ML023310575

North Carolina Electric Membership Corp Financial Statements as of December 31, 2001, 2000 & 1999 Together with Report of Independent Public Accountants

ML023310575
Person / Time
Site:	Oconee, Mcguire, Catawba, McGuire
Issue date:	02/08/2002
From:	Andersen A Andersen Corp
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML023310575 (126)

Text

ANDERSEN North Carolina Electric Membership Corporation Financial Statements As of December 31, 2001, 2000 and 1999 Together with Report of Independent Public Accountants

ANDERSEN REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of North Carolina Electric Membership Corporation:

We have audited the accompanying balance sheets of NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION, a North Carolina corporation, as of December 31, 2001 and 2000, and the related statements of operations and members' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States and the standards applicable to financial audits contained in Government Auditing Standards issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of North Carolina Electric Membership Corporation as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

In accordance with Government Auditing Standards,we have also issued a report dated February 8, 2002, on our consideration of North Carolina Electric Membership Corporation's internal control over financial reporting and our tests of its compliance with certain provisions of laws, regulations and contracts. That report is an integral part of an audit performed in accordance with GovernmentAuditing Standardsand should be read in conjunction with this report in considering the results of our audits.

SULLP Raleigh, North Carolina February 8, 2002

NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION BALANCE SHEETS - DECEMBER 31, 2001 AND 2000 (in thousands)

ASSETS 2001 2000 MEMBERS' EQUITY AND LIABILITIES 2001 2000 ELECTRIC PLANT: MEMBERS' EQUITY:

$1,434,279 Membership fees $1 $ 1 In-service $1,437,108 Patronage capital 22,112 22,112 Accumulated depreciation (648,016) (617,537) 789,092 816,742 Net unrealized gain (loss) on available-for-sale securities 290 (89)

Nuclear fuel, at amortized cost 29,968 34,416 22,403 22,024 Construction work-in-process 2,977 4,591 822,037 855,749 OTHER ASSETS AND INVESTMENTS:

Long-term investments 32,002 82,191 LONG-TERM DEBT 983,737 1,024,194 Noncurrent receivables 13,207 14,952 Investments in associated organizations 7,466 7,438 Special deposits 24,886 32,178 Decommissioning fund 57,252 56,180 CURRENT LIABILITIES:

134,813 192,939 Current maturities of long-term debt 40,454 47,482 Accounts payable 40,423 62,868 CURRENT ASSETS: Accrued interest 174 15,838 Cash and cash equivalents 15,668 14,189 11,560 Other accrued expenses 11,855 Short-term investments 10,727 14,264 137,748 92,906 Accounts receivable 103,608 120,857 Accounts receivable - affiliated companies, net 11,494 6,118 Interest receivable 1,035 1,155 Other current assets 532 147 DEFERRED CREDITS AND OTHER LIABILITIES:

143,064 156,730 57,252 56,180 Reserve for decommissioning DEFERRED CHARGES: Accrued Department of Energy assessment 4,057 4,548 Regulatory asset (Note 1) 26,824 3,284 Other noncurrent liabilities 2,709 2,509 Deferred loss on debt extinguishment (Note 6) 17,463 18,835 64,018 63,237 Debt issuance costs 7,606 8,084 Preliminary project costs 9,418 9,418 Other 1,839 2,164 63,150 41,785 COMMITMENTS AND CONTINGENCIES

$1,163,064 $1,247,203 (Notes 7, 8, 9, 10 and 11) $1,163,064 $1,247,203 The accompanying notes to financial statements are an integral part of these balance sheets.

NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION STATEMENTS OF OPERATIONS AND MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001,2000 AND 1999 (in thousands) 2001 2000 1999 OPERATING REVENUES $659,818 $664,894 $635,772 OPERATING EXPENSES:

Fuel and purchased power 422,790 428,593 409,451 Other production expenses 105,942 105,162 100,489 Depreciation and amortization 36,226 36,676 36,036 Administrative and general 21,375 20,510 17,700 11,648 12,061 12,262 General taxes 597,981 603,002 575,938 61,837 61,892 59,834 OPERATING MARGIN OTHER INCOME (EXPENSE):

Interest and dividend income 5,859 6,989 7,909 (126) 1,421 3,550 Other 5,733 8,410 11,459 INTEREST CHARGES:

Interest expense 65,252 68,133 69,064 2,318 2,169 2,229 Debt fees and expenses 67,570 70,302 71,293 NET MARGIN 0 0 0 CHANGE IN NET UNREALIZED GAIN (LOSS) ON (10,495)

AVAILABLE-FOR-SALE SECURITIES 379 9,951 COMPREHENSIVE INCOME (LOSS) 379 9,951 (10,495) 22,024 12,073 22,568 MEMBERS' EQUITY, beginning of year

$ 22,403 $ 22,024 $ 12,073 MEMBERS' EQUITY, end of year The accompanying notes to financial statements are an integral part of these statements.

NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (in thousands) 2001 2000 1999 CASH FLOWS FROM OPERATING ACTIVITIES:

Net margin $ 0 $ 0 $ 0 Adjustments to reconcile net margin to net cash and cash equivalents provided by operating activities:

Depreciation and amortization 40,138 40,382 38,461 Amortization of nuclear fuel 14,626 14,577 15,273 Amortization of regulatory liability 0 (19,180) (17,211)

Amortization of deferred revenues 0 0 (6,234)

Interest on decommissioning fund 1,072 4,513 3,684 Deferred charges (25,518) (2,559) (959)

Other noncurrent assets and liabilities 1,945 (4,356) (3,248)

Changes in other operating assets and liabilities:

Accounts receivable 11,873 (23,280) (12,207)

Interest receivable 120 (145) 220 Accounts payable (22,445) 16,035 313 Accrued interest (15,664) (1,283) 16,014 Other (88) (197) 298 Net cash and cash equivalents provided by operating activities 6,059 24,507 34,404 CASH FLOWS FROM INVESTING ACTIVITIES:

Additions to electric plant (17,140) (22,414) (16,836)

Increase in decommissioning fund (1,072) (4,513) (3,684)

Decrease in long-term investments 51,061 9,171 30,000 Decrease in deferred revenue fund 0 0 6,234 (Increase) decrease in short-term investments 3,044 (1,857) 4,469 7,013 8,193 (3,315)

Other, net Net cash and cash equivalents provided by (used in) investing activities 42,906 (11,420) 16,868 CASH FLOWS FROM FINANCING ACTIVITIES:

Principal payments of long-term debt (47,486) (35,786) (29,103)

Extinguishment of long-term debt 0 (108,150) 0 0 104,370 0 Proceeds from issuance of long-term debt Net cash and cash equivalents used in financing activities (47,486) (39,566) (29,103)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 1,479 (26,479) 22,169 14,189 40,668 18,499 CASH AND CASH EQUIVALENTS, beginning of year

$15,668 $ 14,189 $40,668 CASH AND CASH EQUIVALENTS, end of year SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

Cash paid during the year for:

Interest $80,699 $ 69,247 $52,884 0 0 0 Income taxes The accompanying notes to financial statements are an integral part of these statements.

NORTH CAROLINA ELECTRIC MEMBERSHIP CORPORATION NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2001, 2000 AND 1999

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Basis of Accounting North Carolina Electric Membership Corporation (the Company) is a member-owned cooperative of 26 electric membership cooperatives (the members) in North Carolina. The Company was formed in 1949 to develop itself as a full-requirements supplier, providing power generation, wholesale electric service and transmission to its members, who in turn service more than 800,000 homes, farms and businesses in North Carolina. The Company follows accounting principles generally accepted in the United States and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS).

Electric Plant Electric plant is stated at original cost, which is the cost of the plant when placed into service, plus the cost of subsequent additions and includes engineering and other indirect construction costs. The cost of renewals and betterments of property is capitalized. The cost of maintenance and repairs and replacements and renewals of items determined to be less than units of property is charged to expense when incurred. At the time properties are disposed of, the original cost plus the cost of removal less salvage of such property, is charged to accumulated depreciation, except in certain cases of properties sold as entireties where profit or loss is recognized.

Depreciation Depreciation is computed using the straight-line method over the estimated service lives of the property as follows:

Estimated Lives Catawba Nuclear Station 40 years Diesel generation equipment 30 years Load management equipment 15 years Building and improvements 35 years Furniture and fixtures 5-10 years Computers and telecommunications equipment 3-10 years Automobiles 4 years

The depreciation rate for the Catawba Nuclear Station (Note 2) has historically included a component to provide for the expected cost of decommissioning the nuclear facility. Based on projected returns from the external trust fund and projected future funding, no such provision was recorded in 1999, 2000 or 2001. In compliance with a Nuclear Regulatory Commission (NRC) regulation, amounts recovered through rates for estimated decommissioning costs (plus interest thereon) are maintained in a separate external trust fund. The provision for expected decommissioning costs, if any, is charged to operations with an offsetting credit to the reserve for decommissioning. Investment earnings generated from the external trust fund designated for decommissioning are maintained in the decommissioning fund with a corresponding increase to the reserve for decommissioning.

The estimate of the expected cost for decommissioning is adjusted periodically to reflect changing price levels and technology. Using a 1999 site study of expected decommissioning costs, including the costs of decontamination, dismantling and site restoration, the Company estimates its portion of such costs to be approximately $543,745,000. The estimate assumes a future annual escalation rate of 3.0% in decommissioning costs and an average investment earnings rate of 6.5%. The decommissioning cost estimates are based on the plant location and cost characteristics for Catawba and assume prompt dismantlement and removal of the plant from service. The actual decommissioning costs are expected to vary from the above estimates because of changes in assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment.

In 1996, the Company determined that the decommissioning liability was overstated based upon the revised estimate of ultimate decommissioning costs. As a result, a regulatory liability of $73,000,000 was reported for amounts to be refunded to members. A similar amount was transferred from the decommissioning fund to long-term investments. In 1998, the Company determined that the decommissioning liability remained overstated in the amount of $20,907,000. An additional regulatory liability was created and a similar amount was transferred from the decommissioning fund to long-term investments. This regulatory liability was amortized through 1999, based on each member's KW and KWH billing determinants for the applicable year. Total amortization of this regulatory liability was

$8,579,000 in 1999.

Regulatory Assets and Liabilities The Company currently complies with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended by SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and, accordingly, has recorded regulatory assets and liabilities related to its operations. This statement requires that regulatory assets be probable of future recovery at each balance sheet date. If recovery of the regulatory assets becomes unlikely or uncertain, these accounting standards may no longer apply. The Company periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its regulatory assets are probable of future recovery in the near term.

The Company incurred significant purchased power costs in excess of budgeted amounts during 2001.

