ML18018B686

Application for Amend to CPPR-158 to Reflect Cancellation of Unit 2.SEC Form 10-K for FY83 Encl

ML18018B686
Person / Time
Site:	Harris
Issue date:	06/20/1984
From:	CAROLINA POWER & LIGHT CO.
To:
Shared Package
ML18018B685	List: ML18018B684 ML18018B686
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

'DR A o 00@00 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.

Notary Public My commission expires: /0/0/gg  : gOTAq>:.~R OBL tC NORTH CAROLINA EASTERN MUNICIP4POSNYY,+'y~

POWER AGENCY ~<ll llilBRR BY:

Ralp W. Shaw, General Manager Sworn to and subscribed before me this ~ day of ~l, C) un~

1984.

Notary Public My commission expires: /0/PT/g~

(9955HHH/pgp)

g)L 'C'g .<<0i 00)f'f ~ ~

(*~-

~

0 p

~

0'I

<g0

'3'j > 6 0

I

.'i 0 iv) 0, 0

' 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 Power Agency P 0 Box 1551 P.O. Box 95162 411 Fayetteville Street Mall 3117 Poplarwood Court Raleigh, North Carolina 27602 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

I II

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 Position Sherwood H. Smith, Jr. 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 IH f7 lt d

d lk I

Operating License Stage Amendment as revised April 1984 William E. Graham, Jr. Executive Vice President Charles D. Barham, Jr. Senior Vice President and General Counsel James H. Davis, Jr. Senior Vice President Lynn W. Eury Senior Vice President Russell H. Lee Senior Vice President H. A. HcDuffie Senior Vice President Wilson W. Horgan Senior Vice President J. L. Lancaster, Jr. Secretary L. T. Quarles Treasurer Paul ST Bradshaw 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 Hr. Jordan C. Horne Town of Apex Town of Ayden Hr. Steven S. Weatherman Hr. Steven L. Harrell Town of Belhaven Town of Benson Hr. Charles R. Stewart Hr. Willis Privott Town of Clayton Town of Edenton (9955HHH/cfr)

ti h

't

~ il 'I I W W l,lt J k IWW

~

I I I t 3 W

'I I 1 if 'I tl 3 h I v

~ I'lt

'

'I r>

h W

It k

I 3 f

1 lt

'f~ ~ ' f

~, I 3 3 h I j

t>

f I I ff Il W

t I > W 0 fI r>

fJ r

o R

fI

)h ft tt gf t'3' W

Operating License Stage Amendment as revised April 1984 Nr. Joseph BE Anderson Nr. Connie Price City of Elizabeth City Town of Fremont Nr. J. A. Wooten, Jr. Nr. W. P. Riley, Jr.

Town of Farmville Town of Hamilton Hr. E. A. Warren Hr. R. G. Anthony City of Greenville Town of Hobgood Hr. Jesse .Harris Hr. Simon C. Sitterson, Jr.

Town of Hertford City of Kinston Hri Gene C. Hill Hr. Peter G. Vandenberg Town of Hookerton City of Laurinburg Hr. Edward B. Walters Nr. Harry L. Ivey Town of LaGrange City of Lumberton Hs. Lois Brown Wheless Nr. C. Vance Greeson Town of Louisburg Town of Pikeville Hr. Boyd C. Hyers Hr. Ralph S. Nobley City of New Bern Town of Robersonville Hr, John HcNeill Hr. Joe Edwards, Jr.

Town of Red Springs Town of Selma Hr. Frederick E. Turnage Hr. Hugh C. Talton City of Rocky Nount Town of Smithfield Hr, N. 0. HcDowell, Jr. Hr. J. Ray King Town of Scotland Neck Town of Tarboro Nr. W. Robert Thorsen Nr. Abbott N. Sawyer City of Southport City of Washington Hr. Rodney V. Byard Nr. T. Bruce Boyette Town of Wake Forest 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~

4 h J J It ~ 4 1 lf

~ 1' ~

,~

'lf J 1 1'h

'I J L J J

~,t u 4 It rl 4 ~I

~ I

~ ur 1,

b 4 1 Jl Pfr I hl I'l' h I

Iu 8 'l uu r ll I 4 I ~

J t h 4 II ,hg 1

I P ul ~

I I1 Pit M 4 Ig l I 4

W irr'I',I 1

u

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 projectsto cover operating and decommissioning costs.

sufficient 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 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 I P P

,'<<<<A )

3w.

I I" I 4

4 I

4 V J; fP'I hl 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 wholesale rates and services are subject to the regulatory

'P&L's 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 Asheville, North Carolina Courier Tribune Asheboro, North Carolina Daily Record Dunn, North Carolina (9955HHH/cfr)

Ik MI . iht',"

, I hM<)JM ))VM n

tt 'N v ~ M h 'M M" ) I M)V >w' Mt I ) V M '

I MM h MI a

v I M I

'v ll I h

,h)t t' M I l MNI 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 I

r V V Vl M

'

Operating License Stage Amendment as revised April 1984 Fayetteville Observer Fayetteville, North Carolina Fayetteville Times Fayetteville, North Carolina News-Argus Goldsboro, North Carolina Henderson Dispatch Henderson, North Carolina Daily News Jacksonville, North Carolina Kinston Daily Free Press Kinston, North Carolina Rob esonian Lumberton, North Carolina Sun Journal New Bern, North Carolina News and Observer Raleigh, North Carolina Raleigh Times Raleigh, North Carolina Richmond County Journal Rockingham, North Carolina Evening Telegram Rocky Mount, North Carolina Sanford Herald Sanford, North Carolina Star-News Wilmington, North Carolina Daily Times Wilson, North Carolina Florence Morning News Florence, South Carolina Sumter Daily Item 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 In addition, it is requested that one copy of each communication be sent to:

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 56-0165465 State or other jurisdiction of I.R.S. Employer incorporation or organization) Identification No.)

411 FayetteviQe Street Raleigh h North Carolina 27602 (Address of principal executive Zip Code) offices) 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 on which registered Common Stock (Without Par Value) New York Stock Exchange Pacific Stock Exchange First Mortgage Bonds, 7-3/496 Series New York Stock Exchange due 2002

$ 2.675 Preference Stock, Series A New York Stock Exchange (Without Par Value, Cumulative)

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:

Average Average Annual Annual Revenue Year KWH Use Bill ~er KWH 1979 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ t~ 11,785 $ 480.84 4.085 1 980 ~ ~ ~ ~ ~ o ~ ~ ~ ~ ~ ~ ~ ~ 12,558 546.11 4.35 198 lo ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 12,087 648.57 5.3V 1982' ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 11,663 V22.26 6.19 1983@ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 11,889 V69.27 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.

Estimated Capital Requirements (In Millions) 1984 1985 1986 Total Construction expenditures $ 716 $ 571 $ 379 $ 1,666 Nuclear fuel expenditures 100 68 109 277 Less AFUDC (a) (112) (128) (52) (292)

Net expenditures (b) 704 511 436 12651 Harris Units 2, 3, and 4 cancellation costs (c) 46 14 14 Long-term debt and preferred stock retirement (d) 2 4 5 Total ~752 $ 529 $ 455 $ 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:

Design Target Projected Estimated Unit ~Canacit Tvee In-Service Date Cost (Millions)(a)

Harris No. 1 900 MW Nuclear 1986 $ 2,546 Mayo No. 2 V20 MW Coal 1991 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.......................... '1,438,723 Mayo Unit No. 2 .......................... 13 166 Total ................................. 61 451.679

7) 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:

Annualized Increased Approximate Revenues Based On Increase in Test Year Level Jurisdictional of Sales Effective Date State Revenues Granted Re uested Granted 5/1/81 South Carolina 11% $ 27,500,000 $ 15,339,000 12/15/81 North Carolina 13 151,432,000 119,197,000 6/1/82 South Carolina 14 40,341,000 24,958,000 9/24/82 North Carolina al 173,700,000 a8,784,000 9/19/83 North Carolina 8 164,913,000 90,855,000 b10/7/83 South Carolina 15 44,040,000 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)

Cost Weighted Ca ital Structure Ratio Rate Cost Long-Term Debt 49.5% 9.59% 475 0 Preferred Stock 12.5 8.96 1.12 Common Equity 38.0 14.50 5.51 Rate of Return 11.38%

South Carolina (test ear ended December 31 1982)

Cost Weighted Ca ital Structure Ratio Rate Cost Long-Term Debt 47.63% 9.49% 4.52%

Preferred Stock 13.04 8.96 1.17 Common Equity 39.33 14.50 5.70 Rate of Return 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:

Net 1983 Maximum Station Fuel Cost(a)

Plant Unit Year Primary Dependable Generation(a) (1983 Avg.

Location Nc. Installed Peel ~Ca acit MWH Mills/KWH)

Asheville 1 1S64 Coal 198 MW 2,377,595 17.62 (Skyland, N.C.) 2 1971 Coal 194 MW Cape Fear 5 1956 Coal 143 MW 1,046,342 18.53 (Moncure, N.C.) 6 1958 Coal 173 MW H. F. Lee 1 1952 Coal V9 MW 1,488,115 19.46 (Goldsboro, NC) 2 1951 Coal V6 MW 3 1962 Coal 252 MW H. B. Robinson 1 1960 Coal 174 MW 578,475 19.28 (Hartsville, S.C.) 2 1S71 Nuclear 665 MW 3,347,522 4.57 Roxboro 1 1966 Coal 385 MW 13,233,756 (c) 20.11 (Roxboro, N.C.) 2 1968 Coal 670 MW 3 1973 Coal V07 M$U 4 1980 Coal 700 MW (b)

L. Y. Sutton 1 1954 Coal 9V MW 1,593,982 2).V9 (Wilmington, 2 1955 Coal 106 MW N.C.) 3 1972 Coal 410 MW Brunswick 1 19VV Nuclear 790 MW (b) 4,426,995 (c) 4.76 (Southport, ¹C.) 2 1975 Nuclear 790 MW (b)

Mayo 1 1983 Coal V05 MW (b) 3,111,583 (c) 21.08 (Roxboro, N.C.)

(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 13-

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 69% 75% 72% 80%

Nuclear 29 23 25 17 Hydro 1 2 2 2 Other 1 1 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.

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 oi 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 e.. No re p airs were required as a result of these inspections; however, the inspection results indicate 'ks s h o uld te that the disks 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 iadioactive gases ' to the environment. The modifications to thee au mented augmen e off-gas B U 't No 1 were completed during the scheduled refueling and maintenance outage uta e w whichic ended en e in August 1983. In December 1983, the NRC gran e aug mented off g as system

~ ~ ~

the Company's request to defer the final modifications to the au 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.

ll) requiremen h'

On Decem b ts re 1 a ted e

er,,

to o

2 1981 thee NRC published final regulations establishing interim hydrogen contio) at operating nuclear power plants 1 nts p ursuant to wic thee Company o is required to make certain modifications to the Brunswick Units.

The Company has sought review of the regulations b y thee 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 requiremen ts . Thee Company has filed with the NRC a request for exemption from the technical requirements of the regulations. The Company cannot ot p redict the outcome of these proceedings.

y, 12 ) In Jul 1982 thee 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 ire d b y iits pre-startup commitments to the NRC and surveiQance requiremen ts an d req uiied i valve testing of containment isolation valves were corn leted re comp e b 1982 Th Company has also made post-startup commitments to th the NRC with respect to long-term corrective actions which it will undertake to assur e timely compliance with technical specification surveillance requirements.

) 1982 the NRC notified the Company that the large diameter reactor t'f recirculation system piping in boiling water reactor units such as the Brunswick Un its has the potential to crack as a result of intergranular stress corrosion and required an such piping at boiling water reactoi'nits undergoing a iefueling or extended outage prior to January 31, 1983, which included Brunswic ni iNo.

swick Unit o. l.

d Brunswick Unit No. 1 during the spring of 1983. Additional

'

t piping inspec recirculation 'nspections wete performed on Brunswick Unit No. 1 in Octoober er 1983 durin~ a scheduledd outage. t Twowo oof 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. pPor t ions o 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 t e 1y $ 36 million 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 runswic k Pl annt an and Robinson Unit No. 2 from certain of the requirements of the NRC's fire protection regulations. With respect to the Brunswick Plant, in Jul u y 1983 the ilRC grante d certain cer ain of o the e exemptions which the Company had requested and denied the remaining requests. With the NRC's concurrence, the Company n w p erformin~ an n is now

'

ana 1 ysis o d eveclop op alternative measures to those originally proposed which the Company can take in order to meet the requirements of the regulations. The Companyv expec ex ects to 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 ans too ccomplete equipment qualification modifications on Brunswick Unit No.

