f127 765 80,950 171 363 694 cr.1,259,208 10,370,624 3,082,336 I 054 176 807 l'otal elect.ric rrtiiity plant, other t.han nuclear fuel Nuclear fuel (nt.oriqinal cost)lotal electric util it.y plant, inciurlirrg r$$$ciear Fuel 4,490,983,227 218,466 220 54t39507,656 36,222 905 13,413,264 171,740,874 cr.113 567 9II 139 cr.4 9 8 54~336 9 745 254 477 419$4 7fl9,449 447$504 73fl 561 513,526,031
$171 039 013 cr.$5 IIIII 014 164 NOlf S (Not.e 2)2.$I 71,203,454 cr.537 420 cr.$171 740 II74 cr.In conformity with the system of'ccounts prescribed by rertrrlut$
$ry authority, intangible assets are 1$$cludcd in uLility plant, the afnfrurrt thereof heinq sct.forth above, and Sct$crbrle Vll is omitted.lire nct.charrqc in Column E represents tfre followinq:
Electric rrtility plant.other thon nuclear frrcl: Transfer of tlarris Units Nos 3 and 4 and.ttrunswick Cootinq Tower to Deferred Debits Transfer between utility and non-utility propcrt.y Total Nuclear frrr:I: Sf)t:rrt fr$el transportaLion charges transf'errcd t o>>rcrnmrlotcd provision for an3ortizatir>$
$of'uclear furl Total 9B 139 cr.$90, l39 cr.
CAROLINA POWER 6 LIGHT COHPANY SCHECULE VI-ACCUHULATEO PROVISIN FOR DEPRECIATION ANO AHORTIZATIN OF ELECTRIC UTILITY PLANT For the Year Ended Oecet$1ber 31, 1983 COLUHN.A COLIM B COLIIHN C COLUHN 0 COLUHN E Oescri tion Balance at Beginning of Period Additions (I)I (2))Charged Charged to)to Other Income Accounts Deductions from Reserves (I)(2)I Retirements, I Balance at Renewals, h (Close of'e lacements Other Period Accumulated provision for depreciation of electric utility plant, other than nuclear fuel (Note 1)$792 fl12 456$130 052 201-0-$26 282 05tl$11 532 494$804 250 193 Accumulated provision for amortization of nuclear fuel$131 279 866 53tl 594 010-0-$8 360 347$4 081 741$149 423 796 NOTES l.This accumulated provision is maintained for all electric utility depreciable plant.For statement of the Company's policy with respect to retirements of property, see Note 1 to Financial Statements.
Tho atnounts-in Column D(1)include net salvage credits for retirements.
Column 0 (2), for electric utility plant other than nuclear fuel, made up of$1108130394 for a reserve reversal due to sale of electric plant in service to Power Agency,$509728 for a transfer to the reserve for non-utility property, and$(3319628)depreciation reserve related to purchase of electric plant in service from Virginia Electric and Po~er Ca7$pany;and, for nuclear fuel, is principally related to a reserve reversal due to the sale of nuclear fuel to Power Agency.
CAROLINA POWER h LlliHT COHPANY SolEDULE VI-ACCUHULATED PROVISION FOR DEPRECIATIIIN AND AHORTIZATION OF t.l.ECTRIC UTILITY PLANT For the Year Ended Deceraber 3i, I982 COLUHN A COLUHN B COLUHN C Additions COLUHN D Deductinns from Reserves COLUHN E Descri tinn I Balance at I Beginning of'Period (I)I I I I Charged to I Income I (2)Charged to Other Accounts I (I)(2)Retirements, Renewals, 5 Re lacements Other I I Balance at I Close of I Period Accumulated provision for depreciation ot electc ic utility plant otl$ec than nuclear fuel (Note I)$717 799 542$114 154 540-0-$17,797 846$22 143 780 5792 012 456 Accumulated pcovis inn for amortizaLion of nuclear fuel$144 791 161$13 536 061-0-$19 137 429$7 909 933$131 279 866 NOTES i.This accumulated pcovision is maintained for all electcic utility depreciable plant.For statement of the Company's policy with respect to retirements of properLy, sec Note I to financial Statements.
The amounts in Column D(l)include net salvage credits for retirements.
Column D (2), for electric utility plant other than nuclear fuel, made up of$2289595195 foc a resecve cevecsal d<<e to sale of electric plant in service to Powec Agency,$20,311 foe a transfec to the reserve for non-$$tility property, and$(8355726)depreciation reserve related to purchase of electric plant in service from Pineh4jcst8 Incorporated; and, foe nuclear fuel, is principally related to a reserve reversal due to the sale ol n4$cleac fuel to Power Agency.
CAROl.INA PONCR~lllT COHPANY SCHFDOLL Vl-ACClkklLATEO PROVISIRt I'OR DCPRLC)ATlDN ATA AINRl l/ATIW Of fLCCIRIC UTll.lTY l'LANT for tho Year On<lcd Dl.comber>I9 l90l COl.lklN A Descri l,inn I COLllHN 0 I Balance at f Beginning of I Period Cotlklw C Additions (i)I (2)Charqcd t Charged to I to Other Income I Acco$$nts (I)Retirements9 Rene$8als9 h Re$lacements (2)Other COl.llHN D Ded<<ctjons from Reserves COLlk1N f I I I Balance at.(Close of I Period Accumulated provision for depreciol,ion of electric ut i l i ty p lent other than nuclear fuel (Note l)$627,407 874$105 056 155-0-$14 507 109$57 296$717 799 542 Accumulated provision for amortization of nuclear fuel$1M 597 818$58 405 161-0-$115,567$98 2'51$144 791 161 NOTCS i.This accumulated provision is maintained for all electric utility depreciable plant.for statement of tile Company's policy$$ith respect tn retirements of property, see Note l to Financial Statements.
The omou$8to in Column D(l)i$$ciude net salvoqe credits for retire$m1nts.Colu2$A O (2)is a Lransfer to the reserve for non-ul.ility property.
CAROL INA POVI ICNT COHPANY VIII-RESERVES For the Year Ended December 31, 1983 COLUNN A Descri tion COLUNN B Balance at I Beginning of Period COL0W C Addi t ions (I)I (2)I Charged I Charged to I to Other Income I Accounts Deductions from Reserves I I I Balance at Close of Period COLS'COLINN E Reserves, deducted from related assets on the balance sheet-Uncollectible accounts 5 1 756 586 5 2 477 369 Reserves other than those deducted from assets on the balance sheet: Injuries and damages 5)947 293 5 2 217 604 Property ieeereeee reserve 5 4 256 420-0-5 712 882-D-5 4 969 302 Reserve for possible coal mine investment losses'0$-0-532 000 000 5-D-5-0-5 32 IIOO 000 This information is omitted in accordance with Rule 12-13 of Regulation S-X of the Securities and Exchange Commission, since the additions, deductions and balances are not significant.
"" See Note 2 to Financial Statements.
CAROLINA PO'.d LIOIIT COHPANY VIII-RESERVES For the Year Ended December 31, 1982 COLUHN A Descri tion Reserves, deducted from related assets on the balance sheet-Uncollectible accounts COLUHN B Balance at Beginning of Period 5 I 532 729 COLIlHN C Additions (1)I (2)I I Charged I I Charged to I to Other I Income Accounts Deductions from Reserves I I I Balanco at I Close of Period S I 756 586 COLUHN D COLUHN E Reserves other than those deducted from assets on the balance sheet: Injuries and damages 5 I 625 939 5 I 947 293 Proporcy Iooorooce re"cree 5 3 961 291-0-5 295 129-0-5 4 256 420 Reserve for possible refund of revenues, not 5 24 592 951 524 698 860 5 31 520 548 823 904 5 499 427 This information is omitted in accordance with Rule 12-13 of Regulation S-X of the Securities and Exchange Commission, since the additions, deductions and balances are not significant.