The Board of Directors determined that these costs would be collected through increased rates in 2002.

Accordingly, the Company established a regulatory asset of $24,313,000 which will be amortized over 2002.

The Company has provided funding to support cooperative efforts in the northeastern United States. The Company established a regulatory asset for these amounts which totaled $2,511,000 and $3,284,000 at December 31, 2001 and 2000, respectively. These assets are being amortized on a straight-line basis over a period not to exceed five years. Total amortization of this regulatory asset was $773,000 in 2001 and $557,000 in 2000

Nuclear Fuel The cost of nuclear fuel, including a provision for the estimated cost of permanent storage of spent fuel, is being amortized based on core burn-up and amounted to $14,626,000 in 2001, $14,577,000 in 2000 and

$15,273,000 in 1999. Final disposition of the spent fuel may require future adjustments to fuel expense.

Pending ultimate disposition, sufficient storage capacity for spent fuel is available through 2008. The accumulated amortization is $85,119,000 and $70,009,000 at December 31, 2001 and 2000.

Derivative Accounting The Company adopted the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (the Statement), as amended, beginning January 1,2001. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. The Statement requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Substantially all of the Company's bulk power purchases and sales meet the definition of a derivative under SFAS No. 133. However, these transactions also meet the normal purchase and sale exception under the Statement and therefore do not need to be accounted for as derivatives.

In addition, the Company began using derivative instruments during 2001 to manage the risks associated with the short-term (less than 90 days) impact of fluctuating natural gas fuel prices on purchased power contracts. These derivatives are carried at their fair market value as determined by broker quotes and are recorded as derivative assets of $26,000 in other current assets and derivative liabilities of $545,000 in other accrued expenses in the accompanying balance sheets at December 31, 2001. As these derivatives are designated as cash flow hedges, certain gains or losses are deferred as a component of members' equity and will be recognized concurrently with the hedged purchased power costs.

Revenue Deferral Plan In 1991, the Company established, and the RUS approved, a revenue deferral plan. The plan provided for a predetermined increment to be included in rates charged to members during 1991 through 1995.

Revenues collected through the revenue deferral plan were deferred and were utilized to reduce member revenue requirements in 1996 through 1999 as authorized by the Board of Directors. The deferred revenues were allocated to members based on their KW and KWH billing determinants for the applicable year. The cash equivalent of all deferred revenues was segregated into the deferred revenue fund and remained in such fund until it was used to reduce member revenue requirements. The deferred revenue balance was fully amortized at December 31, 1999. Deferred revenue amortization reduced member revenue requirements by $6,234,000 in 1999.

Membership Fees and Patronage Capital The Company is organized and operates as a cooperative. Its cooperative members paid a total of $700 in membership fees.

Patronage capital is the net margin retained by the Company which is allocated to members based upon their respective purchases of power from the Company.

Income Taxes The Company is a not-for-profit membership corporation exempt from federal income taxes. In management's opinion, based on the applicable statutes, the Company is not subject to state income taxes.

For the years 1984 and prior, the Company claimed tax-exempt status under Section 501 (c)(1 2) of the Internal Revenue Code of 1954 (the Code), as amended. In 1985, the Company reported as a taxable entity as a result of income received from Duke Power Company (Duke) under a capacity and energy sell-back agreement applicable to Catawba Units No. 1 and 2. As a taxable electric cooperative, the Company annually allocated its income and deductions between member and nonmember activities. Any member taxable income was offset with a patronage exclusion.

In 1999, the Company reapplied for tax-exempt status under Section 501(c)(12) of the Code. The application was approved by the Internal Revenue Service retroactively effective as of January 1, 1996.

The impact of this event resulted in the elimination of the accumulated deferred federal income tax liability of $110,453,000 and related noncurrent receivables from members of $12,438,000. In addition, a regulatory asset of $59,467,000, related to the Duke Settlement (Note 9), was eliminated at the same time as authorized by the Board of Directors. As a result of these events, the Company established a net regulatory liability of $38,548,000 to be amortized through 2000. Total amortization of this regulatory liability was $19,180,000 in 2000 and $8,632,000 in 1999. The remaining net balance of $10,736,000 as of December 31, 2000, was returned to members or will be collected from members, based on each member's contribution to the total balance. Accordingly, $14,586,000 of the regulatory liability balance at December 31, 2000, was returned to members in 2001. The remaining balance due from members was

$1,723,000 and $3,850,000 at December 31, 2001 and 2000, respectively.

Deferred Charges Deferred charges, other than preliminary project costs (Note 9), are amortized using the straight-line method over the following estimated periods:

Estimated Periods Regulatory asset 1-5 years Deferred loss on debt extinguishment (Note 6) 17-24 years Debt issuance costs 24-30 years Other 5 years Cash and Cash Equivalents The Company considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications Certain reclassifications have been made to the prior-year financial statements to conform to the current-year presentation.

New Accounting Pronouncements The Company is required to adopt the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" beginning January 1, 2003 and January 1, 2002, respectively. SFAS No. 143 establishes accounting and reporting standards for the way companies recognize and measure retirement obligations that result from the operation of a long-lived asset. The Statement requires that the fair value of asset retirement obligations be recorded in the balance sheet at the time the liability is incurred which, in many cases, will be when the asset is placed in service. The cost associated with recognizing this obligation is capitalized into the cost of the related long-lived asset. The Company has not yet determined the impact that SFAS No. 143 will have on its financial statements.