C ompany p lans 1 during an outage cuirently scheduled to begin in the spring of o 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 to increase when Harris Unit No. 1 becomes operational. Because of 'xpected 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 33.64 138 1980 38.75 157 1981 42.55 173 1982 47.22 192 1983 47.89 192

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:

Estimated in-service Raw Materials and Services Unit Date Uranium Conversion Enrichment Fabrication Robinson No. 2 1990 1987 2002 1989 Brunswick No. 1 1989 1987 2002 1993 Brunswick No. 2 1990 1987 2002 1988 Harris No. 1 1986 1990 1987 2002 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 f'eing emergency outage of the City's eight 20 MN internal combustion turbine units, of which ive are used by the City for peak shaving purposes. The agreement also makes capacity from these units available to the Company, subject to certam condi't'o i ns, 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 amon~ am 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 Year Ended December 31.

1983 1982 1981 1980 1979 Electric energy suooly (miiUioas of kilowatt-hours) 5 (miUions of kilowatt-hours) 5 Generated aet stat(on outputs Stcam Eosdl. 23,799 23.079 22.372 22.299 18.336 Stcam nudcar. 6 ~ 7.775 6.876 9 J44 8,955 10.802 Hydro. 816 735 437 680 1,019 Internal combustion rutbincs.............. 35 23 117 224 146 Total gencrared. 32,425 30.113 32.270 32.158 30,303 Purchased aad nct interchange.............. 357 1.119 80 25 (3)

Total cncrgy supplr (Company sharc)...... 3" 75" 31.332 32.350 32.183 30JOO Power Agency's ownership share ............ 1.529 361 Total combined system energy supPI...... 3>.311 32.193 hvcragc Eossil fud cost per mdlion ILTII(cents).. ~ . ~ 196.2 194.8 178.5 163.0 141.8 Arcrage nuckar fuel cost per million STU (cease) . ~ ~ 42.L 35.8 37.2 35.7 35.4 Average coul fuel cost (fossil and nudeat) pcr miUion STLI (cents). 156.1 L55.4 135.1 124.9 100.8 Hectric energy saks (miUions oE kilowatt-hours jt Rcsidcntial. 8.010 7.647 7,746 7.870 7.195 Commercial 5,546 5.341 5.072 4.935 4.590 Induserid. LOJLO 9,520 9,968 9.791 9.609 Govemtnent and municipal................ 768 753 823 864 917 Total general business................. 24.S34 23 261 23.609 23.460 2XSLL Sdca for resale:

Standard race schedules Power Agency participants.............. 1.129 '9 C93 X56I 2.363 Other 4.455 4.253 4.285 4.261 3.994 Power Agency contract re51ulremcnts ........ 1.896 1.840 Total electric energy sales.............. 30.885 30.483 30,487 30.282 28.668 Com p any uses. )oases and unaccounted Eot.... ~... 1.897 1.349 1.863 1.901 1.632 Total energy supply (Company hare)...... 3'52 31.832 32.350 3r 183 30.300 Number of cunomcrs(accounts as oE cad of period):

Rcsidcntial. 680.581 660.850 647.491 632.209 617.393 Commercial 110 J41 106.287 104.9 L9 103.994 102.198 Industrid. 4,046 4.010 3.942 3.794 3.625 Government and municipd...., ~ ~ . ~ ~ ~ ~ ~ ~ ~ ~ 919 847 1.111 1.581 1.>47 Total gcacral business............. ~ ~ ~ ~ 795.887 171.994 757.469 741.578 724.963 Resdc. 33 33 55 . 55 54 Total customers ~ ~ ~ ~ 795.920 772.027 757.524 74 1,633 125.011 Operating revenues (ia mUlions) 5 Rcsidcntial. 5 518 474 5 416 342 5 293 Commercial 325 302 250 196 172 Industrid. 479 434 386 297 268 Governrncnt aad municipal......... ~ . ~ ~ ~ ~ ~ 41 39 36 30 09 Total general business...... ~ ~ ~ ~ ~ ~ . ~ ~ ~ ~ 1J63 1.249 1.088 865 762 Sdes for resale 263 275 245 202 156 Toed from energy sdcs. ~ ~ ~ . ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1.626 1J24 1.333 1.067 918 Miscellaneous . 21 14 ll 9 8 Toed operating revenues.. ~ ~ ~ ~ ~ . ~ ~ ~ ~ ~ ~ ~ 5 1.6>7 1.538 5 I J44 5 1.076 5 926 Peak demand of Urm load (thousaads of kilowatts) t Total combined system..... ~ ~ . ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 6.926 6.602 6.402 6.139 5.907 Less Power Agency portion 304 Orr Company coca! peak demand............ 6.622 6.602 6.402 69139 5.907 Less sales to Power Agency and Participants..... 449 637 Company net peak demand.......:..... 6.173 5.965 6 402 6.139 5.907 Total capability at end of period (thousands of kUowatts):

Fossil plants 6.291 5.561 5.519 5.519 4.869 Nudear plants. 2.245 v 245 2.245 2,245 2.245 Hydro plants 214 214 214 214 214 Purchased 75 75 75 75 128 Toed combined system capabUlty........... 8.825 8.095 Less Power Agency owned portion .. ~ ~ . ~ ~ ~ ~ ~ 494 262 Add capabUIty purchased from Power Aecncy .. 75 Totd Company portion . ~ ~ ~ . ~ ~ . ~ ~ ~ ~ ~ ~ ~ 8.406 7.833 8.053 8.053 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

~

Rox oro RRk Mapo

~

Henderson N.C.

~ape ~a*Raleigh Fear r~.

Walt/r's Rhal Ashhville Charlotte,

~ T. C~ 'oldsboro

~

+Southern Pines L~ee MoreheaIl Cit

%P Blewett Bl Jacksonville Darlington aaa Weat herspoon

~Sutt n Robinson S.C. ~- WilnIington~ L And Florence Qg I PAI El RI lCF ARFA Sumter ~ FREER' IR neF Columbia

• B un~wick

~ Rt FIXW

~ A M%'I FAR 5l IIIEIR AMIMRIEAll M ImAIII r MKIFAR FIEF I C IINWt4F

~ FOAEIL EIIE

ITEM 2. PROPERTIES For a description of the Company's major generating units, see ITEM "Generating Capability". See ITEN 1- "Service Area" for a general outline system map, 1-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 No matters were submitted to a vote of security holders in the fourth quarter of 1983.

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 ~Hi h Low Dividends Paid First Quarter $ 23 $ 19 1/2 $ .60 Second Quarter 22 3/4 19 5/8 .60 Third Quarter 22 3/4 19 .60 Fourth Quarter 21 7/8 18 7/8 .60 1983 ~Hi h Low Dividends Paid First Quarter $ 23 $ 20 5/8 $ .60 Second Quarter 22 7/8 21 1/2 .60 Third Quarter 23 3/4 20 3/8 .60 Fourth Quarter 25 1/8 21 1/2 .63 As of February 29, 1984, the Company had 103,189 holders of record of Common Stock.

ITEM 6. SELECTED FINANCIALDATA For the Year Ended December 31 1983 1982 1981 1980 1979 (In Thousands, Except Per Share Figures)

Operating revenues $ 1,647,183 $ 1,538,165 $ 1,343,558 $ 1,075,604 925,910 Net income 239,269 227,147 203,597 161,388 153,244 Earnings for common stock 194,664 182,542 160,937 126,747 124,981 Earnings per common share $ 3.21 $ 3.17 $ 3.06 $ 2.73 $ 3.06 Dividends declared per common share $ 2.46 $ 2.40 $ 2.32 $ 2.20 $ 2.05 Total assets $ 5~293,606 $ 4,9S0,9SS $ 4,715,835 $ 4,241,607 $ 3,647,913 Capitalization:

Common stock and retained earnings $ 1,586,441 $ 1,462,165 $ 1,364,692 $ 1~233~368 $ 1~045~ 150 Preference stock 47,900 47,900 47,900 47,900 47,900 Preferred stock-redemption not required 238,118 238,118 238,118 238,118 238,118 Preferred stock-redemption required 214,785 214,743 214,700 175t100 100~000 Long-term debt, net (a) lt931i672 1~955i824 1<929<448 1,713,467 1,507,690

$ 46,479,000, $ 64,122,000 and $ 21,849,000 N,,>>, N.,

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.

LIQUIDITYAND 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) $ 912.6 $ 398.1 $ 241.9 $ 272.6 Sale of gene.ating units 664.1 79.3 584.8 Financings 318.1 236.5 136.7 444.9 Total 82.394.8 8713.9 $ 963.4 8717.5 and utilized as follows:

Gr oss property additions and nuclear fuel $ 1,948.0 $ 708.6 $ 654.7 $ 584.7 Retirement of long-term debt 346.5 125.7 160.0 60.8 Power Agency trust fund remaining (153.9) 153.9 Other working capital incr ease (decrease), etc. 100.3 33.5 (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):

1983 1982 1981 Net Income $ 12.1 $ 23.6 $ 42.2 Dividends (11.5) (17.3) (26.7)

Deferred income taxes and investment tax credits 66.9 (23.5) 52.5 Depr eciation and amortization 27.8 (8.8) 24.2 Provision for coal mine losses 49.9 Deferred income taxes credited to property accounts 11.0 (4.7) (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 33.9% 39.4% 30.3%

First mor tgage bonds 71.4 87.1 5.5 Long-term notes 44.1 18.0 Commercial paper backed by long-term credit facility (24.1) 29.2 Nuclear fuel financing arrangements (4.4) 4.2 9.4 Short-ter m transactions 23.2 (74.8) 7.6 100.0% 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 qualifying 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. FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA The following financial statements, supplementary data and financial statement schedules are included herein:

~Pa e Auditors'pinion 36 Financial Statements:

Balance Sheets as of December 31, 1983 and 1982 37-38 Statements of Income for the Years Ended December 31, 1983, 1982, and 1981 39 Statements of Retained Earnings for the Years Ended December 31, 1983, 1982 and 1981 39 Statements of Source and Use of Financial Resources for the Years Ended December 31, 1983, 1982 and 1981 40 Schedules of Capitalization as of December 31, 1983 and 1982 41-42 Notes to Financial Statements 43-47 Summary of Quarterly Financial Data Supplemental Inflation Adjusted Data 48-50 Financial Statement Schedules for Years Ended December 31, 1983, 1982 and 1981:

V Utility Plant 51-53 VI - Accumulated Provision for Depreciation and Amortization of Electric Utility Plant 54-56 VIII Reserves 57-59 IX - Shor t-term Borrowing 60 X - Supplementary Income Statement Information 61 All other schedules are omitted as they are either not required, not applicable, or the information is otherwise provided.

Moiite HBskins-8eils 2000 Center Plaza Building Post Office Box 2778 Raleigh. North Carolina 27602 (919) 8284716 Cable DEHANDS Auditorsr Coinicn Ca~lina Power E Light Co??zeny'-

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 Tight Company 1'sted in the accorqanyi<<ng I?

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 has canc led plans for construct<<on of a nucle~ generating u?~t and intends to reauest per..'ssion in each oz <<ts re~tory jur<<sdictions Co recover its costs . lated uo such un"t. ne GutcolN of this lifter ca zlot 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) uncerta<<"?t J r fe~

i ~

a."?y) as,. << "lt have be ."? recuir d had .he outco...e of "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 niche period ended Dece~ier 31, 198- in ccn=o=-.,=:-'y i<<

with gen ray acceoted accounting "rinc<<ples ac@lied cn a ccns'- ent '=asia.

Kso, in ou". Opmhon, subject to the cu"lification r fr 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

re-8 g "?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

't'Q= we were to re'ssue o"" oo~on on these a statements u a. N c ~"rentlv,

~ v it 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 state'nts rom t "<<ch <<t has been Qer've=.

~~:ter. 4Q.Zy 1 g 1 98 It

Balance Carolina Power Sheets.