CAROLINA POWER&LIGHT COHPANY VIII-RESERVES F'r the Year Ended December 319 1981 COLUHN A Descri tion COLIl%B I I)Balance at Beginning of Period COLUNN C Additions (I)!(2)Charged Charged to I to Other Income Accounts COLUHN D COLUNN E I I I I Deductions I Balance at from I Close of Reserves Period Reserves, deducted from related assets on the balance shee't-Uncollectible accounts 8 1 739 560 5 1 532 729 Reserves other than those deducted from assets on the balance sheet: Injuries and damages 5 1 438 045 5 1 625 939 Property tosoroooe reserve 5 3 473 739-0-5 487 552-D-5 3 961 291 Reserve for possible refund of'evenues, net 5 7 794 531 516 798 420-0--D-5 24 592 951 This information is omitted in accordance with Rule 12-13 of Regulation S-X of the Securities and Exchange Commission8 since the additions9 deductions and balances are not significant.
CAROLINA..I 12$LIGHT COMPANY SCIIEDULE IX-SIIORT-TERH BORROWINGS for the Three Year's Ended December 31, 1903 O'OLUMN A COLUHN 8 COLUHM C COLUHN D COI.UHN E COLUHM F Category of'ggregate short-term borrowin sa Balance at end of eriod Weighted average inter'eot rate Haximum)amount)outstanding I during the cried Average amount during the cried>>>>I Weighted (average"" interes't Irate during the cried For the Year Ended December 31 1903 Bank loans Commercial paper<$$+-0-$153 200 000-0-$17 000 000$I 586 301 9.70"$198 550 OIIO$111 095 969 9.22%For the Year Ended December 31 1982 Bank loans Commercial paper><>5 13 000 000$146 575 000 9.71"$38 00tl OtlO 8.66"$266 400 000 5 I 334 247$216 245 066 2.94~12.86%For the Year Enrled December 31 1981 Bank loans Comtaercis 1 paper>>$5 5 17 000 000$239 250 000 2.65" 5 44 000 000 5 8 706 022 12.14$239 250 IIOO$134 855 793" General terms: TISe outstanding bank loans represented demand notes ot notes due within 20 days after the end of the year.The commercial paper at the end of the period had due dates of up to 104 days after the end of the period.Excluded from aggregate short-term borrowings are miscellaneous notes which had balances at year end for 1981-1983 of Q965596249
$2,6359219 and$29400,230 respectively."a Average computed on a daily weiglSted basis.Includes$I3090009000
($7299059000 oL Decetaher 51, 1903)backe<l by long-term credit facilities to 9/24/86 and classified as long-term debt.
CAROLINA POWER&LICHT COHPANY SCHEDJLE X SUPPLEHENTARY INCOHE STATEHENT INFORHATION For the oars ended December 31 (Thousands of Dollars)Taxes-Other than on income taxes: Ad valorem State and city franchise Federal and state social security Hlscellaneous Total 1983$288296 83, 356 15,467 425 127,544 1982 4 29,117 76 8 707 13,457 404 119,765 1981 S 26,964 70,947 10,713 263 100,887 Less-Amount charged to plant and s25ndry accounts Remainder-charged to operating expenses 13 249 15 445 11 599 5114 295 5104\00 5 92 288 Haintenance and repairs other than amounts set out separately in the statements of income are not significant.
4 i ITEM 9.DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There has been no change of the Company's accountants within the twenty-four months prior to the date of the financial statements set forth in ITEM 8.PART III ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT a)Information on the Company's directors is set forth in the Company's 1984 definitive proxy statement dated April 4, 1984 and incorporated by reference herein.b)Executive Officers of the Company Name Recent Business Ex erience Sherwood H.Smith, Jr.William E.Graham, Jr.49 54 Chairman of the Board, President and Chief Executive Officer, Slay 1980 to present;President and Chief Executive Officer, September 1979;President and Chief Administrative Officer, December 1976.Member of the Board of Directors of the Company since 1971.4 Executive Vice President, May 1982 to present;Executive Vice President and General Counsel, May 1981;Senior Vice President and General Counsel, December 1976.Member of the Board of Directors since 1980.Edward G.Lilly, Jr.58 Executive Vice President and Chief Financial Officer, May 1981 to present;Senior Vice President, Chief Financial Officer, March 1979;Senior Vice President, Chief Financial Officer and Treasurer, September 1978;Senior Vice President and Chief Financial Officer, December 1976.Member of the Board of Directors of Company since 1971.Edwin E.Utley 59 Executive Vice President, May 1979 to present;Senior Vice President and Group Executive for Power Supply, December 1976.Member of Board of Directors since 1982.Charles D.Barham, Jr.53 Senior Vice President and General Counsel, Legal and Regulatory Group, May 1982 to present;Vice President and Senior Counsel, December 1980;private law practice, 1974.
James M.Davis, Jr.Senior Vice President-Operations Support Group, August 1983 to present;Senior Vice President-Fuel and Materials Management Group, December 1980;Vice President and Group Executive-Fuel and Materials Management, May 1979;Manager of Rates and Service Practices, November 1977.Lynn W.Eury Russell H.Lee 46 44 Senior Vice President-Fossil Generation and Power Transmission Group, August 1983 to present;Senior Vice President-Power Supply Group, December 1980;Vice President and Group Executive, May 1980;Vice President-System Planning and Coordination, May 1979;Manager of System Operations and Maintenance, January 1972.Senior Vice President, Customer and Operating Service Group, September 1982 to pr esent;Vice President-Eastern Division, September 1980;Division General Manager, June 1978;District Manager, January 1976.M.A.McDuffie Wilson W.Morgan'9 57 Senior Vice President-Nuclear Generation Group, August 1983 to present;Senior Vice President-Engineering and Construction Group, December 1976.Senior Vice President-Corporate Services Group, May 1979 to present;Vice President-System Planning and Coordination, December 1976.Samuel Behrends, Jr.60 Vice President-Cor porate Regulatory Policy, December 1976 to present.Paul S.Bradshaw 46 Vice President and ControQer, March 1980 to present;Controller and Chief Accounting Officer, December 1976.Alan B.Cutter 49 Vice President-Nuclear Engineering and Licensing, August 1983 to present;Vice President-Nuclear Plant Engineer ing, March 1981;Manager, Nuclear Plant Engineering, April 1980;Manager, Projects Operations with Westinghouse Electric Corporation, October 1976 to April 1980.-63" R.Thomas Dwyer, HI 38 Vice President-Performance Review and Audit Services, May 1983 to present;Manager, Performance Review and Audit Services, September 1978;Audit Manager, Deloitte Haskins 4 Sells until September 1978.Norris L.Edge 52 Vice President-Rates and Service Practices, December 1980 to present;Manager of Rates and Service Practices, June 1979;Assistant Manager, Rates and Service Practices, January 1977.Thomas S.Elleman 52 Vice President-Nuclear Safety and Research, May 1979 to present;Department Head, Nuclear Engineering Department, North Carolina State University, July 1974.B.J.Furr 46 Vice President-Operations Training and Technical Services, August 1983 to present;Vice President-Nuclear Operations, September 1979;Manager of Generation, May 1976.Cecil L.Goodnight 41 Vice President-Employee Relations, May 1983 to present;Manager, Employee Relations, August 1980;Assistant to Vice President-Employee Relations prior to August 1980.P.W.Howe 55 Vice President-Br unswick Nuclear Project, December 1982 to present;Vice President-Technical Services, December 1976.Richard E.Jones 46 Vice President and Senior Counsel, and Manager, Legal Department, May 1982 to present;Associate General Counsel, January 1975.William B.Kincaid 63 Vice President-Materials iVIanagement, November 1979 to retirement date, March 1,'984;Vice President, Power Plant Engineer ing, September 1973.Mendall H.Long 63 Vice President-Special Projects, October 1, 1981 to present;Manager, Fossil Plant Engineering Support, January 1977.