SFAS No. 144 established new accounting standards for the impairment of long-lived assets.

Management does not believe SFAS No. 144 will have a material impact on its financial statements.

2. JOINTLY OWNED ELECTRIC PLANT AND RELATED AGREEMENTS On February 6, 1981, the Company entered into (a) the Catawba Nuclear Station Purchase, Construction and Ownership agreement with Duke, together with (b) an Operating and Fuel Agreement and (c) an Interconnection Agreement (the Contracts). Contracts (a) and (b) basically provide for the purchase by the Company of a 56.25% undivided interest in Unit No. 1 of the Catawba Nuclear Station together with a 28.125% interest in the support facilities, and for a sharing of direct construction and operating costs in relation to the respective ownership share of the parties. The Company's total investment in jointly owned facilities amounted to $1,355,078,000 and $1,351,071,000 as of December 31, 2001 and 2000, including capitalized interest expense, net of related investment income.

The cost of power purchased from Duke, as well as power purchased by the Company for its members from Carolina Power & Light Company (CP&L), Virginia Electric and Power Company (VEPCO) and American Electric Power Company (AEP) has been recorded as purchased power on the accompanying statements of operations and patronage capital.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS A detail of the estimated fair values of the Company's financial instruments as of December 31, 2001 and 2000, is as follows (in thousands):

2001 2000 Carrying Fair Carrying Fair Amount Value Amount Value Cash and cash equivalents $ 15,668 $ 15,668 $ 14,189 $ 14,189 Short-term investments 10,727 10,727 14,264 14,264 Long-term investments 32,002 32,002 82,191 82,191 Special deposits 24,886 24,886 32,178 32,178 Decommissioning fund 57,252 57,032 56,180 59,102 Long-term debt 1,024,191 1,098,157 1,071,676 1,108,601

For cash and cash equivalents, the carrying amount approximates fair value due to the short maturity of those instruments. The carrying amount of the decommissioning fund is determined based on the requirements of the related obligation. The special deposits fund balance is contractually determined to meet certain funding requirements. The fair value of the Company's long-term debt is estimated by management based on the current rates offered to the Company for debt of similar maturities.

The Company's investments may be classified as available-for-sale, trading or held-to-maturity.

Available-for-sale securities are carried at market value with unrealized gains and losses added to or deducted from equity. Trading securities are also carried at market value with unrealized gains and losses charged to income. Held-to-maturity securities are carried at amortized cost. All realized and unrealized gains and losses are determined using the specific identification method. As of December 31, 2001 and 2000, $57,252,000 and $56,180,000, respectively, of the decommissioning fund has been classified as held-to-maturity. All other investments are classified as available-for-sale.

The amortized cost, gross unrealized holding gains, gross unrealized losses and fair value of available-for-sale and held-to-maturity securities by major security type at December 31, 2001 and 2000, were as follows (in thousands):

Gross Gross Amortized Unrealized Unrealized Estimated December 31 Cost Gain Loss Fair Value 2001:

Available-for-sale securities:

U.S. Government and agency securities $ 23,324 $ 259 $ (123) $ 23,460 Corporate bonds 28,001 616 (79) 28,538 Equity investments 0 0 0 0 Other 31,668 169 (552) 31,285

$ 82,993 $1,044 $ (754) $ 83,283 Held-to-maturity securities:

U.S. Government and agency securities $ 7,787 $ 41 $ (46) $ 7,782 Equity investments 17,781 187 (156) 17,812 Demand notes 24,327 2,789 (3,024) 24,092 Other 7,357 7 (18) 7,346

$ 57,252 $3,024 $(3,244) $ 57,032 2000:

Available-for-sale securities:

U.S. Government and agency securities $ 19,064 $ 324 $ (176) $ 19,212 Corporate bonds 30,959 143 0 31,102 Equity investments 7,200 0 (385) 6,815 Other 85,688 34 (29) 85,693

$142,911 $ 501 $ (590) $142,822 Held-to-maturity securities:

U.S. Government and agency securities $ 15,243 $ 0 $ (789) $ 14,454 Equity investments 12,963 0 (398) 12,565 Demand notes 23,348 4,098 0 27,446 Other 4,626 11 0 4,637

$ 56,180 $4,109 $(1,187) $ 59,102

Proceeds from the sale of marketable securities were $393,085,000, $181,255,000 and $155,722,000 in 2001, 2000 and 1999, respectively. Related net realized gains included in income were $141,000,

$1,475,000 and $3,493,000 in 2001, 2000 and 1999, respectively.

4. INVESTMENTS IN ASSOCIATED ORGANIZATIONS Investments in associated organizations are stated at cost at December 31, 2001 and 2000, and were as follows (in thousands):

2001 2000 TSE Services Inc. preferred stock $2,000 $2,000 National Rural Utilities Cooperative Finance Corporation:

Subordinated Term Certificate 4,970 4,970 Capital Term Certificates 318 319 Patronage capital certificates 117 116 Other 1 1 Other investments 60 32

$7,466 $7,438 The Company purchased cumulative preferred stock in TSE Services Inc., a related party (Note 11), with a liquidation preference of $2,000,000.

The Subordinated Term Certificate bears interest at 6.75% per annum. The Capital Term Certificates bear interest at 3% to 5% per annum. These certificates are required to be maintained under debt agreements with the National Rural Utilities Cooperative Finance Corporation (NRUCFC) in an amount at least equal to 5% of the original debt issued or guaranteed by NRUCFC until maturity of the related debt instruments. These investments in associated organizations are similar to compensating bank balances and are necessary in order to maintain current financing arrangements.