8c Light Company December 31, 1983 and 1982 1983 1982 (tn itious .".~a)

Electric UtilityPlant:

Elec'.ric utility plant other than nuclear fuel:

In service . S3.629.625, S3.019. 141 Held for future use 12.902 10.350 Construcnon work in progress . 1.697.551 1.994.906 Total 5.340.078 5.024.397 Less accumulated depreciation 884.250 792.013 Net . 4.455.828 4.232.384 I luclear tuel . 264.802 231.518 Less accumulated amortization . 149,424 131.280 Net . 115.378 100.238 Electric utility plant. net 4.571.206 4.332.622 Current Assets:

Ccsh cnd temporary ccsh investments 9.214 8.028 Accounts receivable. net 97.651 75.140 Power Agency Trust Fund 153.89 I Matenals and supplies:

Fuel 101.893 121.896 Other . 25,338 29.495 Deter:ed fuel cost 6.186 5.070 Current portion of deferred income taxes 16.967 16.948 Prepa ~ents. etc 9.162 20.636 Total current assets 266.411 431.104 Other Assets:

Uncmortized canceled project costs:

Hams Unit No. 2 (Note 6) 263.733 Hams Units Nos. 3 fznd 4 (Note 8[f)) . 121A60 124.587 Unrecovered nuclear tuel disposal costs (Note 8[e]) .. 29.267 Investment in coal-mining subsidicnes (Note 2) ...... 2 I 9.620 Miscellaneous other property and investments ....... 22.348 I 8.5o0 Unamortized debt expense 3,467 3.230 Other deferred debits 15,712 21.232 Total other assets . 455.989 187,229 Total S5.293.606 S4.950955 e notes to!inancial

~ I staiernen',s.

'alanl-e Sheets Carolina Power Light Company December 8c 31, 1983 and 1982 abilities 1983 1982 (In:l20VSar CS i Capitalization (see Schedules of Capitalization):

Common stock . S1.151,323 S 1.071.863 Common stock subscribed 2.205 l.528 Retained earnings 432,913 388.774 Preference stock . 47,900 47.900 Preterred stock-redemption not required ............. 238.118 238.118 Preferred stock-redemption required. net ............. 214.785 2!4 743 Long-term debt (excluding current matunties}, net ..... L909.823 1.891.702 Total ccpitalization (excluding current matunties of long-term debt} . 3.997.067 3.854.628 Current Liabilities:

Long-term debt due within one year 21. 849 Notes payable:

Bank demand notes . l 3.CCO Other (pnncipally commercial paper)... 82.703 19 n4n Accounts payable:

Construction contract retentions 5.370 f 3.725 Other 126.055 :59 pl0Q Customers'eposits , p~4v 7.905 v Tcxes accrued 41.782 68.467 interest accrued ..., .................... 42.378 N

~ 4%

l,w'4 ~

Dividends declared 58.833 '4.769 Other 4.319 4.C05 Total current liabilfties 391.194 395."ov Deferred Credits and Other Lfahfffffes:

Accumulated deferred income taxes:

Hams Units Nos. 2. 3 and 4 . 134.702 35.885 Gain on sale of facilities (Note 7) . (98.125) (94.080)

Other. net . 494.424 447.926 Total cccumulated deferred income taxes .. 531.201 389.731 Accumulated deferred investment tax credits ... 174.112 180.700 Uncmortized gain on sale of facilities (Note 7) .. 128.104 117.348 Other . 71.928 22 494 Total deferred credits and other liabilities... 905.345 700.674 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)

Operating Revenues (Note 9) S1.647.183 S 1.538.165 S 1.343.558 Operating Expenses:

Operation:

Fuel for generation 517.625 473.509 459.591 Deferred tuel costs (1,115) 1.423 523 Purchased and tnterchange power. net ...... 18.583 50.226 19.388 Other (Note 2) 285,671 233.147 174.084 Matntenance . 137.383 167.458 I 25.876 Deprectation ard amortization (Note I) ....... 148,342 126.355 I IOA09 Taxes other than on!ncome 114.295 104.300 97.288 Income tax expense (Note 5) . 162.443 133.622 118.996 Total operating expenses . 1,383.227 1.290.040 1.106.155 Operating income 263.956 248.125 237.403 Other Income:

Allowarce for other funds used during construction . 94.927 98.353 92.508 Income tax credits (Note 5) 31.078 38.472 35.846 Amornzed ga!n on sale of facilities (Note 7) ......... 11A22 Other!ncome (deductions). net (Note 2) ............ (4.945) 13.919 8.593 Total other income.............. 132A82 15O.744 I 36.947 Income Before Interest Charges . 396A38 398.869 374.350 Interest Charges:

Long-term debt 171.448 180.986 177 98 I Other 17.551 34.00! 31.201 Allowance for borrowed funds used dunng corstructtonwredit (Note 5) (31.830) (43.265) (38A29)

Net interest charges . 157,169 17 I.722 170.753 Net Income 239,269 227.147 203.597 Preferred and Preference Stock Dividend Re~ements ....... 44.605 44.605 42."60 Earnings for Common Stock......... S 194.664 S 182.542 S 160.937 Average Common Shares Outstanding . 60.645 57.539 Earnings Per Common Share . S S 3.17 S 3.06 See notes to financial statements.

Statements of Retained. Zarnings-For the Years Ended December 31, 1983 1982 1981 (tn thousands)

Balance at Beginning of Year S 388.774 S 345.353 S 309.819 Net Income 239,269 227.147 203.597 Total 628.043 572.500 513.416 Deduct:

Cash dividends declared:

Preferred and Preference Stock at stated rates (Note I) 44.605 44.6O5 Common Stock (at annual rate of S2Ab a share in 1983. S2.40 in 1982 and S2.32 in 1981) ............. 150.423 138.878 123.578 Total cash dividends declared 195,028 l83A83 167.638 Capital stock dtscount and expense 102 243 425 Total deductions 195.130 183.726 168.063 ance at End of Year . S 432.913 S 388.774 S 345.353 See notes to financtal statements.

" Stafexnents of Source and Use of Financial Resources Carolina Power Light Company For the Years Ended December 8c 31, 1983 1982 1981 (In Thousands) ource of Financial Resources:

Current resources provided from operations:

Net income . ...................................,.... S 239.269 S 227,147 S 203.597 Items not requiring (providing) current resources:

Depreciation and amortization . 180.565 141.334 150.105 Amortized gain on sale of facilities ................. (11.422)

Provision for possible coal-mine investment losses ... 49.868 Noncurrent deferred income taxes. net ............. 172.341 I0.391 I50.940 Investment tax credit adjustments. net............... (6.589) 88,493 (28.569)

Other funds portion of AFUDC (94.927) ~98. 383) ~92.888)

Total current resources provided from operations 529.105 369.012 383.565 Sale of generating facilities 79.301 584.801 Total current resources . 608.406 953.813 383.565 Additions to plant accounts representing capitalization of other portion, less deferred income taxes on borrowed funds portion of AFUDC 64.056 56A05 8 .23)

Total resources provided excluding financings 672.462 1.010.218 938.798 Financings:

First mortgage bonds . 168.767 119.038 24.248 Preferred stock 39.458 Common stock Public offerings 59.6I6 Common stock Plans (Note 3) 80.077 53.852 35.931 Other long-term notes . 42 60.270 80.000 Commercial paper backed by long-term credit facility . (57.015) 130.CCO Nuclear tuel trust and lease obligations ............ (10.409) 5.731 41.954 Decrease in temporary cash investments plus increase in short-term notes payable ........ 54.993 ( I02.195) 33.705 Total resources provided from financings ...... 236A55 I36.696 4aa.9! 2 Total . S 908.917 S l. 146.914 S 883.708 Use of Financial Resources:

Gross property additiots. excluding nuclear fuel' S 660.130 S 638.284 S 548.508 Nuclear fuel additions' 48.488 16A50 36.223 Canceled projeca expenditures 20.710 15.355 Dividends for the year . 195.028 183.a 83 166.238 Repayment of first mortgage bonds . 123.346 20.000 15.000 Repayment of other long. term debt . 2.333 140.064 Repayment of nuclear fuel lease obligation ....... 45.827 Net increase (decrease) in the following working capital components:

Power Agency trust fund . (153.891) 153.891 Accounts receivable. net . 22.511 4,284 8.019 Materials and supplies (24.160) 13.968 19.930 Accounts payable (7.861) (10A82) 56.943 Reserve tor retund of revenues 499 24.094 (16.799)

Other. net 15.389 (25,687) (11.002) 88scellaneous. net . 6,395 (26.790) I 4.82!

Total S 908.917 S1.146.914 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 $ 1.151.323 $ 1.071.863 Subscnbed 2.205 1.528 Retained earnings. limited in payment as dividends under cenain circumstances under the Company's charter, however. none restncted at December 31. 1983 ... 432913 388.774 Total common stock equity 5 I,584.441 S I.462.! 65 PREFERENCE AND PREFERRED STOCK. without par value.

cumulanve (Note 3):

At December 31. 1983 Redemption Shares Price 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 ..., .. Sl IOCO 237 259 $ 24.376 "4 3"6 Senal Preterred Stock(b)

$ 420 Senes .. 102.GO I GO,GGO 10.000 IG.CCG 5.44 Senes . 101 GO 250.GCO 25.000 "S.CCO 910 Senes. 10300 300.000 30.000 30.000 795 Senes. 104 00 3M.COO 35.000 35.0CO 772 Senes. 104 00 500.GGO 49.425, 49,425 8.48 Senes . 105 00 450.000 64.317 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 . SI I I 16 $ 40.000 S 40.CCO 1400$ enes . 114 GO 40.000 40.000 Preferred Stock A. authonzed. 5.000.000 shares S745 Senes . 104 00 5CO.GCO 50.000 MCCO 8.75 Senes . 107 23 SC0.000 50.000 50.CGO 9 25 Senes ................. .......... 104 50 180,000 18.000  ! 8.CCO 900 Senes . (c) 17:.GOO 17.500 17.MO Vnamcmzed discount . (715)

Total-redempnon required 2.! =.000 5 214.785 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

1983 1982 (tn Ihoi)scow)

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) . S 67.346 f491%. due Apnl l. 1987 5 125.000 125.!Xo 4g)L due March I. 1988 20.000 20.GCO 4i'A. due Apnl I. 1990 25.000 25.0CO 4i!% due November I. 1991 25.000 25.GGO I I L due December l. 1992 2 100.000 'QOCCO Marunng 1994 Ihrougn 1998-4m% to 6iA . 140.000 140.GGO Matunrg l999 through 2003-7< to Sill . 525.000 525.GCO Matunng 2C04 through 2008-SH% to 934% . 325.000 325.000 Matunng 2009 through.2013- IO'ri%, to l2'8% . 325.000 225.000 Pollution Control Senes:

A 8 %. due 2001-2009 (pnnctpal amount less proceeds held by Trustee: 1982. SI.900) .. 63.000 61. IOO B. 7.4% due IO 1-83 (pnnci pal amount less proces held by Trustee l 982. S12.227) .... 37. J73 C. 7 A due 10-1-83 . 6.CGO D. (5.65%, to 4/I/84) due 4-1-2009 48.485(b)

F (5.65% to 4/I/84) due 4-1-2009 5.970(b)

F. (7.0% to I I/I/S4) due 11-1-2010 (pnncipcl cmount less proceeds held by Trustee 1983. S32.!40) . 2.560(b)

Total liat rnortage bonds.pnnctpal amounts . 1.730.015 I.c82.2lc Other Icrg.term debt:

Nuclear tuel trust obligations (vancbie rctes. !0.47% avercge effective interest cost at 12-3I.83: 9.56% 5 at l2-31-82) ............................. ~ . ~ ~ ., ~ 80.215 90.62'O.CCO 86r% Guarcnteed Notes (Finance 8V,V,) due 2.15-89 (Ncte I (bi}

~

60.000 Carolina Pipeline (Vanable mterest rate - I I.5% at 12-31.82) 2 03'2 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) 72.985 130.CCO Misce J'aneous promissory notes 107 co Totcl long. tenn debt. pnncipal amounts 1.943.322 1.965.242 Unamortized discount and premium net < I L 880) (9.418)

Total long-term debt. including current maturities 1,931.672 1.955.824 Less long-tenn debt due wtthfn one year.

Nuclear tuel trust obligattons . 21.849 19.882

?i48% PcllutiOn COntral BOndS. due 10-1-83 43 773 Carolina Pipeline due 10 l-83 . Ser Total long-tenn debt. excluding cutrent matunhes . 8).909.823 S 1.891.702 TOTAL CAPITALIZATION(exc! uding c~nt matunties of long. term debt } 53.99?.067 S 3. 5 54. 6 a 8 ia) Long tenn debt maturtltes tor the nest tire rems. including estimated amounts under continuous nuclear tuel ttnanctng arrangements for which repayments of present obligations are based on energy produced. are (in thousands):

1984 1985 1986 1987 1988 First mongcge bonds ............... S 125.GCO 20.CCO Nuc! ear tuel 521.849 S IS 488 S 20.577 IO.M7 3.556 Long-term credit fact! tty obltganons . I 30."00

.otcls S21.849 S!8.488 S I 50.8?7 S135.507 S23 '=6 fb) Redeemable annually at the option of the holder-backed up by a portion of the long term credit facility of 5130.000.000.