Jack B.McGirt 59 Vice President-Fossil Generation, August 1983 to present;Vice President-Fossil Operations, December 1980;Manager, Fossil Operations, November 1979;Manager of Fossil and Hydro Section, November 1977.Bobby L.Montague 48 Vice President-Planning R Coordination, June 1981 to present;Manager System Planning dc Coordination, May 1980;Director, Project Analysis, July 1978;Manager, Energy Services, December 1976.Albert L.Morris, Jr.59 Vice President-Corporate Communications, December 1976 to present.E.S.Noell 56 Vice President-Transmission, May 1981 to present;Manager, Transmission System Engineering and Construction, October 1976.Sheldon D.Smith 63 Vice President-Nuclear Plant Construction, May 1979 to present;Manager of Power Plant Construction, September 1976.Earl F.Stephenson 59 Vice President-Customer Service Operations Support, December 1976 to present.R.A.watson 50 Vice President-Harris Nuclear Project, August 1983 to present;Vice President-Fuel Department, March 1980;Manager, Fuel Department, May 1977.J.L.Lancaster, Jr.58 Secretary and Manager of Corporate Insurance, July 1973 to present.L.T.Quarles 39 Treasurer, March 1979 to present;Assistant Treasurer and Manager of Tax, Cash, Pensions and Bank Relations, November 1977.
ITEM 11.EXECUTIVE COMPENSATION Information on executive compensation is set forth in the Company's 1984 definitive proxy statement dated April 4, 1984 and incorporated by reference herein.ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT a)The Company knows of no persons who are beneficial owners of more than five percent of any class of the Company's voting securities.
b)Information on security ownership of the Company's management is set forth in the Company's 1984 definitive proxy statement dated April 4, 1984 and incorporated by reference herein.ITEiVI 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information on certain relationships and transactions is set forth in the Company's 1984 definitive proxy statement dated April 4, 1984 and incorporated by reference herein.PART IV ITEiVI 14.EXHIBITS FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-IC.a)1.Financial Statements Filed: See ITEM 8-Financial Statements and Supplementary Data.2.Financial Statement Schedules:
See ITEM 8-Financial Statements and Supplementary Data.
3.Exhibits Filed: Exhibit No.~3a(l)Exhibit No.3a(2)Exhibit No.*3a(3)Exhibit No.*4a(2)Exhibit No.*4a(3)Exhibit No.*4a(4)Exhibit No.*4a(5)Exhibit No.~4a(6)Exhibit No.*4a(7)Restated Charter of Carolina Power 4 Light Company, dated May 22, 1980 (filed as Exhibit 2(a)(l), File No.2-64193).By-laws of the Company as amended March 21, 1984.Resolution of Board of Directors, dated December 8, 1954, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock,$4.20 Series (filed as Exhibit 3a(2)to Form 10-K for year ended December 31, 1980, File No.1-3382)Resolution of Board of Directors, dated January 17, 1967, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock,$5.44 Series (filed as Exhibit 3a(3)to Form 10-K for year ended December 31, 1980, File No.1-3382)Statement of Classification of Shares dated May 7, 1970, relating to the authorization of, and establishing the series designation,-dividend rate and redemption prices for the Company's Serial Preferred Stock,$9.10 Series (filed as Exhibit 3a(4)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock,$7.95 Series (filed as Exhibit 3a(5)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock,$7.72 Series (filed as Exhibit 3a(6)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated October 23, 1973, relating to the relative rights and preferences of the Company's Preferred Stock A,$7.45 Series (filed as Exhibit 3a(7)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated February 22, 1974, relating to the'elative rights and preferences of the Company's Serial Preferred Stock,$8.48 Series (filed as Exhibit 3a(8)to Form 10-K for year ended December 31, 1980, File No.1-3382).
Exhibit No.*4a{8)Exhibit No.*4a(9)Exhibit No.*4a{10)Exhibit No.*4a(ll)Exhibit No.*4a(12)Exhibit No.*4a(13)Exhibit No.*4a(14)Exhibit No.*4a(15)Exhibit No.*4a(16)Statement of Classification of Shares dated March 13, 1975, relating to the relative rights and preferences of the Company's$2.675 Preference Stock, Series A (filed as Exhibit 3a(9)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated September 7, 1979, relating to the relative rights and preferences of the Company's Preferred Stock A,$8.75 Series (filed as Exhibit 3a(10)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated February 20, 1980, relating to the relative rights and preferences of the Company's Preferred Stock A,$9.25 Series (filed as Exhibit 3a(ll)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated August 29, 1980, relating to the relative rights and preferences of the Company's Serial Preferred Stock,$11.16 Series (filed as Exhibit 3a(12)to Form 10-K for year ended December 31, 1980, File No.')-3382).
Statement of Classification of Shares dated September 15, 1980, relating to the relative rights and preferences of the Company's Preferred Stock A,$9.00 Series (filed as Exhibit 3a(13)to Form 10-K for year ended December 31, 1980, File No.1-3382).Statement of Classification of Shares dated May 1, 1981, relating to the relative rights and preferences of the Company's Serial Preferred Stock,$14.00 Series (filed as Exhibit 3a{14)to Form 10-K for year ended December 31, 1981, File No.1-3382).Preferred Stock Purchase Agreement dated October 23, 1973 relating to Preferred Stock A,$7.45 Series (filed as Exhibit 4a{l)to Form 10-K for year ended Decembe~31, 1980, File No.1-3382).Preferred Stock Purchase Agreement dated September 1, 1979 relating to Preferred Stock A,$8.75 Series (filed as Exhibit II-A to Form 10-Q for Quarter Ended September 30, 1979).Preferred Stock Purchase Agreement dated February 18, 1980 relating to Preferred Stock A,$9.25 Series (filed as Exhibit II-A to Form 10-Q for Quarter Ended March 31, 1980).