5. SPECIAL DEPOSITS Special deposits consist of debt service reserve funds for pollution control bonds as required by the Company's bond agreements and the Company's agreements with Duke. Debt service reserve funds totaled $8,886,000 and $8,860,000 at December 31, 2001 and 2000, respectively.

In 1994, under the terms of its Catawba ownership agreements with Duke as discussed in Note 2, the Company entered into an Amended Depository Agreement with Duke under which the Company was required to establish a Special Reserve Fund depository account in an amount equal to the greater of

$750,000 or one percent of the Company's estimated payments to Duke under the terms of the Interconnection Agreement plus one-sixth of the Company's estimated payments to Duke under terms of the Operating and Fuel Agreement during the current fiscal year. The depository account totaled

$18,504,000 and $23,269,000 as of December 31, 2001 and 2000, respectively.

6. LONG-TERM DEBT Long-term debt consists of mortgage notes payable to the United States of America acting through the Federal Financing Bank (FFB) and the RUS, Pollution Control Revenue Bonds and promissory notes to NRUCFC. Substantially all assets of the Company are pledged as collateral for the debt. The terms of the mortgages, notes and bonds are as follows (in thousands):

2001 2000 FFB mortgage and RUS note advances, maturing at various dates through 2018 with fixed interest rates ranging from 5.00% to 8.06% at December 31, 2001 and 2000 $ 919,159 $ 966,629 Pollution Control Revenue Bonds, Series 2000, with principal payments due in 2020 through 2024, guaranteed by NRUCFC, three series with interest payable monthly at varying rates (average of 1.9% and 4.60% at December 31, 2001 and 2000, respectively) 99,400 99,400 NRUCFC note, interest payable semi-annually at 9.05%, principal payments due in 2020 through 2024 4,970 4,970 NRUCFC note advances, interest and principal payable quarterly through June 14, 2023, interest rate of 6.0% and 5.88% at 662 677 December 31, 2001 and 2000, respectively 1,024,191 1,071,676 (40,454) (47,482)

Less - Current maturities

$ 983,737 $1,024,194 In conjunction with a debt refinancing in 1998, the Company financed a premium of $96,192,000 with respect to debt that was not substantially modified. The premium with a remaining balance of

$85,576,000 as of December 31, 2001, will be paid and recognized as interest expense over a 17-year period (the remaining life of the debt at the time of refinancing). Additionally, a loss on extinguishments of

$21,313,000 was incurred with respect to the debt that was substantially modified. This loss was recorded as a deferred charge to be amortized over the same 17-year period. The refinancing will result in a net economic benefit of approximately $68,647,000 over the term of the modified notes.

In September 2000, the Company refunded the remaining Series 1984 Pollution Control Revenue Bonds with an outstanding principal balance of $108,150,000. In connection with the refunding of the bonds, the Company sold the securities in the corresponding Debt Service Reserve Fund and recognized a gain on the sale of $667,000. In addition, the Company wrote off $997,000 of original debt issuance costs which was recorded as a deferred charge to be amortized over a 24-year period (the remaining life of the debt).

Also, in September 2000, the Company issued Series 2000 Pollution Control Revenue Bonds, guaranteed by NRUCFC, in the amount of $99,400,000. The bonds were issued in three series, with principal payments due in 2020 through 2024. Interest on the bonds is payable monthly at varying rates. In addition, the Company borrowed $4,970,000 from NRUCFC to finance the purchase of a subordinate term certificate with NRUCFC, a requirement for NRUCFC to guarantee the pollution control bonds.

Maturities of the long-term debt described above for the five-year period beginning January 1, 2002, and thereafter, are summarized below (in thousands):

Years Amount 2002 $ 40,454 2003 42,554 2004 45,112 2005 47,641 Thereafter 848,430

$1,024,191 The Company also has a $30 million line of credit with NRUCFC which was unused at December 31, 2001 and 2000. The interest rate available under this agreement would be determined at the time an advance is made. This line of credit is perpetual and is subject to withdrawal on a revolving basis as needed.

7. EMPLOYEE BENEFIT PLANS All employees of the Company participate in the National Rural Electric Cooperative Association (NRECA)

Retirement and Security Program (the Program), a defined benefit pension plan qualified under Section 401 and tax exempt under Section 501 (a) of the Code. In this multiemployer plan, which is available to all member cooperatives of NRECA, the accumulated benefits and plan assets are not determined or allocated separately by individual employer. The Company makes annual contributions to the Program equal to the annual pension expense, except during a period when a moratorium is in effect.

Payments to the Program for current period service cost were $1,549,000 in 2001, $1,283,000 in 2000 and $999,000 in 1999.

All employees of the Company are eligible to participate in the NRECA Savings Plan, a defined contribution plan qualified under Section 401 (k) and tax exempt under Section 501(a) of the Code.

Eligible employees may make contributions to the plan of up to 15% of their salary. The Company matches employee contributions to the plan up to 3% of the employee's salary. Total company contributions to the NRECA Savings Plan were $286,000 in 2001, $268,000 in 2000 and $253,000 in 1999.