.otes to hncncial statements.

Noies to Pinancial Siatements

'. Summary of Sfgnfffcant Accounting Policies therefore. the Company recorded lower depreciation provisions solely applicable to wholesale opercrions (a) System of Accounts. The accounting records of the (SI 947.CM less for 1983. Sl.527.000 less tor 1982 cnd Compcny are maintcined as prescnbed in unform systems S3.383.000 less for 1981),

of accounts of the Federal Energy Regulatory Comrr~ion (FERC) and the regulatory commissions of North Carolina and South Ccrolina. Amortizatton of nuclear tuel costs (1983. S30.594.000.

1982. SI3.536.000: 1981. S38.784000). including disposal (b) Subsidiaries. The Company's financicl statements costs through April 6. 1983. is computed on the unit of reflect consolidation of its wholly-owned foreign financing production method and charged to fuel expense, The substdiary. Carolina Power fk Light Finance N.V.. which in amortization charges tor disposal costs totaled. for 1983 1982 was orgarized and issued S60.000.000 pnncipal through Apnl b. S3.650.000: for 1982. S7.684.COO less a amount of Ib",".L Guaranteed Notes. See Note 2 for wholesale revenue retund related reduction ot S14.313.0CO information on the coal-mining subsidianes. app! tccble to the years 1977-1982: and for 1981. S10.064.000.

Nuclear tuel disposal costs are paid quarterly tor nuclear generation after Apnl b. 1983, (See Note 8(e)).

(c) Electric Utility Plant. The cost of additions.

including replacements of units of property and bet terments.

is charged to utility plant, Maintenance and repairs of (f) Revenues. Customers'eters cre read and bills are property. and replacements and renewals of items rendered on a cycle basis. Revenues are recorded when determined to be less than units of property. are charged to billed. cs is the customcrg practice in the industry maintenance expense. The cost of units ot property replcced or renewed or otherwise retired. plus removal or disposal costs. less salvage. is charged to accumulated (g) Deferred Fuel Costs. The Companys rc:es in cll depreciation. E!ectric utility plant. other than nuclear iuel. is three ot its regulatory lunsdictions are adiustable for, subject to the lien of the Company's morigage, Nuclear tuel fluctuations in fuel costs, For South Carolira retail opera!tons.

is pledged. or subject to be pledged. as collcteral tor the Company defers the difference bergen fuel costs nuc!ear fuel ttnanc:ng arrargements. incurred and the relcted customer bt!lings ard penccicaily adiusts rates to retlect this difference For wholesale operattors. the Comocny adooted a similar procedure (d) Allowance for Funds Used During Construction effective January 1982. For North Carolina retcil operations.

(AFUDC). As prescnbed in regulatory uniform systems of pursuant to c June 1982 amendment to Norh Carohna

-".courts. cn allowance for the cost of borrowed and other utilities Icr~. the fuel cost component ot rates ref lee:s

ds used to finance electric utility plant construction. less estimcted fuel expense for the penod that the rates willbe in pliccble income taxes. is charged to cost of plant, effect ai.d may be adtusted once in every twelve moi.ths in egulatory authonties consider the inclusion of these fuelwostwnly proceedings, ln addition. fuel costs may be recognized costs as appropriate for the purpose of considered in general rare case proceedings.

establishing rates for the Company's utuity charges to customers over ihe service lives of the property The other portion ot AFUDC is credited to other income. the borrowed Effective for service rendered on and cfter September funds portfon is credited to interest charges and the deferred 19. 1983 the North Carolina Utilities Commission approved a income tax provision is reflected as a reduction in AFUDC- general rate increase that included a base fuel component borrowed funds. The composite. netwf-tax AFUDC rate was of S.01677 per KWH (up from S.Olbl I) and directed the approximately 9 3 percent in 1983 and 1982 and 8,8 percent establishment of an intenm deferred account for vcriatiors in 1981. between actual tuel expense incurred and the base tuel Certcin construction-work-in-progress expenditures component revenues. provtdfng consideration of the (totaling S662.570.000. S412.535.000. S405.419.000 and deferred cmounts in the next ger eral rate case heanng now S229.590.COO at December 31. 1983. 1982. 1981 and 1980. planned for the third quaner of 1984. At December 31. 1983 respectively) are included in the rate base for rctemaking the Company has deferred Sl.627.000 ot costs ircurred in purposes. AFUDC is not capitalized (charged to the cost of excess ot such base tuel component revenues, plant) on such expenditures.

(h) Income Taxes, Comprehersive interper:od (e) Depreciation and Amortizatfon. Depreciction of incor..e tax cllocc'ion has been observed. begtnmrg:n utility plant. other than nuclear tuel. for financial reporting 1976. for all signtf!cart timing d:ffererces. In complicrce purposes is computed on the straight-line method bcsed on with regulctory accounting. income taxes are ciicccted esnmated remaining useful lives. cdjusted for estimated net between operating tncome and other income. orincipclly salvcge or disposal costs. and charged principally to with respect to interest charges re!cted to constn;c:.on work depreciction expense. Depreciction provisions. as a in progress. The Company and tts domestic substdtanes ft!e percent of average deprecicble property other than consolidcted federal income tax retur."s, Ircome taxes are nuclear fuel. approximated 3.8 percent in 1983 cnd 1982 allocated among the companies bcsed upon the ratios ot and 36 percent in 1981. Depreciation rctes are reviewed their respective "separate tax liabilities 'o the ccrpo! tda.'ed penodicclly and charges in esnmctes (inc!uding the costs to tax Itabtltty See Note 5 with respect tocer ainotherincome "mantle or decontaminate nuclear generating plants) tax intormation, made. cs appropnate. on a prospective basis.

A!Iowabfe depreciation rates for wholesale ratemaktng ses have been different frcm those regularly used by (I) Investment Tax Credits. Investrrent tax c.edits cre e Comp"ny and cl!owed by other ratemcking iunscicticns. beii.g amomzed over:he service lives ot the property

(I) Preferred and Preference Dividends. Preferred and 3. Capital Stock Issued and Reserved reference dividends declared and charged to retained mfngs include amounts applicable to the first quarter of Capital stock shares have been issued cs tollows.

the following year. except for the Preferred Stock A series representing the total changes tn the respective accounts in which dividends are wholly applicable to the year in which the years indicated (fn thousands):

declared.

1983 I982 1981 (k) Retirement Plan. The Company has a noncontribu-tory retirement plan for all full-time employees and ts Common stock:

funding the costs accrued under the plan. Retirement plan Pubkc offenngs . 3.000 costs for !983. 1982 and 1981 were approximately SPSP ............ 812 669 590 S14.2'6.000. S15.946.000 and S I 1.223.000. respectively. The 2.034 I 2c7 actuancl present value of accrued benefits (assuming rates ESOP ........... 494 73 70 of return ot 11 percent and 14 percent. respectively) and the CSOP ........... 310 232 !4 market value of assets available for benefits. as of the most Total ......... 3.650 2.696 4 93 I recent valuation dates. are as follows (in thousands):

Preferred Stock-redemptfon required:

January I ~ Senal preferred stock 1983 1982 SI4 00 Seaes ..........

Acfuanct present value of accrued plan ber.e his At December 31. 1983. I A25.211 shcres of common stock Vested S 52.094 S35.643 Nonvested were reserved for issuance under ihe Stock Purchase-7.309 4,39l Savfngs Program for Employees (SPSP}. 6.134.960 shares Tot I S 59.403 S40.034 under the Automatic Dividend Reinvestment Plan f ADRP>.

Market ralue of assets cvailable for 1.080.406 shares under the Employee Stock Ownersi..ip Plea benefits 5103,640 S69.995 (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 4. Notes Payable and Lines of Credit stated at average cost. The Company maintains an cllowcnce tor doubtful accounts receivable (1983. At December 31. 1983. the Company had tirm. urused S2 477.COO: 1982. S1.757.000). Bond premium. discount cnd lines of credit with varous tinanc:ci insiitutiors totaling expense are amortized over the life of the related debt. 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

2. Investment in Coal-Mining Subsidiaries S61.000 per month. Such lines ot credit are reviewed On November 29. 1983. the Company acquired the periodically. at which time they may be renewed or rerrain:ng 20 percent interests fn its two coal-m:ning canceled.

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

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 S 7.316 S 29.055 S 52.732

-State (106) 18.933 {427)

Deterred taxes. net-Federal 142.887 913 808 4

-Stcrte 19.137 (1.939) 14.237 Investment tax cred:t ad,'ustments. net . (6.791) 86.660 (28.400)

Total 162.443 I 33.622 t tB.WO Included in other tncome (a)

Ileduchon in currently payable taxes-Federal . (9.791) (1.088) (58.026>

-State .... (813) (1.524) (!.037)

Detened taxes-Federal (a) (18.238) (35.514) 26.720

-State (a) (2337) (2.179) (3.334)

Investtnent tax credit adtustments. net 101 1.833 ( lo9)

Total (31.078) (38.472) (35.846)

Total income tax expense 5131.365(a) S 95 150(a) 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 . S 11.091(b) S 11.863(b) S 8.515(b)

Nuclear fuel disposal costs . 41.874 (19 466) 526 Aocelerated depreciation and other propeny cost differences.

Ortgtnattors . 62.374 59 131 43. IOO(c)

Reversals.... (32990) (37 753)

Deferred recognition ot gain on sale of generahng tact tihes. net . '4.201)

(94.080)

Unbilled revenues. net 1.770 (19. 729)

Deferred tax gain on sale ot tacilities. net 16.660 62. 160 Provision for possible refund ol revenues. net (17) 11.54o 5 902 Utihzation ol subsidianes tax losses . 8.347 5.87! 0.439 Canceled protect costs. net 93 432 (14.!00) 49 'F73 Tax loss cartytofward (39 Miscellaneous other timing differences. ret 659'17.(32>

"4 'o2} 4 O13 Total prov'store lor deterred income taxes. ret .. SI 4 lA49 S(38.719) SI 18 477 (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 37.6% 37,2L

'ihe effects of including ARJDC on other funds in pretax income 12.5 14.0 14.8 Effective income lax rate. excluding AFUDC on other tunds from prelax income . 52.9 51.6 52.0 State income taxes. net ol federal income lax benefit (3.4) (3.8) (3.3)

Other differences. net (3.5) (1 8) (2 7)

Statutory lederal income tax rale 46.(8 46.(P4 At December 31. 1983, the Company had generated but, The Company does not maintain its accumulated not utilized investment tax credits totaling approximately depreciation accounts on a separate unit basis ancL S109 million (including SIO millfon of ESOP credits). The therefore, amounts applicable to the Mayo Plant, Brunswick Company also generated a tax loss carryforward estimated Plant and Roxboro Unit No. 4 are not shown above. The at S81 million in 1983 and expected to be utilized in 1984. Company's share of expenses for the jointly owned units is included in the appropriate expense category in the statements of income.

6. Hafzis Unit No. 2 The total gain from the sale of the generating facilities to In December 19S3. the Company canceled further the Power Agency was S323 milifon net of income taxes and construction on Harris Unit No. 2. a 900.000 kilowatt nuclear is being amortized to other income over three years generating unit planned for completion in 1990. The beginning October l. 1983.

Company's share of the estimated final investment in the In connection with the sale of these facilities. the jointlyowned canceled unit is S315 million. The Company is Company is obligated to purchase portions (generally seelang regulatory permission to wnte off the costs over a starting at 50 percent) of the Power Agency's ownership period of ten years and to recover such costs through rates. 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.

. Joint Ownership of Generating Facilities The minimum payments applicable to Mayo Unit No. I and Hams Unit No. I are presently estimated at S5.561.000.

The North Carolina Eastern Municipal Power Agency S5.168,000, S35,2S5,000. S38.588.000. and S35,786.000. for the (Power Agency). which members include a majonty of the years 1984 through 1988. respectively, and S210, 195.000 ior Company's previous municipal wholesale customers. has the period 1989 through 2000. representing total estimated acquired undivided ownership interests in certain future minimum payments of S330.583.000 for such capacity.

generating facilities of the Company. The Company and Variable costs of such purchases are primanly tuel costs.