Exhibit No.*4a(17)Exhibit No.<<4b(18)Exhibit No.4b(19)Exhibit No.4b(20)Exhibit No.4b{21)Preferred Stock Purchase Agreement dated September 15, 1980 relating to Preferred Stock A,$9.00 Series (filed as Exhibit 4(a)to Form 10-Q for Quarter Ended September 30, 1980).Mortgage and Deed of Trust dated as of May 1, 1940 b tween the Company and Irving Trust Company and Frederick G.Herbst (D.W.May, Successor), Trustees an e e~~7 the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No.2-64189);and the Sixth through Thirtieth Supplemental Indentures (Exhibit 2(b)-5, File No.2-16210;Exhibit 2(b)-6, File No.2-16210;Exhibit 4(b)-8, File No.2-19118;Exhibit 4{b)-2, File No.22439;Exhibit 4(b)-2, File No.2-24624;Exhibit 2{c), File No.2-27297;Exhibit 2{c), File No.2-30172;Exhibit 2(c), File No.2-35694;Exhibit 2{c), File No.2-37505;Exhibit 2(c), File No.2-39002;Exhibit 2(c), File No.2-41738;Exhibit 2(c), File No.2-43439;Exhibit 2(c), File No.2-47751;Exhibit 2(c), File No.2-49347;Exhibit 2(c), File No.2-53113;Exhibit 2(d), File No.2-53113;Exhibit 2(c), File No.2-59511;Exhibit 2(c)File No.2-61611;Exhibit 2(d), File No.2-64189;Exhibit 2(c), File No.2-65514;Exhibit 2(c), File No.2-66851;Exhibit 2(d), File No.2-66851;Exhibit 4(b)-l, Pile No.2-891299;Exhibit 4(b)-2, File No.2-81299 and Exhibit 4{b)-3;File'o.2-81299.Thirty-first Supplemental Indenture dated as of iAIarch 15, 1983.Thirty-second Supplemental Indenture dated as of March 15, 1983.Thirty-third Supplemental Indenture dated as of December 1, 1983.Exhibit No.4b(22)Thirty-fourth Supplemental December 15, 1983.Indenture dated as of Exhibit No.*10a(l)Exhibit No.*10a{2)Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power R Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a)(1)to Form 10-K for year ended December 31, 198), File No.1-3382).Operating and Fuel Agreement dated July 30, 1981 between C li a Power dc Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, toge ether with resolution dated December 15, 1981 changing name to"69-Exhibit No.*10a(3)Exhibit No.*10a(4)Exhibit No.*10c(1)Exhibit No.10c(2)Exhibit No.*10c(3)Exhibit No.*10c(4)Exhibit No.10c(5)Exhibit No.12 Exhibit No.24a Exhibit No.24b North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10a(2)to Form 10-K for year ended December 31, 1981, File No.1-3382).Power Coordination Agreement dated July 30, 1981 between Carolina Power 2 Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency and amending letter dated January 29, 1982 (filed as Exhibit 10a(3)to Form 10-K for year ended December 31, 1981, File No.1-3382).Amendment dated December 16, 1982 to Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power 2 Light Company and Power Agency (filed as Exhibit 10a(4)to Form 10-K for the year ended December 31, 1982, File No.1-3382.)Directors Deferred Compensation Plan effective January 1, 1982 as amended January 1, 1983 (filed as Exhibit 10c(1)to Form 10-K for year ended December 31, 1981 and Exhibit No.10c(4)to Form 10-K for the year ended December 31, 1982, File No.1-3382.)Supplemental Executive Retirement Plan effective January l~1984.Retirement Plan for Outside Directors (filed as Exhibit 10c(3)to Form 10-K for year ended December 31, 1981, File No.1-3382).Executive Deferred Compensation Plan effective May 1, 1982 and amendment thereto effective January 1, 1983 filed as Exhibit No.10c(5)to Form 10-K for year ended December 31, 1982, File No.1-3382.)Senior Management Deferred Compensation Plan.Computation of Ratio of Earnings to Fixed Charges.Consent of Deloitte Haskins dc Sells Consent of Paul Weir Company Incorporated
- Incorporated her ein by reference as indicated.
(b)Reports on Form 8-K filed during or with respect to the last quarter of 1983: Date of Reoort Item Re orted October 13, 1983 October 21, 1983 Item 5.Other Events Item 5.Item V.Other Events Financial Statements, Pro Forma Financial Information and Exhibits.(Filing included Interim Financial Statements for the quarter ended September 30, 1983).November 30, 1983 Item 2.Item 5.Item V.Acquisition or Disposition of Assets Other Events Financial Statements, Pro For ma Financial Information and Exhibits (Filing included no financial statements).
December 16, 1983 Item 5.Other Events Item 7.Financial Statements, Pro Forma Financial Information and Exhibits (Filing included no financial statements).
December 21, 1983 Item 5.Other Events Item 7.Financial Statements, Pro Forma Financial Information and Exhibits (Filing included no financial statements).
January 16, 1984 (for the month of December, 1983.)Item 5.Other Events SIGNATURES Pursuant to the requirements of Section 13 or 15(d)of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 23rd day of March, 1984.CAROLINA POWER 8(LIGHT COMPANY Registrant By/s/Paul S.Bradshaw Paul S.Bradshaw Vice President and Controller Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
~Si ature/s/Sherwood H.Smith Jr.(Sherwood H.Smith, Jre Chairman of the Board, President and Chief Executive Officer)Title Principal Executive Officer and Director Date/s/Edward G.Lill Jr.(Edward G.Lilly, Jr.Executive Vice President)
Principal Financial Officet and Director/s/Paul S.Bradshaw Paul S.Bradshaw Vice President and Controller)
Principal Accounting Officer/s/Daniel D.Cameron Sr.Daniel D.Cameron, Sr./s/Felton J.Caoel (Felton J.Capel)Director Director March 23, 1984 George H.V.Cecil Director/s/Charles W.Coker Jr.Charles W.Coker, Jr.)Director/s/William E.Graham Jr.William E.Graham, Jr.Director iVIargaret T.Harper)Director
~si ature/s/L.H.Harvin Jr.L.H.Harvin, Jr.)Title Director Date (Karl G.Hudson, Jr.)Director John G.Medlin, Jr.Director March 23, 1984/s/A.C.Monk Jr.A.C.Monk, Jr.)Director Horace L.Tilghman, Jr.Director/s/E.E.Utlev (E.E.Utley)Director 0
APPENDIX C AUDITED FINANCIAL STATEMENTS OTHER FINANCIAL INFORMATION North Carolina Eastern Municipal Power Agency (Taken from Appendix E of North Carolina Eastern Municipal Power Agency's March 1984 Official Statement) rnst W inney APPENDIX E 1100 Branch Banking&Trust Buildinti Raleigh, North Carolina 27601 919/833-7301 Officer and Board of Commissioners North Carolina Eastern Municipal Power Agency Raleigh, North Carolina We have examined the balance sheets of North Carolina Eastern Municipal Power Agency as of December 31, 1983 and 1982, and the related statements of revenues and expenses and changes in fund balance (defici)and changes in financial position for the years then ended.Our examinations were made in accordance with generally accepted auditing standards and, accordingly, included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
In our opinion, the financial statements referred to above present fairly the financial position of North Carolina Eastern Municipal Power Agency at December 31, 1983 and 1982, and the results of its operations and the changes in its financial position for the years then ended, in conformity with generally accepted accounting principles applied on a consistent basis.ERNST&.WHINNEY Raleigh, North Carolina March 2, 1984 NORTH CAROLINA EASTERN MUNICIPAL POWER AGENCY BALANCE SHEETS (Thousands of Dollars)ASSETS 1983 December 3I 1983 UTlLITY PLANT-Notes 6 and M'Electric plant in service (net of accumulated depreciation
-1983$14,105;1982$3,089)Construction work in progress Nuclear fuel (net of accumulated amortization
-1983$5,378;1982 SPECIAL FUNDS-INVESTED ASSETS-Note N Construction fund.Bond fund.Reserve and contingency fund Decommissioning fund..Special reserve fund.CURRENT ASSETS Invested funds-Note N Revenue fund.Operating fund Term-loan fund Supplemental fund Participant accounts receivable Fossil fuel stock interest receivable
.Prepaid expenses..DEFERRED DEEtTs-Notes B, C, D and E VEPCO compensation payment.Development costs.Unamortized debt issuance costs Cancelled nuclear unit Nuclear fuel disposal fees Net costs to be recovered from future billings to participants
..........