8. OTHER POSTEMPLOYMENT AND POSTRETIREMENT BENEFITS The net postretirement benefit liability recognized by the Company, included in other noncurrent liabilities on the accompanying balance sheets, is summarized as follows (in thousands):

2001 2000 Retired plan participants $ 455 $ 477 Active plan participants 1,357 1,196 Unrecognized actuarial gain 493 442 Accumulated postretirement benefit obligation $2,305 $2,115

Net postretirement benefit cost for 2001 and 2000 is included in administrative and general expenses and consists of the following components (in thousands):

2001 2000 1999 Service cost - Benefits attributed to service during the period $141 $123 $170 Interest cost on accumulated postretirement benefit obligation 113 112 118 Amortization of actuarial gain (22) (20) 0 Net postretirement benefit cost $232 $215 $288 The Company has revised certain assumptions related to the computation of the accumulated postretirement benefit obligation, resulting in a net actuarial gain of $493,000. For measurement purposes, a 9.0% annual increase in the cost of covered health care benefits was assumed for 2001, the rate was assumed to decrease gradually to 5.5% in the year 2008 and remain at that level thereafter.

Increasing the assumed health care cost trend by one percentage point would increase the accumulated postretirement benefit obligation for 2001 by $49,000. The average discount rate used in determining the accumulated postretirement benefit obligation was 7.25%.

9. COMMITMENTS AND CONTINGENCIES Duke Power Company Settlement As discussed in Note 2, the Company and certain other parties (the Catawba buyers) own various undivided interests with Duke in Catawba. As of December 31,1993, a number of contractual disputes existed between the Catawba buyers and/or the Company and Duke, which were resolved in 1994.

One dispute related to billings rendered to Duke by the Company totaling approximately $162,176,000 for income taxes accrued through December 31, 1993. Duke contested the appropriateness of this amount and, therefore, had not paid any amounts billed through 1993. The other disputes related to differences among the parties on interpretation of certain provisions of the Catawba contracts.

In March 1994, the Company and Duke agreed to a settlement of all outstanding disputes. Under the terms of the settlement, Duke paid the Company $75,017,000. Since the terms of the settlement provide that Duke has no further liability for income taxes, the Company wrote-off the remaining receivable balance of $87,159,000 and recorded a regulatory asset in the amount of $56,654,000, which is net of a reduction in accumulated deferred federal income taxes of $30,505,000. This regulatory asset was being amortized over a 20-year period in accordance with the recovery period established by the Board of Directors. The remaining unamortized asset balance was written off in 1999 in conjunction with the Company's reapplication for tax-exempt status (Note 1).

Department of Energy Assessment The Energy Policy Act of 1992 gave the Department of Energy (DOE) the authority to assess utilities for the decommissioning of its facilities used for the enrichment of uranium included in nuclear fuel costs. In order to decommission these facilities, the DOE estimates that it would need to charge utilities a total of

$150,000,000, adjusted for inflation, annually, for 15 years based on enrichment services to date. Based on preliminary estimates from Duke, the Company recorded its share of the liability. A corresponding asset was recorded as nuclear fuel and is being amortized to nuclear fuel expense over the 15-year assessment period. The estimated remaining liability at December 31, 2001, of $4,057,000 is included in the accompanying balance sheets in deferred credits and other liabilities.

Power Coordination Agreements and Purchased Power Commitments In 2001, the Company entered into Power Supply Agreements (PSA) with American Electric Power Service Corporation (AEP), Dominion Davidson, Inc. (Dominion) and South Carolina Electric & Gas Company (SCE&G) to supply capacity. AEP will provide 100 MW in 2003 and 150 MW in 2004 through 2012. Dominion will provide 100 MW in 2003, 250 MW in 2004 and 570 MW in 2005 through 2030.

SCE&G will provide 250 MW beginning in 2004 and continuing through 2012. These resources will replace resources previously supplied under other contractual arrangements and will be used to serve NCEMC's intermediate needs.

In 1998, the Company negotiated a PSA with CP&L which replaced the Power Coordination Agreement.

In addition, the Company negotiated a Network Service Agreement which provides for transmission service under CP&l's open access transmission tariff. The new PSA provides for an annual peak rate for the top blocks which is essentially revenue-neutral. These new agreements became effective January 1, 1999.

Also in 1998, the Company entered into an additional purchased power agreement with CP&L for 800 MW of peaking capacity beginning in 2001. The capacity from this purchase will be used to serve NCEMC's peaking needs in 2002 and 2003 in the Duke and CP&L areas, with options to extend to all or part of the 800 MW for 2004 and 2005. The agreement provides for fixed capacity charges and energy charges capped at a gas-indexed rate.

In 1996, the Company renegotiated the Interconnection Agreement with Duke, the Power Coordination Agreement with CP&L and the power supply contract with VEPCO. The negotiations resulted in varying contract expiration dates with more power supply flexibility at prices more closely related to market conditions.

In 1996, the Company began receiving 200 MW of capacity from AEP to replace requirements previously provided by CP&L. The agreement extends through 2010 and provides for fixed capacity charges and system average energy costs.

Plant Construction Agreement During the mid-1 990s, the Company purchased property, incurred licensing and architect fees and entered into an agreement to build a combined-cycle natural gas-fired electric generating plant.

Construction of the plant was scheduled to begin in 1998 Due to changing power supply market conditions, in 1996 the Company decided to delay the construction of the generating plant indefinitely.

The Company has capitalized these preliminary project costs of $9,418,000 through December 31, 2001, in the accompanying balance sheets. Prior to year-end, the Company entered into a definitive agreement with Dominion to sell the property for approximately $12,000,000 contingent upon receiving approval from RUS.