Power Agency are entitled to shares of the generating maintenance and other operation expenses for the capability and output of each unit equal to their respective respective units. Contractual purchases from Mayo Unft No.

ownership interests. Each also pays its ownership share. on a I commenced on iis commercial operation date. March l.

current basis. of additional construction costs. tuel inventory 1983, and totaled S14800.000 for 1983.

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

8. Commitments and Contingencies interests and investments in the jointly owned generating (a) Construction and Nuclear Fuel. The Company has facilities were as follows (dollars in millions): incurred substantial commitments inconnectionwith itscon-struction program. Construction expenditures ere estimated to be S1.7 billion and nuclear fuel expenditures S278 million Company fnvestment for 1984 through 1986 in connection with that program Plant or Unit Megawatt Ownership Plant Under (Type Fuel) capabrllty Inleresl ln service consaucnon (b) Leases. Rental commitments for operating leases and for unrecorded capital leases at December 31. 1983 cre Mayo Plant (Coat) 1 A40" 83.83% S4205 S 13.2 not material with respect to the Company's financial position Hams Plam (Nuclear) 900" 83.83% 1.438.7 or results ot operations.

Brunswick Plant (c) Insurance. The Company is a member of Nuclear (Nuclear) 1.580 8 1.67% 7296 100.9 Mutual Limited (NML). established to provide insurance Roxboro Unl! No. 4 coverage against property damage to insured's nuclear (Coal) 700 87.06'b 186.7 generating facilities. The Company is insured thereunder for S500 mtilion at the Brunswick Plant and S500 million at the nol include nuclear tueL costs. Robinson Plant. The Company cufTently would be subIect to srgn target capabrilry. maximum relrospecuve prerruum cssessments of cppmxl-

mately S65 million in the event losses at insured factltttes ettect on the tinanc:cl position or results of operations ct the

~ . exceed premiums. reserves. reinsurance and other NML Company resources. which are at present more than S300 mil!ton.

The Compar.y is also a member of Nuclear Electrc (e) Nuclear Fuel Disposal Cost. The inc!ear "..'cste

'nsurcnce Limited (NEIL). initially established to provide Policy Act of 1982 esi bltshes that the lederai aover." ..en'. is responsible for the d.'scosal o! spent nuclecr tue! cn"'.nc: the 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 owi.ers anc ope.=:oa ot ruclecr aenerctmg f'ac:!:ties will make pa trments to cover those costs. At Dece...ber ':

the net remcining cccumulcted provisicns rcr'.he esto..=,ea 983.

costs ot such dtsposai ccsts tncuneed through Apn! 6. 1983 ere (staning 26 weeks after the outage) and for Sl.250.000 per S29.267.000 less than!he required pxyrr en'.s or 588 mtI!tcn week for!he next 12 months for each operating nuclear Amounts attributcb!e to wholesale customers !otating aenerating unit. NE!L also provides decontamination and approximctely SIO mtilton. previously rea "redtersto be excess property insurance for nuclear generating facilities refunded. may be recovered in proceedtn-o ceto.e '.."ie The Company is insured thereunder for S435 million excess FERC. The Company expects to prospective!v increcse:!s ot 5500 mt!lion at both its Brunswick and Robinson plants. The charges to operattoris for tuel expense over c recscn"c.'e Company currently would be subject to retrospective period ot time for lhis change in the esnmaied ccs'.s "en'.

premium assessments of up to approximctely S23 million tuel disposal The Com"any must sele, "y .'une 3 with respect to the incrementcl replacement power costs from one of several payment optic".~ tor ine ccsis mc ..e" coverage and S!5 million with respeci to the decontamina- through Apnl b. 1983. Costs incurred therec"er .e pc:d tion cnd excess property coverage in the event covered expenses at insured facilities exceed premium reserves.

quarterly.

reinsurance and other NEIL resources. (f) Hanis Units Nos. 3 and 4. In Decemcer ! "8: '"--

The Company's public liability for a nuclear incident is Company eliminated these u..its !rom ..s cc."s:." -.:";.

protected up to the maximum limit on pub!ic liabilityclaims program. Pursucnt to regulctory authcr:z=iions. the pursuant to the Pnce-Anderson Act. which is S580 million for Company begat. amortizing in Ju!y 1922 the ccsis ecch occurrence. through conventional insurance pooh associated with these units and is recoverng the cos'.s cnd through an industry retrospective assessment program. throuah revenues Amounts amortized io operciing In the event that public hability claims from an insured expenses totaled S13.251.000 in 1983 and S6.95a.000 m 1982 nuclear incident exceed the pnmary tinancicl protection provided by the insurance pools. which is currently S160 9. Other Rate Matters million. the Company would be sublect to a pro rata Operating revenues increased S70.616.GGO in 1983 over cssessment of up to a maximum of S15 millionwith respect to 1982 cnd S140.548,000 in 1982 over 1981, ct:ncutccle to cny single nuclear inc:dent and cn aggregate maximum of general rate increcses placed in!o ettec'i s:r.ce 1980 ~so S30 million within any ca!endar year iiicluded in revenues. representing tuel cost billings ccove c (d) Claims. There are certain claims pending cgainst base cost of fuel (as defined for ecci: rc'.en:ck:na

'he Compcny !n lhe opinion of the Company. Iiabihties. !f

~

~ lunsdic! ion). is S40 617 GCO lor 1983. Sb).o45 GGO ior 1982 cnd ny. ansing !rom these claims would not have a matenal 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 .........""" S405.559 S359,935 S402.342 S370.329 Operaimg!ncome ......"".""" 90.! 34 8! ASS 44.750 57.768 55.232 55.473 n2 7'tn Net tncoine .

Earnings Per Common Share .......  !.24 46 76 Dividend Paid Per Common Share .. .60 JO .60 60 Common Stock Pnce Per Ware:

High 23 22' 22't 2!:r Low . !9& !9'-t 19 !8:1 1983 Operating Revenues .............. S416.638 $ 36!,370 5449.720 S420A55 Operaung!rcoine ................ 8!.359 49.853 69.540 63.204 Net Income . 78A60 44A38 60.182 56 189 Eammgs Per Common Share ......  !.13 .55 80 72 Dividend Paid Per Con mon Share . ,60 60 60 63 Coinmon Stock Price Per Share."

High . 23 22/0 23'i 25 ~

Low .

20.. 21 7 20-'t 21".

Supplemental Inflation Adjusted Data (Unaudited)

The data. as reported in the pnmary financial statements. Under ratemaking practices established by regulatory are based on actual. nominal. historical costs. However. commissions. the Company can recover through revenues dunng penods of significant cl.anges in general price only the onginal cos! (htstoncat costfnomiral dollars) levels. that nominal dollar information becomes distorted deprec:ation. Therefore. the increase m the dollar amount and fails to rellect real economic costs or value. The for the cost of plant (stated in either htstoncat cost/constant

-onvenhonal basis does not account for the event of dollars or current cost) over the onginat cost is deemed rot

flation.i.e,. variations over time in the purchasing power or presently recoverable and. therefore. must be reflected as a alue of the dollar. In an effort to provide financial "reduction in assets to net recoverable cost."

information about the elfects of changing pnce levels. the To further rellect the economics of regulation. the Financial Accour.ting Standards Board issued Statement No. reduction in asset "cost" is offset to the extent that the plant iis

33. Financial Reporting and Changing Prices. in September ffnanced from sources that have a fixed. or contractural. rate 1979 This statement requires most larger companies to of return and claim against assets of the Company. Under disclose (among other things) certain significant historical present ratemaking practices. the Company can recover cost data in constant dollars represented by the average through revenues the contractual rate of return for such level dunng the year of the Consumer Price index for all capital and. therefore. is able to effectively recover the Urban Consumers (CPI-U) and current cost information fnflation impact (purchasing power gain or loss) on such concerning the measurement of assets and the expiration of capital to the extent reflected iii the annual cost rate, Any asset values. holding gain associated with such capital (moretcry liabilities) fs therefore, not realizable and is ar. offset agatra The constant dollar information on the following the "reduction in assets to net recoverable cost.- The pages'eflects the nominal hlstoricat costs and prices treatment given herein to the holding gains on monetary restated by applying the CPI-U in conformity with Statement liabilities recognizes that prices charged by the Con.pcny No. 33. are designed to recover for such capital no more than any inflation costs factored mto the contractual annual cost rate.

The current cost information on the following pages Thus. the purchasing power adjustment to the tangible

.etlects changes in specific pnces of plant from the date the assets. which is not realizable and is wntten off. cs well as'.he plant was acquired to the present and differs from constant increased operating expenses. resu! ts in no fi.".ancial!oss;o dollar amounts to the extent that specific prices have the owners of the Company (the common shareholders) lo increased more or less rapidly than pnces in general. The the extent of the leverage financing.

current cost of property. plant and equipment. which includes land. land nghts. Intangible plant. property held for This information should be mewed as an esnmate ct the tuture use and construction-work-in progress. represents the approximate effects of inflancn. rather than a precise esnrnated cost of replacing existing plant assets and was measure.

determined pnmanly by indexing the surviving plant by the Handy-Whitman fndex of Public Utility Construction Costs. The statement of mcome. adlusted for changmg pnces The current cost of nuclear fuel was determined by recent reflects adjustments only with respect to electrc utility voice pnces, The current year's provision for depreciation plant-the area of the Company most affected by intlation.

rd amortization was determmed by applying !he All other items are considered to have been etteciively mpanys depreciation and amortization rates to the tr nsacted at average I983 once levels. and theretore. ao dexed'current cost an:ounts not require adlustment

Statement of Tacome from Continuing Operations Adjusted for Changing Prices for the Year Ended December 31, 1983 As Constant Current Reported Dollar Cost in the Average Average Primary 1983 1983 Statements Dollars Dollars (In Thousands)

Operating revenues S1.647.183 S1.647.183 S1.647.183 Operating expenses:

Operation and maintenance:

Fuel for generation 517.625 524.411 534ABB Other . 440.522 440.522 440.522 Depreciation and amortization 148.342 251.059 257.747 Taxes other than on income . 114.29S 114.29S 114.295 Income tax expense 162A43 162A43 162A43 Total operating expenses 1.383.227 1A92.730 1.509.495 Operating income 263.956 154.453 137.688 Other income-net 132.482 132.482 132.482 Income before interest charges Net interest charges .. .. 396.438 286.935 270.170 157.169 157.169 157. 1o9 Income from continuing operations (excluding reduction to net recoverable cost) 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" ....~..... ~.... S 63 908 Increase (reduction) in assets to net recoverable cost S (48.233) 154.692 Effect of increase in general price level ..........,. ~250.0oB}

Excess of increase in general price level over increase ln specific prices atter reduction to net recoverable cost 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 Pxices Year 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) 5 129.8 S 120.5 S I I 7.3 S 92.4 S I 28 3 Income from continuing operations per common share (after preferred stock dividend requirements and excluding reduction in assets to net recoverable cost) S 1.40 S l.29 S 1.34 S I 08 S 2 20 Net assets at year-end at net recoverable cost 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) S 113.0 S 102.2 S 104.7 S 79 7 S 1130 Income from continuing operations per common share (after preferred stock dividend requirements and excluding reductton in assets to net recoverable cost) S 1.13 S 098 S 1.10 S 0.82 S 1.82 Net assets at year-end at net recoverable cost 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 S 112.3 S I I6.9 S 266.9 S 368A S 373 9 Cash divtdends declared per common share $ 2A6 S 2A8 S 2.54 2.66 S 2 82 Market pnce per common share at year-end S 21.63 S 21.94 S 21.47 S ~094 S 2482 CPI-U-average 298.4 289 I 272,4 2468 2i74

-year wnd 303.5 292A 281.5 258 4 2299

CAROLINA PO .. LIGIIT COHPANY SCHESfLE V UTILITY PLANT For the Year Ended Decelaher 31, 1983 COLUHM A COLUHN 8 COLQfN C COLUHN D COLON E COLUHN F Balance at I Balance at Beginning Add it ions Other Changes- Close of Classification of'eriod ot Cost Retirements Debits/Credits Period Electric utility plant other then nuclear f'uel (at original cost):

In Service:

Intangible plant (Note 1) $ 177,329 $ 177,329 Production plant 1, 737,423,357 $ 521 9 491 5911 $ 14, 794, 742 $ 5484348825 cr 2818986859701 Transmission plant 445,247,587 94,492,331 1,744,221 2,661,619 540,657,316 Distribution plant 739 8 1 87 ~ 396 66,854,702 9,442,922 143,043 796,742,219 General plant 90 817 674 11 290 363 3 290 190 2 812 cr. 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 1,790,714 2, 551,907 1,757,399 3,548,113 Held for future use 10,350,091 2,551,907 12,901,998 Electric plant purchased or sold 4,496,639 484968639 cr. 0 Construction work in progress 1 994 905 675 32 054 196 cr. 265 300 843 cr. 1 697 550 636 Total electric utility plant other than nuclear fuel 5,024,396,462 660,130,379 29,272,075 315,176,419 cr. 5834080788347 Nuclear fuel (at original cost) 231 518 038 48 407 041 8 368 347 6 836 0!i3 cr. 264 II01 489 Total electric utility plant including nuclear fuel $ 5 255 914 5llti $ 708 618 220 $ 37 640 422 $ 322 012 462 cr. $ 5 604 879 836 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 $ 6380448427 cr.