ToTAL AssETs$366,689 369,033 31,792 767,514 88,096 230,647 8,312 1,458 1,144 329,657 44,538 20,238 3,885 19,195 87,856 18,195 6,126 6,609 333 119,119 14,770 9,234 32,628 53,937 9,048 57,752 177,369 51.393.659
$189,320 394,872 17,259 601,451 506,845 213,798 8,072 570 1,091 730,376 7,306 4,053 5,556 21,521 38,436 13,549 3,990 10,938 223 67,136 15,158 7,310 33,535 46,462 102,465 51.501.428 See notes to financial statements E-2 NORTH CAROLINA EASTERN MUNICIPAL POWER AGENCY BALANCE SHEETS thousands of Dollars)LIABILITIES AND FUND BALANCE December st 1982 LONG-TERM DEBT Revenue bonds payable-Note F.Term loans payable-Note H Less: Unamortized discount.SPECIAL FUNDS LIABILITIES Construction fund payables-Note E..Term loans payable-Note H Accrued interest on bonds CURRENT LIABILITIES Accounts payable Accrued taxes.Accrued interest on term loans Miscellaneous current and accrued liabilities
.FUND BALANcE (DERcIT)-Note 0.CohIMITMENTs AND CGNTINGENcIEs
-Notes I and L$1,300,000 13,597~4),319 1,272,278 (119)26,403 76,523 102,807 13,137 2,397 1,508 1.650 18,692~118)$1,300,000 25,000~42,380)1,282,420 984 137,000 64.196 202,180 10,922 1,952 1,908 1.132 15,914 914 TOTAL LIABILITIES AND FUND BALANCE$1,393,659$1.501.428 See notes to financial statements E-3 NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY STATEMENT OF REVENUES AND EXPENSES AND CHANGES IN FUND BALANCE (DEFICIT)(Thousands of Dollars)Ycl)r Ended December 31 Operating Revenues Sales of electricity to participants
-Note J Sales to utilities 1983$187,731 14,861 202,592 1983$129,967 129,967 Operating Expenses Operation and maintenance Fuel Power Coordination Services: Purchased power Transmission and distribution Other 106,295 15,643 478 107,900 10,441 357 17,575 7,926 25,187 4,312 Administrative and general Amounts in lieu of taxes.....
N.C.gross receipts tax.Depreciation and amortization Nr T OPFR niNo INcob!E (DErtcIT).Interest Charges and Credits Interest expense Amortization of debt issuance costs.Investment income Net interest capitalized
-Note M Add net costs to be recovered from future billings to participants-Note D.ExcEss (DEFIclENcY) or.REYENUEs ovER ExPENsEs Fund balance (deficit)at beginning of period FUND BALANcE (DEFIcIT)AT END oF PERIQD-Note 0................
~122,416 7,620 949 11,154 11,611 196,512 6,080 157,296 2,265 (54,982)~86.)77 18,402 11,290 (1,032)914 118,698 2,588 221',798 3,592 145.135 (15,168)63,667 910 (31,554)~2.624)30,399 46.492 925~ll)See notes to financial statements NORTH CAROLINA EASTERN MUNICIPAL POWER AGENCY STATEMENTS OF CHANGES IN FINANCIAL POSITION (Thousands of dollars)Ye28r Ended December 31~~I SOURCE OF FUNDS Operations:
'perating revenues.Operating expenses............................
Items not involving funds:, Depreciation and amortization Amortization of nuclear fuel...TQTAL FRoM (UsED IN)OPERATIQNs.........
~Financing and Investments:
Bond issues Term loan.Investment income'.Loan expenses..Items not involving funds: Amortization of debt issuance costs TOTAL FROM (USED FOR)FINANCING AND INVESTMENTS TOTAL SOURCE OF FUNDS USE OF FUNDS Net additions to utility plant.Additions to unamortized debt discount and issuance costs Provision to retire term loans.....:.'...............
Provision for extraordinary nuclear fuel disposal fees..Net increase in other deferred debits~~~~1983$202,592 (196,512)11,611 4,432 22,123 15,000 54,982 (73,384)2,265 (1,137)20,986 181,511 97 26,403 9,048 56,068 273,127 1982$129,967 (145,135)3,592 946 (10,630).1,300,000 137,000 31,554 (61,953)910 1,407,51,1 1,396,881 605,488 76,998 137,000 6.097 825,583 INCREASE (DECREASE)
IN WORKING CAPITAL9 INCLUDING SPECIAL FUNDS~~~~~~~~4~~~~~~CHANGES IN COMPONENTS OF WORKING CAPITAL, INCLUDING SPECIAL FUNDs Increase (decrease) in special funds Increase (decrease) in current assets: Invested funds Accounts receivable
-participants
.Fossil fuel stock.Interest receivable Prepaid expenses.~$252,)41)$571,298 49,420 4,646 2,136 (4,329)110 29,628 13,258 3,990 10,935 211$(400,719)$730,376 Increase (decrease) in special funds liabilities
....~..............
Increase (decrease) in current liabilities:
Accounts payable.Accrued taxes Accrued interest.Miscellaneous liabilities (348,736)(99,373)2,215 445 (400)518 96,595 788,398 202,180 9,988 1,952 1,848 1,132 217,100 INCREASE (DECREASE)
IN WORKING CAPITAL9 INCLUDING SPECIAL FUNDS~~~~~~~~~~~$252,141)$571.298 E-5 NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY NOTES TO FINANCIAL STATEMENTS Note A-General Description North Carolina Eastern Municipal Power Agency (Agency)is a joint agency organized and existing uant to Cha ter 1598 of the General Statutes of North Carolina (Act)to enable municipal electric systems h u h theor anization of the Agency to finance, build,own and operategcne cneration and transmission projects.The Agency is composed of thirty-two municipal electric systems who r'eceive ower and energy through the Agency.All h A's members are participants in the Initial Project, such project being comprised of the t e gency i'units resentl in d'd d h'nterests in three nuclear and three fossil generation
'y L.With the ower commercial operation or under construction by Carolina Power&Light Company (CP&).i p d f m the Initial Pro'ect.together with supplemental purchases of power and energy'mentsofits artici ants, exclusive from CP&L, the Agency provides the total electric power and energy requirements o i s par i'p of power allotments from the Southeastern Power Administration.
The A ency has entered into several agreements with CP&L which'overn the purchase, ownership, ie gency a e tin units in the Initial Project.Under these agreements.
c onstruction operation and maintenance of the genera ing n'P&L th onstruction and operation of the generating units in g y its in which the A ency has un ivi e manages e c an,'f construction ownership interests.
ot an.B h CP&L and the Agency have, the right to challenge the allocation o d'ustment charges fora period exten ing to pri o e d1 1 f th second year after which the challenged payment or a ju was made.The Agency has also entered into agreements with CP&L whereby thc Agency purchases power and ived throu h the Initial Project in order to meet the total requirements of the egyi ex sso hat ecei t roug t e niiao e participants.
e gency as a s.Th A h l o entered into agreements with CP&L and Virginia ec ric a Company or ie~(VEPCO)for the wheeling of power and energy between the Agency an i s par i'p reements with CP&L obligate CP&L to purchase from the Agency power and energy in sp'r ins ecified erccntages o ver a eriod of 16 years)of the Agency's entitlement to such power CP&L b h an ene d rgy from certain units after each has been placed in o p c mmercial o eration.cgan p r nit 1 durin 1983 under terms o t e f h such power and energy from the Agency's entitlement from Mayo Un'g agreements.
t blished and financed under Power System Revenue Bond Resolution No.R-2-82 The Initial Project is esta is e an nance u ution establishes s ecial d ted b the Board of Commissioners(Board) of the Agency.The Resolu ion es a'(Resolution) a opte y e oar sed for costs of ac uisition and construction f d t hold roceeds from debt issuance, such proceeds to be use or cos s qnso o p establishes s ecial funds in which f h I'P'nd to establish certain reserves.The Resolution also e'which o eratin costs, debt service, Initial Project revenues from participants are to be deposited and from w ic op'and other specilied payments are made.The Agency has entered into two power sales agreements with each o p p of its artici ants for supplying the ner re uirements of the participants.