Transfer of Harris Unit No. 2 to Deferred Debits 253,711,533 cr.

Electric Plant acquisition adjustment - VEPCO 1,757,399 Transfer between utility and non-utility property, etc. Ill 858 cr.

Total '$315 176 419 cr.

Nuclear fuel:

Original cost of property sold or subsequently transferred to Power Agency, and adjustments related thereto $ 888429755 cr.

Hiscellaneous adjustment" 2 II06 712 Tbtal 6,nx6; nrem~ ~~

CAflO IfII (<( 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 flalance at I Oafance at Beginning of h<fdi t ions I Other Changes - Close of Classification I Period ol Coot IIetirements Debits>>'Credits I Period Electric utility plant other than nuclear fuel (at original cost.):

In Service:

Intangible plant (Note I) i77,329 l77,329 Production plant 1,017,27 5,020 $ 45,216,509 $ 5,709,74O $ 119,270,432 cr. 1,737,423,357 Transmission plant 405,009,391 41,206, 349 1,201,296 73,143 445,247,507 Distr ihut ion plant. 684,800,709 59,512,354 0,122,692 2,916,945 739,107,396 Ceneral plant, 70 025 241 15 063 690 '1 724 810 1 346 447 cr. 90 817 674 Electric utility plant, in service 2,985,447,770 161,070,902 16,030,538 ii7,634,791 cr. 3)012)053)343 Electric plant acquisition adjustment 1,259,200 531,506 1,790,714 field for future use 10)370>624 >

73,210 93,751 cr. 10,350,091 Electric plant purchased or coler than nuclear fuel 4)054)336)745 630)204,190 16) 830) 530 451,305,935 cr. 5,024,396,462 Nuclear fuel (at original cost) 254 477 419 1(450 n,nc 19 U7 429 20 272 A36 cr. 231 510 038 Tol,ai electric utility plant including r>uc]ear f<<el . $ 5 1A(l 014 164 $ 654 734 274 $ 35 975,967 $ 471 657 971 cr. $ 5 255 914 500 (Note 2)

NOIIS 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.

21 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 $ 450)943)059 cr.

'f roost or holwoen utility o>>>I non-uliliIy properf y) elc. 442 076 cr.

I nial $ 45( 305 9'll cr.

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 53 571 Total $ 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 Balance at, I Balance at, 8eqinning of I Arlditinns Other Changes I Close Classification I Period I at Cost I Retirements I Periortnf'ebits/Credits Electric utility plant other thon nuclear fuel (at original cost):

In Service:

Intangihie plant (Note 1) 177,329 177,329 Production plant 1$ 775$ 613$ 683 f 39,439,450 347,223 cr. f 1,874,664 198l7$ 275$ 020 Transmission plant 375,072,239 31,934,619 2,631,888 714,421 40S,089,391 Dist ribut ior$ plant 645,726,714 51,366,379 9 $ 357 9600 2 9054 9704 cr. 604,080,789 Ceneral plant 66 505 674 13 403 077 I 770,999 192 511 cr. 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 1,259,208 1,259,208 Held for future use 1D,035,644 254,030 80,950 10,370,624 I iectric plant prrrctrased or sold 390029336 3,082,336 Construction work in proqress I 616 5I2,736 4fl9,f127 765 171 363 694 cr. I 054 176 807 l'otal elect.ric rrtiiity plant, other t.han nuclear fuel 4,490,983,227 54t39507,656 13,413,264 171,740,874 cr. 4 9 8 54 ~ 336 9 745 Nuclear fuel (nt. oriqinal cost) 218,466 220 36,222 905 113 567 9II 139 cr. 254 477 419 lotal electric util it.y plant, inciurlirrg r$ $ $ ciear Fuel $4 7fl9,449 447 $ 504 73fl 561 513,526,031 $ 171 039 013 cr. $5 IIIII 014 164 (Not.e 2)

NOlf S 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.

2. 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 $ I 71,203,454 cr.

Transfer between utility and non-utility propcrt.y 537 420 cr.

Total $ 171 740 II74 cr.

Nuclear frrr:I:

Sf)t:rrt fr$ el transportaLion charges transf'errcd t o>>rcrnmrlotcd provision for an3ortizatir>$ $ of'uclear furl 9B 139 cr.

Total $ 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 Additions Deductions from Reserves (I) I (2) (I) (2) I Balance at ) Charged Retirements, I Balance at Beginning of Charged to ) to Other Renewals, h ( Close of'e Oescri tion Period Income Accounts lacements Other Period Accumulated provision for depreciation of electric utility plant, other than nuclear fuel (Note 1) $ 792 fl12 456 $ 130 052 201 $ 26 282 05tl $ 11 532 494 $ 804 250 193 Accumulated provision for amortization of nuclear fuel $ 131 279 866 53tl 594 010 $ 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 COLUHN D COLUHN E Additions Deductinns from Reserves (I) I (2) (I) (2) I I Balance at I I Charged Retirements, I Balance at I Beginning of' I Charged to to Other Renewals, 5 I Close of Descri tinn Period I Income I Accounts I Re lacements Other I Period Accumulated provision for depreciation ot electc ic utility plant otl$ ec than nuclear fuel (Note I) $ 717 799 542 $ 114 154 540 $ 17,797 846 $ 22 143 780 5792 012 456 Accumulated pcovis inn for amortizaLion of nuclear fuel $ 144 791 161 $ 13 536 061 $ 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 I COLllHN 0 Cotlklw C COl.llHN D COLlk1N f Additions Ded<<ctjons from Reserves I I (i) I (2) (I) (2) I Balance at Charqcd Retirements9 I Balance at.

f Beginning of t Charged to I to Other Rene$ 8als9 h ( Close of Descri l,inn I Period Income I Acco$ $ nts Re $ lacements Other 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 $ 14 507 109 $ 57 296 $ 717 799 542 Accumulated provision for amortization of nuclear fuel $ 1M 597 818 $58 405 161 $ 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 COLUNN B COL0W C COLS' COLINN E Addi t ions I (I) I (2) I Balance at I Charged Deductions I Balance at I Beginning of I Charged to I to Other from Close of Descri tion Period Income I Accounts Reserves Period 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 5 712 882 -D- 5 4 969 302 Reserve for possible coal mine investment losses'0 $ 532 000 000 5 -D- 5 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 COLUHN B COLIlHN C COLUHN D COLUHN E Additions I (1) I (2) I I Balance at I Charged I Deductions I Balanco at Beginning of I Charged to I to Other I from I Close of Descri tion Period Income Accounts Reserves Period Reserves, deducted from related assets on the balance sheet Uncollectible accounts 5 I 532 729 S I 756 586 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 5 295 129 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 COLIl% B COLUNN C COLUHN D COLUNN E I Additions I I I (I)  ! (2) I I

) Balance at Charged Deductions I Balance at Beginning of Charged to I to Other from I Close of Descri tion Period Income Accounts 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 5 487 552 -D- 5 3 961 291 Reserve for possible refund of'evenues, net 5 7 794 531 516 798 420 -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 O

SCIIEDULE IX - SIIORT-TERH BORROWINGS for the Three Year's Ended December 31, 1903

'OLUMN A COLUHN 8 COLUHM C COLUHN D COI.UHN E COLUHM F Haximum Average I Weighted Category Weighted ) amount amount ( average""

of'ggregate Balance at average ) outstanding during interes't short-term end of inter'eot I during the the Irate during borrowin sa eriod rate cried cried >>>> the cried For the Year Ended December 31 1903 Bank loans $ 17 000 000 $ I 586 301 Commercial paper<$ $ + $ 153 200 000 9.70" $ 198 550 OIIO $ 111 095 969 9.22%

For the Year Ended December 31 1982 Bank loans 5 13 000 000 9.71" $ 38 00tl OtlO 5 I 334 247 2.94~

Commercial paper><> $ 146 575 000 8.66" $ 266 400 000 $ 216 245 066 12.86%

For the Year Enrled December 31 1981 Bank loans 5 17 000 000 2.65" 5 44 000 000 5 8 706 022 Comtaercis 1 paper>>$ 5

$ 239 250 000 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 1983 1982 1981 taxes:

Ad valorem $ 288296 4 29,117 S 26,964 State and city franchise 83, 356 76 8 707 70,947 Federal and state social security 15,467 13,457 10,713 Hlscellaneous 425 404 263 Total 127,544 119,765 100,887 Less-Amount charged to plant and s25ndry accounts 13 249 15 445 11 599 Remainder-charged to operating expenses 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 FINANCIALDISCLOSURE 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. 49 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 William E. Graham, Jr. 54 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 46 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.

Russell H. Lee 44 Senior Vice President, Customer and Operating Service Group, September 1982 to pr esent; Vice President - Eastern

'9 Division, September 1980; Division General Manager, June 1978; District Manager, January 1976.

Engineering M. A. McDuffie -

Senior Vice President Nuclear Generation Group, August 1983 to present; Senior Vice President - and Construction Group, December 1976.

Wilson W. Morgan 57 Senior Vice President - Corporate Services May 1979 to present; Vice President

-Group, 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 FINANCIALSTATEMENT 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) Restated Charter of Carolina Power 4 Light Company, dated May 22, 1980 (filed as Exhibit 2(a)(l), File No. 2-64193).

Exhibit No. 3a(2) By-laws of the Company as amended March 21, 1984.

Exhibit No. *3a(3) 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)

Exhibit No. *4a(2) 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)

Exhibit No. *4a(3) 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).

Exhibit No. *4a(4) 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).

Exhibit No. *4a(5) 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).

Exhibit No. ~4a(6) 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).

Exhibit No. *4a(7) 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) 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).

Exhibit No. *4a(9) 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).

Exhibit No. *4a{10) 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).

Exhibit No. *4a(ll) 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).

Exhibit No. *4a(12) 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).

Exhibit No. *4a(13) 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).

Exhibit No. *4a(14) 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).

Exhibit No. *4a(15) 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).

Exhibit No. *4a(16) 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) 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).

Exhibit No. <<4b(18) Mortgage and Deed of Trust dated as of May 1, 1940 b e tween e the Company and Irving Trust Company and Frederick G. Herbst (D. W. May,7 Successor), Trustees an

~ ~

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.

Exhibit No. 4b(19) Thirty-first Supplemental Indenture dated as of iAIarch 15, 1983.

Exhibit No. 4b(20) Thirty-second Supplemental Indenture dated as of March 15, 1983.

Exhibit No. 4b{21) Thirty-third Supplemental Indenture dated as of December 1, 1983.

Exhibit No. 4b(22) Thirty-fourth Supplemental Indenture dated as of December 15, 1983.

Exhibit No. *10a(l) 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).

Exhibit No. *10a{2) 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, togeether with resolution dated December 15, 1981 changing name to "69-

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).

Exhibit No. *10a(3) 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).

Exhibit No. *10a(4) 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.)

Exhibit No. *10c(1) 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.)

Exhibit No. 10c(2) Supplemental Executive Retirement Plan effective January l~ 1984.

Exhibit No. *10c(3) Retirement Plan for Outside Directors (filed as Exhibit 10c(3) to Form 10-K for year ended December 31, 1981, File No. 1-3382).

Exhibit No. *10c(4) 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.)

Exhibit No. 10c(5) Senior Management Deferred Compensation Plan.

Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges.

Exhibit No. 24a Consent of Deloitte Haskins dc Sells Exhibit No. 24b 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 Item 5. Other Events October 21, 1983 Item 5. Other Events Item V. 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. Acquisition or Disposition of Assets Item 5. Other Events Item V. 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 Item 5. Other Events (for the month of December, 1983.)

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 Title Date

/s/ Sherwood H. Smith Jr. Principal Executive (Sherwood H. Smith, Jre Officer and Director Chairman of the Board, President and Chief Executive Officer)

/s/ Edward G. Lill Jr. Principal Financial (Edward G. Lilly, Jr. Officet and Director Executive Vice President)

/s/ Paul S. Bradshaw Principal Accounting Paul S. Bradshaw Officer Vice President and Controller)

/s/ Daniel D. Cameron Sr. Director Daniel D. Cameron, Sr. March 23, 1984

/s/ Felton J. Caoel Director (Felton J. Capel)

Director George H. V. Cecil

/s/ Charles W. Coker Jr. Director Charles W. Coker, Jr.)

/s/ William E. Graham Jr . Director William E. Graham, Jr.

Director iVIargaret T. Harper)

~si ature Title Date

/s/ L. H. Harvin Jr. Director L. H. Harvin, Jr.)

Director (Karl G. Hudson, Jr.)

Director John G. Medlin, Jr. March 23, 1984

/s/ A. C. Monk Jr. Director A. C. Monk, Jr.)

Director Horace L. Tilghman, Jr.

/s/ E. E. Utlev Director (E. E. Utley)

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)

APPENDIX E rnst W inney 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 MUNICIPALPOWER AGENCY BALANCE SHEETS (Thousands of Dollars)

ASSETS December 3I 1983 1983

UTlLITY PLANT Notes 6 and M

'Electric plant in service (net of accumulated depreciation 1983 $ 14,105; 1982 $ 3,089) $ 366,689 $ 189,320 Construction work in progress 369,033 394,872

Nuclear fuel (net of accumulated amortization 1983 $ 5,378; 1982 31,792 17,259 767,514 601,451 SPECIAL FUNDS INVESTED ASSETS Note N Construction fund . 88,096 506,845 Bond fund . 230,647 213,798 Reserve and contingency fund 8,312 8,072 Decommissioning fund .. 1,458 570 Special reserve fund . 1,144 1,091 329,657 730,376 CURRENT ASSETS

Invested funds Note N Revenue fund. 44,538 7,306 Operating fund 20,238 4,053 Term-loan fund 3,885 5,556 Supplemental fund 19,195 21,521 87,856 38,436 Participant accounts receivable 18,195 13,549 Fossil fuel stock 6,126 3,990 interest receivable . 6,609 10,938 Prepaid expenses .. 333 223 119,119 67,136 DEFERRED DEEtTs Notes B, C, D and E VEPCO compensation payment . 14,770 15,158 Development costs . 9,234 7,310 Unamortized debt issuance costs 32,628 33,535 Cancelled nuclear unit 53,937 Nuclear fuel disposal fees 9,048 Net costs to be recovered from future billings to participants .......... 57,752 46,462 177,369 102,465 ToTAL AssETs 51.393.659 51.501.428 See notes to financial statements E-2

NORTH CAROLINA EASTERN MUNICIPALPOWER AGENCY BALANCE SHEETS thousands of Dollars)

LIABILITIESAND FUND BALANCE December st 1982 LONG-TERM DEBT

Revenue bonds payable Note F . $ 1,300,000 $ 1,300,000

Term loans payable Note H 13,597 25,000 Less: Unamortized discount . ~4),319 ~42,380) 1,272,278 1,282,420 SPECIAL FUNDS LIABILITIES

Construction fund payables Note E .. (119) 984

Term loans payable Note H 26,403 137,000 Accrued interest on bonds 76,523 64.196 102,807 202,180 CURRENT LIABILITIES Accounts payable 13,137 10,922 Accrued taxes . 2,397 1,952 Accrued interest on term loans 1,508 1,908 Miscellaneous current and accrued liabilities . 1.650 1.132 18,692 15,914 FUND BALANcE (DERcIT) Note 0 . ~118) 914 CohIMITMENTs AND CGNTINGENcIEs Notes I and L TOTAL LIABILITIESAND FUND BALANCE $ 1,393,659 $ 1.501.428 See notes to financial statements E-3

NORTH CAROLINA EASTERN MUNICIPALPOPOVER AGENCY STATEMENT OF REVENUES AND EXPENSES AND CHANGES IN FUND BALANCE (DEFICIT)

(Thousands of Dollars)

Ycl)r Ended December 31 1983 1983 Operating Revenues Sales of electricity to participants Note J $ 187,731 $ 129,967 Sales to utilities 14,861 202,592 129,967 Operating Expenses Operation and maintenance 17,575 7,926 Fuel 25,187 4,312 Power Coordination Services:

Purchased power 106,295 107,900 Transmission and distribution 15,643 10,441 Other 478 357

~

122,416 118,698 Administrative and general 7,620 2,588 Amounts in lieu of taxes..... 949 221',798 N.C. gross receipts tax . 11,154 Depreciation and amortization 11,611 3,592 196,512 145.135 NrT OPFR niNo INcob!E (DErtcIT) . 6,080 (15,168)

Interest Charges and Credits Interest expense 157,296 63,667 Amortization of debt issuance costs . 2,265 910 Investment income (54,982) (31,554)

Net interest capitalized Note M ~86.) 77 ~2.624) 18,402 30,399 Add net costs to be recovered from future billings to participants Note D . 11,290 46.492 ExcEss (DEFIclENcY) or. REYENUEs ovER ExPENsEs Fund balance (deficit) at beginning of period FUND BALANcE (DEFIcIT) AT END oF PERIQD Note 0 ................

(1,032) 914 ~ll 925

)

See notes to financial statements

NORTH CAROLINA EASTERN MUNICIPALPOWER AGENCY STATEMENTS OF CHANGES IN FINANCIALPOSITION (Thousands of dollars)

Ye28r Ended December 31

~ ~

1983 1982 I

SOURCE OF FUNDS Operations:

'perating revenues . $ 202,592 $ 129,967 Operating expenses ............................ (196,512) (145,135)

Items not involving funds:,

Depreciation and amortization 11,611 3,592 Amortization of nuclear fuel ... 4,432 946 TQTAL FRoM (UsED IN) OPERATIQNs......... ~ 22,123 (10,630)

Financing and Investments:

Bond issues ~ ~ ~ ~ .1,300,000 Term loan . 15,000 137,000 Investment income '. 54,982 31,554 Loan expenses .. (73,384) (61,953)

Items not involving funds:

Amortization of debt issuance costs 2,265 910 TOTAL FROM (USED FOR) FINANCING AND INVESTMENTS (1,137) 1,407,51,1 TOTAL SOURCE OF FUNDS 20,986 1,396,881 USE OF FUNDS Net additions to utility plant. 181,511 605,488 Additions to unamortized debt discount and issuance costs 97 76,998 Provision to retire term loans .....:.'............... 26,403 137,000 Provision for extraordinary nuclear fuel disposal fees .. 9,048 Net increase in other deferred debits 56,068 6.097 273,127 825,583 INCREASE (DECREASE) IN WORKING CAPITAL9 INCLUDING SPECIAL FUNDS ~ ~ ~ ~ ~ ~ ~ ~ 4 ~ ~ ~ ~ ~ ~ ~$ 252,)41) $ 571,298 CHANGES IN COMPONENTS OF WORKING CAPITAL, INCLUDING SPECIAL FUNDs Increase (decrease) in special funds $ (400,719) $ 730,376 Increase (decrease) in current assets:

Invested funds 49,420 29,628

Accounts receivable participants . 4,646 13,258 Fossil fuel stock . 2,136 3,990 Interest receivable (4,329) 10,935 Prepaid expenses . 110 211 (348,736) 788,398 Increase (decrease) in special funds liabilities .... ~.............. (99,373) 202,180 Increase (decrease) in current liabilities:

Accounts payable . 2,215 9,988 Accrued taxes 445 1,952 Accrued interest . (400) 1,848 Miscellaneous liabilities 518 1,132 96,595 217,100 INCREASE (DECREASE) IN WORKING CAPITAL9 INCLUDING SPECIAL FUNDS ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~$ 252,141) $ 571.298 E-5

NORTH CAROLINA EASTERN MUNICIPALPOPOVER AGENCY NOTES TO FINANCIALSTATEMENTS 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 receive ower and energy through the Agency.

All t h e Agency 's members are participants in the Initial Project, such project being comprised of the d 'd d h'nterests '

i in three nuclear and three fossil generation units resentl y in

'

commercial operation or under construction by Carolina Power & Light Company (CP& L).. With i the p ower d f m the Initial Pro'ect. together with supplemental purchases of power and energy from CP&L, the Agency provides the total electric power and energy requirements 'mentsofits o i s par i 'p ants, exclusive artici of power allotments from the Southeastern Power Administration.

an, ie Agency The ency hasa eentered into several agreements with CP&L which'overn the purchase, ownership, c onstruction operation and maintenance of the genera tin ing units in the Initial Project. Under these agreements.

manages th e c onstruction and operation of the generating units its in which the Ag encyy has un ivi e n'P&L

'

ownership interests. . Bot h CP&L and an the Agency have, the right to challenge the allocation o f construction charges fora period exten d'ing to pri'1 1 o f th e second year after which the challenged payment or a d'ustment ju was made.

The Agency has also entered into agreements with CP&L whereby thc Agency purchases power and egyi ex sso hat eceiived tthrou Company (VEPCO) for

~

roug h tthee Initial

'

niia Project in order to meet the total requirements of thee participants. . Th e Agency h as a ls o entered into agreements with CP&L and Virginia ec ric a ie wheeling of power and energy between the Agency an i s par i 'p or the

'o

'

reements with CP&L obligate CP&L to purchase from the Agency power and energy r insin sp ecified erccntages o ver a eriod of 16 years) of the Agency's entitlement to such power an d ene rgy from certain units after each has been placed in c o mmercial o p eration. CP&L b cgan p r h such power and energy from the Agency's entitlement from Mayo Un' nit 1 durin g 1983 under terms o f t h e agreements.

The Initial Project is esta t blished is e an nance u and financed under Power System Revenue Bond Resolution No. R-2-82

'

(Resolution) a d opte oar of Commissioners(Board) of the Agency. The Resoluution ted b y thee Board ion esestablishes a s ecial

'

f d t hold o p roceeds from debt issuance, such proceeds to be use sed for costss of ac q uisition and construction or cos 'nso f h I ' P ' nd to establish certain reserves. The Resolution also eestablishes '

'

s ecial funds in which Initial Project revenues from participants are to be deposited and from w which o eratin costs, debt service, ic op and other specilied payments are made.

The Agency has entered into two power sales agreements with each of o its p artici p ants for supplying the ner re uirements of the participants. Under the Initial Project Power Sales

" " g cy t o the p artici p ants their respective s ares o ni ia o' the Initial Pro'ect are pledged as security for on s issue un er a ment ofoperating expenses. Each participant isobligate i bli ated to pay ay iitsssshareofoperatingcostsand are debt service

t. Under the Su lemental Power Sales Agreements, the Agency sells to each participant

'

i ion power and energy it requires in excesss o tthee aadditional of tthat rovided at provi e by y output from the Initial Project.

Note B Significant Accounting Patlclcs Basis ofAccounting: The accounts o of thee Agency are maintained in accordance with the Uniform System

'

of Accounts of the Federal Energy Regulatory Commission, and are in conformi f ity with enerall y accepted accounting principles.

':

Electric Plant in Serviee: All direct and indirect expenditures, including interest charges on debt outstanding net of investment earnings on fun dss noot yet expended, related to the Agency's undivided ownership E-6

NORTH CAROLINA EASTFRN MUNICIPALPOPOVER AGENCY NOTES TO FINANCIALSTATEMENTS (Continued)

'

interests in four of CP&L's generatin units i s in commercial co operation have been recorded at original cost and

'

are eing depreciated (or amortized) on a s traight-line r basis over the average composite life of each unit's Construction worl'n Pro ress: All dir g:

outstanding net of investment earnings on funds nnot yeet expen i ect and indirect expenditures, including interest char es on debt ex endede, rc rclaated to the Agency's undivided ownership

'

in wo o 's generating units under construction are capitalized as Construction  % or'in k

'

until such time as the units become operational. Depreciation on a unit w'll i b e recognize wh en 'ogress it becomes operational.