Under the Initial Project Power Sales t the artici ants their respective s ares o ni ia o'"" g cy o p p the Initial Pro'ect are pledged as security for on s issue un er i bli ated to ay its shareofoperatingcostsand debt service a ment ofoperating expenses.Each participant isobligate to pay i ss are t.Under the Su lemental Power Sales Agreements, the Agency sells to each participant t e a i ion's of that rovided by output from the Initial Project.the additional power and energy it requires in excess o t at provi e y Note B-Significant Accounting Patlclcs The accounts of the Agency are maintained in accordance with the Uniform System Basis of Accounting:
The accounts o e of Accounts of the Federal Energy Regulatory Commission, and are in conformi y'y f it with enerall accepted accounting principles.
Electric Plant in erviee: S': All direct and indirect expenditures, including interest charges on debt outstanding net of investment earnings on un s no f ds ot yet expended, related to the Agency's undivided ownership E-6 NORTH CAROLINA EASTFRN MUNICIPAL POPOVER AGENCY NOTES TO FINANCIAL STATEMENTS
-(Continued) interests in four of CP&L's generatin units in co'i s in commercial operation have been recorded at original cost and are eing depreciated (or amortized) on a s r'traight-line basis over the average composite life of each unit's Construction worl'n Pro ress: All dir g: i ect and indirect expenditures, including interest char es on debt outstanding net of investment earnings on funds not et ex ended rcla n ye expen e, rc ated to the Agency's undivided ownership in wo o's generating units under construction are capitalized as Construction
%k'ogress until such time as the'or'in it becomes operational.
units become operational.
Depreciation on a unit w'll b'h i e recognize w en funds not et Nuclear Fue/: All expenditures includin inte g'rest on debt outstanding net of investment earnings on un s not yet expended, related to the purchase and construction of the A enc's undivide I f I o<<h I char ed to fu e nuc ear units are capitalized, amortized on the units of production method and c arged to fuel expense.Amortization of nuclear fuel costs in 1983 and 1982 includes a rovi'nd S222,000, respectively, for estimated disposal costs.bein Deferred Debits: Deferred debits are shown net of accumulated amo t'.D I mor ization.eve opment costs are are bein g amortized on a straight-linc basis over the life of the I't'P'U e ni ia roject.namortized debt issuance costs are eing amortized on a straight-line basis over the term of the debt.Net Costs to Be Rec v Billings to Partici ants are no'p n t amortized but will be recovered thro'ugh future rates (see Note D'.H e e.et osts to e Recovered from Future Unit 2 cancellation costs will be amortize r ized over the life of the corresponding revenue bonds (see Note E~.a es see ote).arris I Fossil Fuel Stac/': Fossil Fuel Stock is stated at cost.1nvesttnentst The Agency is authorized under the Resolution to invest its fund'.S.G securities, Federal a agency securities, securities collateralizcd by securities of the U.S.G i s un s in..overnment a encies bank c r'*, ertificatcs of deposit and other investment securities as allowed in a d o e..overnment or Federal of the Resolution.
a owe in accor ance with provisions Investments arc carried at cost, adjusted I'r amortization of premium or disc h h market value (see Note N).r iscountw ic approximates Taxest Income of the A enc g ncy is exempt from Federal income tax ender Section 115 of the Internal Revenue Code.Under Chapter 159B of the General Statutes of North C I'ort aro ina, t e Agency is exempt from would otherw'per y an ranchise or other privilege taxes.In lieu of property taxes th A e gency pays an amount which tax.the A enc a s to t o herwise be assessed on the real and personal property of the A.I I'e gency.n ieu o a franchise or privilege ower or ener x.e gency pays to the State an amount equal to six percent of the gross rec'f I f eip s rom sacs o electric services.p gy, less such like amounts included in payments to vendors for el t'e ec ric power or energy or related Note C-Vepco Compensation Payment The VEPCO corn to those artici ants rev'O compensation payment represents compensation to VEPCO f I or ear y termination of service par icipants previously served by VEPCO.This payment and its related costs were d f d being amortized on a strai ht-line s s were e erre and are'g-inc basis over 40 years, theexpectcd lifeof the Initial project.The December 31, 1983 balance of$14,770,000 includes the$15,515,000 payment to VEPCO and$33 000 of ca net of S778,000 accumulated amortization.
an, o capitalized interest, Note D-Net Costs to be Recovered from Future Billings to Participants (2 the Initial Pr e Rates Ior power billings to participants are designed to cover"costs" as defined b'I'R ()'oject Power Sales Agreements; and (3)the Supplemental Power Sal A ne y ()t e esolution; A enc's rates wills st ower a es greements.
The b the Resol i g y'y ematically provide for the debt requirements operating fu d d y eso ution and the Power Sales Agreements.
Those"expenses", accordin o n s an reserves as specified Accountin Princi e ose expenses, accor ing to Generally Accepted A r'rinciples(GAAP), which are not included as"costs" under the R I'h P greements are del'erred to such'periods as they are intended to be covered by rates.nnct e'eso ution an t e Power Sales E-7 NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY NOTES TO FINANCIAL STATEMENTS
-(Continued)
Net costs to be recovered from future billings to participants (in thousands of dollars)include the following:
Yc22r Ended Inception to December 31, December 31, 1983 1983 GAAP Expenses Not Included in Charges to the Participants:
Depreciation
..~~~~~~~~~~Amortization of VEPCO compensation payment..............
Amortization of acquisition adjustments Amortization of debt issuance costs.Amortization of development costs Interest costs not capitalizable
.Bond Resolution Requirements Included in Charges to the Participants:
Debt service Investment income not available for operating purposes........
Changes in operating fund working capital requirements
~......Special funds deposits.Reserve and contingency fund valuation Net costs to be recovered from future billings to participants
...$6,834 389 4,182 2,265 206 56,296 70,172 22,885 1,878 (1,252)37,943~2,572)58,882$11,290$8,457 778 5,649 3,175 319 105,845 124,223 22,885 1,927 44,231~2.572 66,471$57,752 Note E-Cancelled Nuclear Unit On December 21, 1983, CP&L's Board of Directors cancelled Harris Unit 2 in which the Agency had a 16.17%ownership interest.The Agency's investment in the unit at the time of'cancellation was$63,783,000.
However, under terms of the Purchase, Construction and Ownership Agreement between the Agency and CP&L, the Agency's ownership share decreases to 12.94%, its load ratio share at the time of closing, since the unit was cancelled prior to commercial operation.
On February 17, 1984, the Agency received$9,846,000 from CP&L, 20%of the direct costs incurred through the cancellation date, for its investment in Harris Unit 2.The receivable for this amount is offset against construction payables.The Agency remains 1iable for 12.94/o of all cancellation costs associated with Harris Unit 2 subsequent to the cancellation date.Cancellation Costs related to Harris Unit 2 will be amortized on a straight-line basis over the life of the Power System Revenue Bonds.Note F-Power System Revenue Bonds The Agency has been authorized to issue Power System Revenue Bonds (Bonds)in accordance with the terms, conditions and limitations of the Resolution.
The total amount to be issued is to be suAicient to pay costs of acquisition and construction of the Initial Project, and/or to comly with other purposes as set forth in the Resolution.