Nuclear Fue/: All expenditures includin g inte 'rest on debt outstanding net of investment earnings on funds un s not yet et expended, related to the purchase and construction of the A enc 's undivide I f I o <<h e nuc Iear units are capitalized, amortized on the units of production method and cchar fu expense. Amortization of nuclear fuel costs in 1983 and 1982 includes a rovi ed to fuel arged S222,000, respectively, for estimated disposal costs.

'nd Deferred Debits: Deferred debits are shown net of accumulated amo mor t'ization.. Deve I opment costs are

't' '

bein g amortized on a straight-linc basis over the life of thee I ni ia P roject. U namortized debt issuance costs eing amortized on a straight-line basis over the term of thee debt.

are bein e . Net osts to Bee Recovered et Costs Rec v from Future Billings to Partici'p ants are nno t amortized but will be recovered thro'ugh future rates a es (seesee Note ote D'. ). H arris Unit 2 cancellation costs will be amortize r ized over the life of the corresponding revenue bonds (see Note E~. I Fossil Fuel Stac/': Fossil Fuel Stock is stated at cost.

1nvesttnentst The Agency is authorized under the Resolution to invest iitss fund un s in '.S... G overnment securities, Federal a gency securities, securities collateralizcd by securities oof thee U.S. G overnment or Federal ..

• , r a encies bank c ertificatcs

'

of deposit and other investment securities as aallowed owe in accor a d ance with provisions of the Resolution.

Investments arc carried at cost, adjusted I'r amortization of premium orr disc iscountw h ic h approximates market value (see Note N).

Taxest Income of the Ag enc ncy is exempt from Federal income tax ender Section 115 of the Internal Revenue Code. Under Chapter 159B of the General Statutes of North ort C aro I'ina, t e Agency is exempt from per y an ranchise or other privilege taxes. In lieu of property taxes th e Agency pays an amount which would ootherw'herwise be assessed on the real and personal property of thee Agency.. In I'ieu o a franchise or privilege

'

tax.x. thee Agencyenc pays a s to the t State an amount equal to six percent of the gross rec eip s rom sacs

'

f I o f electric p ower or ener gy, less such like amounts included in payments to vendors for el e ec t ric power or energy or related services.

Note C Vepco Compensation Payment The VEPCO compensation corn payment represents compensation to VEPCO for ear Iy termination of service to those par artici ants previously served by VEPCO. This payment and its related costs icipants s s were d e ferre d and are rev'O being amortized on a strai'g ht-line - inc basis over 40 years, theexpectcd lifeofthe Initial project. The December 31, 1983 balance of $ 14,770,000 includes the $ 15,515,000 payment to VEPCO and $ 33 000 o net of S778,000 accumulated amortization.

an, of capitalized ca interest,

Note D Net Costs to be Recovered from Future Billings to Participants Rates Ior power billings to participants are designed to cover "costs" as defined 'I' ne b y ( ) t e R esolution;

'oject

((2 ) the Initial Pr e Power Sales Agreements; and (3) the Supplemental Power ower Sal a es Agreements. The Ag enc ys rates willsyst ematically provide for the debt requirements operating fu n d s an d reserves as specified b y the Resol eso utioni and the Power Sales Agreements. Those ose "expenses",

expenses, accor accordin ing too Generally Accepted

' '

Accountin Princi rinciples(GAAP),

nnct e which are not included as '"costs" under the R eso Iution an t h e Power P Sales Agreements r are del'erred to such'periods as they are intended to be covered by rates.

E-7

NORTH CAROLINA EASTERN MUNICIPALPOPOVER AGENCY NOTES TO FINANCIALSTATEMENTS (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 .. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ $ 6,834 $ 8,457 Amortization of VEPCO compensation payment.............. 389 778 Amortization of acquisition adjustments 4,182 5,649 Amortization of debt issuance costs 2,265 3,175

.Amortization of development costs 206 319 Interest costs not capitalizable . 56,296 105,845 70,172 124,223 Bond Resolution Requirements Included in Charges to the Participants:

Debt service 22,885 22,885 Investment income not available for operating purposes........ 1,878 1,927 Changes in operating fund working capital requirements ~...... (1,252)

Special funds deposits . 37,943 44,231 Reserve and contingency fund valuation ~2,572) ~2.572 58,882 66,471 Net costs to be recovered from future billings to participants ... $ 11,290 $ 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 MUNICIPALPOPOVER AGENCY NOTES TO FINANCIALSTATEMENTS (Continued)

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 beginning in 1999 ....... ~...............

13.25% maturing in 2002 with annual sinking fund requirements 33,000 beginning in 2002............,.........

13.75% maturing in 2011 with annual sinking fund requirements 10,00% maturing in 2014 with annual sinking fund requirements 175,QQQ beginning in 2012 53,000 10.5Q% maturing in 2017 with annual sinking fund requirements beginning in 2015 . 93.000 400,000 Series 1982B 9.00% to 12.20% maturing annually from 1985 to 1994 ......... 24,810 12.875% maturing in 1998 with annual sinking fund requirements beginning in 1995 22,970 13.125% maturing in 2002 with annual sinking fund requirements beginning in 1999 37,360 13.50'Fo maturing in 2012 with annual sinking fund requirements beginning in 2003 262,850 10.75% maturing in 2/15 with annual sinking fund requirements beginning in 2013 50,000 9.00% maturing in 2017 with annual sinking fund requirements beginning in 2015 52,010 450,000 Series 1982C 7.00% to 10.75% maturing annually from 1985 to 1997 54,510 11.00% maturing in 2003 with annual sinking fund requirements beginning in 1998 . 66,450 11.25% maturing in 2018 with annual sinking fund requirements beginning in 2004 . 279,040 7.50% maturing in 2019 with annual sinking fund requirements beginning in 2018 . 50,000 450,000 5 l. 300.000 The Series 1982A Bonds maturing in 2017 willbe 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 of dollars) are as follows:

December 31, 1985 . S 3,605 December 31, 1986 . 3,950 December 31, 1987 4,975 Decemb r 31, 1988 . 5,480 December 31, 1989 and thereafter 1,281.990 Total bonds outstanding at December 31, 1983 ............... $ 1,300.000 E-9

NORTH CAROLINA EASTERN MUNICIPALPOPOVER AGEYCY NOTES TO FINANCIALSTATEMENTS (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 Agcnc h1aximnm Net Commercial Dependable Ultimate O~e ~Cbilil Ownership bitcgawatts Roxboro Unit 4 1980 700M% 12.94% 90.6M'14.0 Mayo Unit I 1983 705 16.17 Mayo Unit 2 1991 720 16.17 116.4 Total Coal-Fired Capability 321.0MW NUCLEAR-FUELED UNITS Agencv Maximum Net Commercial Dependable Ultimate

~Oli C~btlil ~Ob sbl iitcgawatts Brunswick Unit 2 1975 790 Miv 18.33% I44.8M'44.8 Brunswick Unit I 1977 790 18.33 Harris Unit I 1986 900 16.17 145.5 Total Nuclear-Fueled Capability . 435. 1 Total of All Units . 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 MUNICIPALPOPOVER AGENCY NOTES TO FINANCIALSTATEMENTS (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 MUNICIPALPOPOVER AGENCY NOTES TO FINANCIALSTATEMENTS (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 1983 1982 Amortized Market Amortlsed Market Cost Value Cost Value tThousands or dollars)

U.S. Treasury Bills $ 63,573 $ 63,570 $ 46,111 $ 46,211 U.S. Treasury Notes . 81,717 82,640 77,712 81,435 Federal Farm Credit Bonds 36,103 37,270 74,715 76,805 Repurchase Agreements . 94,261 94,261 206,730 206,730 Federal Home Loan Bank Notes .. 26,924 27,558 87,211 93,156 FNMA . 95,821 95,709 204,214 208,429 Bankers'cceptances . 21,298 21,177 68.438 68.438 Total Investments 419,697 422,185 765,131 781,204 Cash . ~2,184 ~2.1847 3,681 3,681 Total Cash and Investments $ 417,513 $ 420.001 $ 76L812 $ 784.885 Consisting of:

Special Funds . $ 329,657 $ 730,376 Current Assets . 87,856 38,436

$ 417,513 $ 768.812 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 willbe 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 MUNICIPALPOPOVER AGENCY SCHEDULE OF REVENUES AND EXPENSES BOYD RESOLUTION AND OTHER (Unaudited)

For the years ended December 31, 1982 and 1983 (Thousands of dollars) 1983 1983 Bond Bond Resolution Total Bond Resolution Total Bond Initial Supplemental Resolution Initial Supplemental Resolution

~Pro ect and Other'nd Other ~Pro ect and Other'nd Other REVENUES Sales of electricity to participants .. $ 65,225 $ 122,506>> $ 187,731 $ 4,816 $ 125,151>> $ 129,967 Sales to utilities ................. 14,861 14,861 Investment revenue available for operations . 36,266 2.106 38.372 19.043 1.028 20,071 TOTAL REVENUES ............ 116,352 124,612 240,964 23,859 126,179 150,038 EXPENSES Operation and maintenance ....... 17,575 17,575 7,926 7,926 Fuel . 25>187 25,187 4,312 4,312 Power coordination services:

Purchased power .........'..... 4,635 101,660 106,295 1,239 106,661 107,900 Transmission power....... ~.... 15,643>> 15,643 10,441>> 10,441 Other 478 478 357 357 4 4,635 117,781 122,416 1,239 117,459 118,698

Administrative and general CP&L 6,480 6,480 2,172 2,172

Administrative and general Power Agency 517 623 1,140 130 286 416 Amounts in lieu of taxes.......... 949 949 221 221 N.C. gross receipts tax ........... 3,914 7,240 '1,154 289 7,509 7,798 Letter of credit commitment fee ... 91 91 29 . 29 Interest on revenue bonds......... 22,885 22,885 Excess funds valuation transfers:

Reserve and contingency (2,572) (2,572)

Special funds deposits:

Reserve and contingency 2,720 2,720 Decommissioning.............. 852 852 572 572 Rate stabilization .............. 34,371 34,371 5,717 5,717 Change in operating fund working capital requirements 1,252 1.252 1,252 1.252 36.691 36,691 7,541 7.541 TOTAL EXPENSES...... 116.352 125.644 241.996 23,859 125.254 149,113 NET REVENUES OVER EXPENSES $ ~ 5 925 $ 925

>>

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 INTENTIONALLYLEFT BLANK E-15

NORTH CAROLINA EASTERN MUNICIPALPOWER AGENCY STATEMENT OF CHANGES IN FUNDS'SSETS (Unaudited)

For the years ended December 31, 1982 and 1983 (Thousands of Dollars)

Invested Assets Bond and Power December 31, Note Billing Investment 1981 Proeeedsi1) ~Reeel ts ~Earnln Disbursements Construction Fund Construction account .. ~............ $ $ 9?8,932 $ $ 7,456 $ (615,002)

Construction interest account ........ 222,724 6,921 Bond Fund Bond fund interest account .......... 70 Reserve account 153,045 3,962 Revenue Fund Revenue account 2,729 69 Rate stabilization account .........,. 3 Reserve & Contingency Fund ....... 8,121 115 Decommissioning Fund ............ (2)

Operating Fund Working capital account 4,501 352 (12,352)

- Fuel account Supplemental Fund . 99,337 860 (91,249)

Special Reserve Fund ................ 91 Term Loan Fund . 8.808 15,653(2) 677 ~27.009

$ 8,808 $ 1,367,323 $ 117,719 $ 20,574 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

Invested Invested Assets Bond and Power Assets Dccembcr 31, Note Billing Investment Dcccmbcr 31, Transtcr 1982 Proceeds ~Recci ts Earnings Disbursements Transfers 1983

$ (30.873) $ 340,513 $ 15,000 $ $ 16,932 $ (292,743) $ (23,347) $ 56,355 (63,313) 166,332 16,018 (150.609) 31,741 60,215 60,285 545 (140,719) 156,548 76.659 (3,494) 153,513 19,801 (19,326) 153,988 213 3,011 61,932 240 (60.661) 4 522 4,292 4,295 1,380 34,341 40.016 (164) 8,072 948 (3,548) 2,840 8.312 572 570 103 785 1.45S 11,005 3,506 744 (58,792) 70,814 1 f7.272 547 547 3.419 3.066 12,573 21,521 121,364 2,106 (111.069) (14,727) 19.195 1,000 1,091 96 (43) 1.144 7,427 5,556 489 (2.126) (34) 3.885 S 1S. 5768.812 515,000 $ 183,296 $ 59.402 5 1608.9971 S 5417.512

yl 0