On November 9, 1982, the Local Government Commission of North Carolina approved the issuance of such bonds up to a maximum principal amount of$2,850,000,000; additional Local Government Commission approval must be obtained for the issuance of Bonds in excess of this amount.The Bonds are payable from and secured by the revenues derived by the Agency from its ownership and operation of the Initial Project, after payment of operating expenses, and other moneys and securities pledged under the Resolution.
E-8 NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY NOTES TO FINANCIAL STATEMENTS
-(Continued) 53,000 400,000 Power System Revenue Bonds outstanding at December 31, 1983 (in thousands of dollars)were as follows: Series 1982A 8.75%to 13.00%maturing annually from 1985 to 1998.........$46,000 13.25%maturing in 2002 with annual sinking fund requirements beginning in 1999.......~...............
33,000 13.75%maturing in 2011 with annual sinking fund requirements beginning in 2002............,.........
175,QQQ 10,00%maturing in 2014 with annual sinking fund requirements beginning in 2012 10.5Q%maturing in 2017 with annual sinking fund requirements beginning in 2015.93.000 Series 1982B 9.00%to 12.20%maturing annually from 1985 12.875%maturing in 1998 with annual sinking beginning in 1995 13.125%maturing in 2002 with annual sinking beginning in 1999 13.50'Fo maturing in 2012 with annual sinking beginning in 2003 10.75%maturing in 2/15 with annual sinking beginning in 2013 9.00%maturing in 2017 with annual sinking beginning in 2015 to 1994.........fund requirements fund requirements fund requirements fund requirements fund requirements 24,810 22,970 37,360 262,850 50,000 52,010 450,000 Series 1982C 7.00%to 10.75%maturing annually from 1985 to 1997 11.00%maturing in 2003 with annual sinking fund requirements beginning in 1998.11.25%maturing in 2018 with annual sinking fund requirements beginning in 2004.7.50%maturing in 2019 with annual sinking fund requirements beginning in 2018.54,510 66,450 279,040 50,000 450,000 5 l.300.000 The Series 1982A Bonds maturing in 2017 will be payable at par at the option of the holders on January 1, 1987, or any January 1 thereafter upon notice given by such holders as prescribed.
The Series 1982B Bonds maturing in 2015 will be payable at par at the option of the holders on July 1, 1987, or any July 1 thereafter upon notice given by such holders as prescribed.
Interest on Bonds is payable semi-annually on January 1 and July l.Scheduled maturities of bond issues through 1988 and thereafter (in thousands December 31, 1985.December 31, 1986.December 31, 1987 Decemb r 31, 1988.December 31, 1989 and thereafter Total bonds outstanding at December 31, 1983...............
of dollars)are as follows: S 3,605 3,950 4,975 5,480 1,281.990$1,300.000 E-9 NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGEYCY NOTES TO FINANCIAL STATEMENTS
-(Continued)
Note G-Acquisition and Construction Program The Agency has substantial commitments in connection with the acquisition and construction of the Initial Project.The Agency's agreements with CPEcL specify the purchase of undivided ownership interests in nuclear and fossil generating units presently in commercial operation or under construction by CP&L.COAL-FIRED UNITS Roxboro Unit 4 Mayo Unit I Mayo Unit 2 Total Coal-Fired Capability Commercial O~e 1980 1983 1991 h1aximnm Net Dependable
~Cbilil 700M%705 720 Agcnc Ultimate Ownership 12.94%16.17 16.17 bitcgawatts 90.6M'14.0 116.4 321.0MW NUCLEAR-FUELED UNITS Brunswick Unit 2 Brunswick Unit I Harris Unit I Total Nuclear-Fueled Capability
.Total of All Units.Commercial
~Oli 1975 1977 1986 Maximum Net Dependable C~btlil 790 Miv 790 900 Agencv Ultimate~Ob sbl 18.33%18.33 16.17 iitcgawatts I44.8M'44.8 145.5 435.1 M'56.1M'n April 29, 1983, the Agency completed the purchase of its ultimate ownership interests in three operating units.The present estimate of acquisition and construction costs of the Initial Project indicates that it will require the issuance of$2,500,000,000 of Bonds including bonds presently outstanding.
Any future changes in the construction schedules of those units not yet commercial may affect the costs of such facilities and therefore affect the amount of Bonds to be issued.The Agency and CP&L have obtained from governmental and regulatory agencies and commissions all necessary permits for construction of the Harris and Mayo Units.An operating license for the Harris Unit is required to be issued by the Nuclear Regulatory Commission.
Environmental and other permits for the Harris and Mayo Units must be obtained before such units can be placed in commercial operation.
The Agency and CPttcL are following established procedures in order to obtain such licenses and permits.However, there is no assurance that such licenses or permits will be issued.Note H-Term Loans On December 23, 1981, the Agency entered into a$25,000,000 term loan agreement with several banks.The loan is due and payable on December 23, 1984 and bears semi-annual interest at seventy percent of the prime rate charged by Morgan Guaranty Trust Company.On June I, 1983, the Agency entered into a$15,000,000 term loan agreement with two banks.The loan is for five years, is payable in semi-annual graduated installments beginning on July 31, 1984, and bears interest at seventy percent of the prime rate charged by NCNB National Bank.The proceeds of the term loans were used to finance acquisition and construction costs of the Initial Project, and to finance extraordinary repairs at the Brunswick Nuclear Station.On February 28, 1983, a$137,000,000 term loan was paid in full to the lending bank.
NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY NOTES TO FINANCIAL STATEMENTS
-(Continued)
Note I-Letter of Credit At December 31.1983, the Agency had an unused letter of credit from a bank of$11,900,000 payable to CP&L.The letter of credit is required to be maintained, and to be increased periodically, in compliance with the agreements between CP&L and the Agency.The Agency is required under the terms of the letter of credit agreement to pay quarterly commitment fees, such fees being a percentage of the unused letter of credit (approximately
$2'2,000 per quarter).Note J-Rates The Agency's rates for power and energy billed to participants are designed to cover costs of the Initial Project as well as costs of supplemental power and energy.All rates must be approved by the Agency's Board.All rates except those for the fuel adjustment clause are designed on an annual basis.The Agency is required to review the adequacy of these annual rates quarterly.
If the rates are determined to be inadequate by such a review, revised rates may be adopted at such time with approval of the Board.The fuel adjustment clause is designed to recover (1)the dilferences between the fuel costs incurred in the preceding fuel adjustment period and the projected fuel costs reflected in rates during the same period: and (2)the difference between projected fuel costs expected to be incurred in the following fuel adjustment period and the fuel costs anticipated to be recovered through the base energy-rate during the same period.Note K-Insurance CP&L carries insurance on units in the Agency's Initial Project suflicient to meet regulatory requirements or in accordance with usual utility industry practice.The insurance is carried by CP&L for the benefit of CP&L and the Agency.Note L-Other Commitments The Agency has entered into a contract with ElectriCities of North Carolina, Inc.whereby ElectriCities provides to the Agency, at actual cost, management services as necessary to conduct business.This agreement is for three years continuing through December 31, 1986, and shall be automatically renewed for successive period of three years until terminated with written notice by either party at least one year prior to the end of any contract term.Management fees of$1,640,000 and$1,095,000 were paid to ElectriCities in 1983 and 1982, respectively.
Note M-Capitalized Interest Interest costs of$101,000,000 and$14,088,000 were capitalized as part of the cost of power plants under construction during 1983 and 1982, respectively.
The capitalized interest costs were offset by$14,822,000 and$11,464,000 in interest earned on related unexpended bond proceeds for 1983 and 1982, respectively.
NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY NOTES TO FINANCIAL STATEMENTS
-(Continued)
Note N-Invested Assets All undisbursed bond proceeds not currently required for operations have been invested.The investments are carried at amortized cost.Investment income in 1983 and 1982 includes$356,000 and$341,000, respectively, of realized gains on sales of securities.
December 31 U.S.Treasury Bills U.S.Treasury Notes.Federal Farm Credit Bonds Repurchase Agreements
.Federal Home Loan Bank Notes..FNMA.Bankers'cceptances
.Total Investments Cash.Total Cash and Investments Consisting of: Special Funds.Current Assets.Amortized Cost$63,573 81,717 36,103 94,261 26,924 95,821 21,298 419,697~2,184$417,513$329,657 87,856$417,513 1983 Market Value tThousands or$63,570 82,640 37,270 94,261 27,558 95,709 21,177 422,185~2.1847$420.001 Amortlsed Cost dollars)$46,111 77,712 74,715 206,730 87,211 204,214 68.438 765,131 3,681 1982 Market Value$46,211 81,435 76,805 206,730 93,156 208,429 68.438 781,204 3,681$730,376 38,436$768.812$76L812$784.885 Note 0-Fund Balance (Deficit)The Agency's rates for power and energy billed to participants are designed to match as closely as possible costs of the Initial Project, as well as costs of supplemental power and energy during the rate setting period.To the extent that expenses incurred vary, from Agency estimates, there will be a deficiency or excess of revenues to meet such expenses.Such deficiency or excess of revenues is taken into consideration when designing rates for the immediately following rate setting period.For the year ended December 31, 1983, there was a revenue deficiency of$1,032,000, of which$914,000 was covered by the Fund Balance excess at December 31, 1982, resulting in a Fund Balance Deficit of$118,000 at December 31, 1983.In anticipation of a Fund Balance deficit at December 31, 1983, the Agency budgeted$466,000, the expected amount of the deficit when the budget was prepared, to be recovered through rates during 1984.
Ernst EcWhitiney 1100 Branch Banking 8 Trust Building Raleigh, North Carolina 27601 919/833-7301 Officers and Board of Commissioners North Carolina Eastern Municipal Power Agency Raleigh, North Carolina Th e audited financial statements of the Agency and our report thereon are presented in the preceding section of this report.The information presented hereinafter is for purposes of additional analysis and is not required.for a fair presentation of the financial position, results of operations, changes in financial position or changes in fund balance (deficit)of the Agency.Such information has been subjected to the auditing procedures applied in our examination of the financial statements and, in our opinion, is fairly stated in all material respects in relation to the financial statements taken as a whole.ERNST&iVHINNEY Raleigh, North Carolina March 2, 1984 E-13 NORTH CAROLINA EASTERN MUNICIPAL POPOVER AGENCY SCHEDULE OF REVENUES AND EXPENSES-BOYD RESOLUTION AND OTHER (Unaudited)
For the years ended December 31, 1982 and 1983 (Thousands of dollars)Bond Resolution Initial~Pro ect 1983 Total Bond Supplemental Resolution and Other'nd Other Bond Resolution Initial~Pro ect 1983 Total Bond Supplemental Resolution and Other'nd Other REVENUES Sales of electricity to participants
..Sales to utilities.................
Investment revenue available for operations
.TOTAL REVENUES............
EXPENSES Operation and maintenance
.......Fuel.Power coordination services: Purchased power.........'.....
Transmission power.......
~....Other 4 Administrative and general-CP&L Administrative and general-Power Agency Amounts in lieu of taxes..........
N.C.gross receipts tax...........
Letter of credit commitment fee...Interest on revenue bonds.........
Excess funds valuation transfers:
Reserve and contingency Special funds deposits: Reserve and contingency Decommissioning..............
Rate stabilization
..............
Change in operating fund working capital requirements TOTAL EXPENSES......
NET REVENUES OVER EXPENSES$65,225 14,861 36,266$122,506>>$187,731 14,861 2.106 38.372 116,352 124,612 240,964 17,575 25>187 17,575 25,187 4,635 4,635 6,480 517 949 3,914 91 22,885 (2,572)2,720 852 34,371 1,252 36.691 101,660 15,643>>478 117,781 623 7,240 106,295 15,643 478 122,416 6,480 1,140 949'1,154 91 22,885 (2,572)2,720 852 34,371 1.252 36,691 116.352 125.644 241.996 19.043 1.028 20,071 23,859 126,179 150,038 7,926 4,312 1,239 1,239 2,172 7,926 4,312 106,661 107,900 10,441>>10,441 357 357 117,459 118,698 2,172 130 286 416 221 221 289 7,509 7,798 29.29 572 5,717 1,252 7,541 23,859 125.254 572 5,717 1.252 7.541 149,113$~5 925$925$4,816$125,151>>$129,967>>Supplemental and Other includes$1,020,000 and$1,389,000 as revenues and$1,116,000 and$1,403,000 as expenses in 1982 and 1983, respectively, related to delivery of All Requirements Bulk Power Supply beyond Delivery Points on the CP&L transmission system.E-14 THIS PAGE INTENTIONALLY LEFT BLANK E-15 NORTH CAROLINA EASTERN MUNICIPAL POWER AGENCY STATEMENT OF CHANGES IN FUNDS'SSETS (Unaudited)
For the years ended December 31, 1982 and 1983 (Thousands of Dollars)Construction Fund Invested Assets December 31, 1981 Bond and Note Proeeedsi1)
Power Billing~Reeel ts Investment
~Earnln Disbursements Construction account..~............
$Construction interest account........Bond Fund Bond fund interest account..........
Reserve account Revenue Fund$9?8,932$222,724 153,045$7,456$(615,002)6,921 70 3,962 Revenue account Rate stabilization account.........,.
Reserve&Contingency Fund.......Decommissioning Fund............
Operating Fund Working capital account-Fuel account 8,121 4,501 2,729 69 3 115 (2)352 (12,352)Supplemental Fund.Special Reserve Fund................
Term Loan Fund.8.808$8,808 99,337 860 91 15,653(2)677$1,367,323$117,719$20,574 (91,249)~27.009 2 1742.612)(1)Net of underwriter's fee of$30,717,000 and discount on bonds of$43,083,000 plus accrued interest of$4,123,000.
(2)The Agency supplied the VEPCO Participants with their power and energy requirements from December 30, 1981 until April 22, 1982.As the Revenue and Supplemental Funds were not established until the Agency first issued Bonds, all revenues and expenses during such period were accounted for through the Term Loan Fund.E-16 Transtcr Invested Assets Dccembcr 31, 1982 Bond and Note Proceeds Power Billing~Recci ts Investment Earnings Disbursements Transfers Invested Assets Dcccmbcr 31, 1983$(30.873)(63,313)$340,513 166,332$15,000$$16,932 16,018$(292,743)$(23,347)$56,355 (150.609)31,741 60,215 (3,494)60,285 153,513 545 19,801 (140,719)156,548 76.659 (19,326)153,988 213 4,292 (164)572 3,011 4,295 8,072 570 61,932 240 1,380 948 103 (3,548)(60.661)34,341 2,840 785 4 522 40.016 8.312 1.45S 11,005 547 3,506 547 744 (58,792)70,814 3.419 1 f7.272 3.066 12,573 1,000 7,427 21,521 1,091 5,556 S 1S.5768.812 515,000 121,364 2,106 (111.069)96 (14,727)(43)(2.126)(34)5 1608.9971 S 489$183,296$59.402 19.195 1.144 3.885 5417.512 yl 0