10. NUCLEAR INSURANCE Duke maintains nuclear insurance coverage on its nuclear facilities in three areas; liability coverage, property, decontamination and decommissioning coverage and extended accidental outage coverage to cover increased generating costs and/or replacement power purchases. The Company, along with other joint owners of Catawba, reimburses Duke for certain expenses associated with nuclear insurance premiums paid by Duke.

The Price-Anderson Act provides that nuclear reactor owners insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $9.5 billion. The maximum required private primary insurance of $200 million has been purchased along with a like amount for the benefit of the co-owners of Catawba to cover certain worker tort claims. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $200 million, a licensee of a nuclear power plant could be assessed a deferred premium of up to $88 million (NCEMC's share is $24.8 million) for certain licensed reactors. It would be payable at a rate not to exceed $10 million (NCEMC's share is $2.8 million) per year per licensed reactor for each incident. If retrospective premiums were to be assessed, the Company will be responsible for its share of any retrospective premiums or other costs incurred by Duke in the event an accident occurs where liabilities exceed insurance coverage.

Duke is a member of Nuclear Electric Insurance Limited (NEIL), which provides $500 million in primary property damage coverage for each of Duke's nuclear facilities. If NEIL's losses ever exceed its reserves, Duke will be liable, on a pro rata basis, for additional assessments of up to $18 million (NCEMC's share is

$5.1 million). This amount represents five times Duke's annual premium to NEIL. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba Duke also purchases insurance through NEIL's excess property, decontamination and decommissioning liability insurance program. NEIL provides excess insurance coverage of $2.25 billion for Catawba. If losses ever exceed the accumulated funds available to NEIL for the excess property, decontamination and decommissioning liability program, Duke will be liable, on a pro rata basis, for additional assessments of up to $18 million (NCEMC's share is $5.1 million). The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba.

Duke participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Catawba is insured for up to approximately $4 million per week, after a 12-week deductible period, with declining amounts per unit where more than one unit is involved in an accidental outage. Coverages continue at 100% for 52 weeks and 80% for the next 110 weeks. If NEIL's losses for this program ever exceed its reserves, Duke will be liable, on a pro rata basis, for additional assessments of up to $15 million (NCEMC's share is $4.2 million).

This amount represents five times the annual premium to NEIL for insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. The joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premiums assessments resulting from the NEIL policies applicable to the joint ownership agreements.

11. RELATED-PARTY TRANSACTIONS In accordance with a management agreement, the Company provides staff services to the North Carolina Association of Electric Cooperatives, Inc. (NCAEC), the Tarheel Electric Membership Association, Inc.

and subsidiary (TEMA), TSE Services Inc. and the CEC Self Insurance Fund, Inc., (CECSIF) which are all related parties. The management agreement provides that charges for these services include a component for general corporate expenses and an assessment for office space and computer equipment.

The Company also charges the ElecTel Cooperative Credit Union, a related party, a fee for office space and use of the Company's copy machines. Charges to NCAEC were $3,991,000 in 2001, $4,275,000 in 2000 and $1,758,000 in 1999. Charges to TEMA were $2,236,000 in 2001, $2,240,000 in 2000 and

$1,928,000 in 1999. Charges to the CECSIF were $40,000 in 2001, 2000 and 1999. Charges to TSE Services Inc. were $4,821,000 in 2001, $5,427,000 in 2000 and $2,222,000 in 1999.

The Company purchases various services from TSE Services Inc. Expenses related to these services totaled $1,209,000 in 2001, $2,566,000 in 2000 and $628,000 in 1999. The Company also purchases various services from NCAEC. Expenses related to these services totaled $2,134,000 in 2001 and

$2,638,000 in 2000.

The Company has accounts receivable net of accounts payable with related parties at December 31, 2001 and 2000, as follows (in thousands). These amounts do not bear interest.

2001 2000 NCAEC $ 312 $ 313 TEMA 1,062 778 TSE Services Inc. 10,117 5,024 CECSIF 3 3

$11,494 $6,118 The Company has designated $27,000,000 for loans to members for economic development and construction of customer-owned generation. At December 31, 2001 and 2000, outstanding loans totaling

$13,305,000 and $14,598,000, respectively, have been included in accounts receivable and noncurrent receivables in the accompanying balance sheets. Economic development loans (totaling $12,972,000 and

$13,950,000 at December 31, 2001 and 2000, respectively) do not bear interest and have repayment terms of up to seven years with an initial payment deferral of up to four years available under certain circumstances. Customer-owned generation loans (totaling $333,000 and $648,000 at December 31, 2001 and 2000, respectively) accrue interest at fixed and variable rates ranging from 1.9% to 8.3%. The repayment terms for these loans range from 3 to 7 years. The contractual maturities of the economic development loans and customer-owned generation loans described above are as follows:

Years Amount 2002 $ 1,743 2003 1,910 2004 1,934 2005 1,182 Thereafter 6,536

$13,305

PIEDMONT MUNICIPAL POWER AGENCY Financial Statements and Schedules December 31, 2001 and 2000 (With Independent Auditors' Report Thereon)

PIEDMONT MUNICIIPAL POWER AGENCY Table of Contents Page Independent Auditors' Report Balance Sheets 2 Statements of Revenues and Expenses and Changes in Retained Earnings 3 Statements of Cash Flows 4 Notes to Financial Statements 5-23 Supplementary Information:

I Schedule of Revenue and Expenses Actual and Budget Per the Bond Resolution and Other Agreements 25 2 Schedule of Revenue and Expenses Per the Bond Resolution and Other Agreements 26-27

Suite 900 55 Beattie Place Greenville, SC 29601-2106 Independent Auditors' Report The Board of Directors Piedmont Municipal Power Agency:

(the "Agency")

We have audited the accompanying balance sheets of Piedmont Municipal Power Agency expenses and changes in as of December 31, 2001 and 2000, and the related statements of revenues and are the responsibility retained earnings and cash flows for the years then ended. These financial statements is to express an opinion on these financial statements of the Agency's management. Our responsibility based on our audits.

in the United States of We conducted our audits in accordance with auditing standards generally accepted obtain reasonable assurance about America. Those standards require that we plan and perform the audit to examining, on a test whether the financial statements are free of material misstatement. An audit includes the financial statements. An audit also includes basis, evidence supporting the amounts and disclosures in made by management, as well as assessing the accounting principles used and significant estimates reasonable that our audits provide a evaluating the overall financial statement presentation. We believe basis for our opinion.

in all material respects, the In our opinion, the financial statements referred to above present fairly, 2000, and the results of its operations and financial position of the Agency, as of December 31, 2001 and principles generally accepted in the its cash flows for the years then ended in conformity with accounting United States of America.

method of accounting for As discussed in note 2 to the financial statements, the Agency changed its derivative instruments in 2001.

statements taken as a Our audits were made for the purpose of forming an opinion on the basic financial presented for purposes of whole. The supplementary information included in Schedules I and 2 is Such information has been additional analysis and is not a required part of the basic financial statements.

of the basic financial statements and, in our subjected to the auditing procedures applied in the audits basic financial statements taken as a whole.

opinion, is fairly stated in all material respects in relation to the K~t~G, LCP March 1, 2002 a member of KPMG Internatolnal. a Snass associatim

PIEDMONT MUNICIPAL POWER AGENCY Balance Sheets December 31, 2001 and 2000 (Dollars in thousands)

Assets 2001 2000 Utility plant (note 5):

Electric plant in service $ 554,828 554,492 Nuclear fuel 32,076 37,658 Construction work-in-progress 2,516 1,407 589,420 593,557 Less accumulated depreciation and amortization (284,854) (269,565)

Net utility plant 304,566 323,992 Restricted funds (note 6) 198,270 190,380 Revenue fund assets (note 7)"

Cash 7,125 7,637 Marketable debt securities 236,190 235,722 Accrued interest receivable 3,610 4,050 Due from restricted funds 1,292 1,199 Participant accounts receivable 8,992 10,609 Other accounts receivable 4,792 3,601 Materials and supplies 5,742 5,726 Derivative financial instruments 4,832 Total revenue fund assets 272,575 268,544 Other assets:

Unamortized debt issuance costs 18,666 19,908 Net costs recoverable from future Participant billings (note 8) 418,849 397,481 Costs on advance refundings of debt 162,344 173,400 Other 2,521 2,693 Total other assets 602,380 593,482

$ 1,377,791 1,376,398 Liabilities and Retained Earnings Long-term debt (notes 9 and 10)

Bonds 1,286,404 1,302,429 Unamortized discounts (47,882) (50,628)

Unamortized premiums 1,066 1,230 1,239,588 1,253,031 Restricted fund liabilities 49,446 Accrued interest payable 50,901 Reserve for decommissioning (note 11) 39,329 35,419 90,230 84,865 Revenue fund liabilities - accounts payable (note 7) 12,455 10,299 Retained earnings 35,518 28,203 Commitments and contingencies (notes 14 and 15)

$ 1,377,791 1,376,398 See accompanying notes to financial statements.

PIEDMONT MUNICIPAL POWER AGENCY Statements of Revenues and Expenses and Changes in Retained Earnings Years ended December 31, 2001 and 2000 (Dollars in thousands) 2001 2000 Operating revenues:

$ 117,548 118,082 Sales of electricity to Participants Sales of electricity to other utilities 16,208 14,475 Other 1,207 1,204 Total operating revenues 134,963 133,761 Operating expenses:

22,337 22,311 Operation and maintenance 6,958 6,692 Nuclear fuel amortization Purchased power (note 4) 24,769 26,875 4,709 4,466 Transmission 1,409 1,639 Distribution 12,426 11,956 Administrative and general 18,656 18,792 Depreciation 3,910 4,392 Decommissioning Payments in lieu of property taxes 4,385 4,550 99,559 101,673 Total operating expenses 35,404 32,088 Net operating income Other income (expenses):

26,772 27,848 Interest income Net increase in fair value of investments and derivative 4,853 12,196 instruments Interest expense (69,587) (73,735)

(13,402) (13,566)

Amortization expense (5,405)

Other expense, net (2,485)

(53,849) (52,662)

Total other expenses, net (18,445) (20,574)

Revenues under expenses before deferred items Net expenses recoverable from future Participant 21,368 23,409 billings (notes 2 and 8)

Revenues over expenses before cumulative effect 2,835 2,923 of a change in accounting principle 4,392 Cumulative effect of a change in accounting principle (note 2) 7,315 2,835 Revenues over expenses 28,203 25,368 Retained earnings at beginning of year

$ 35,518 28,203 Retained earnings at end of year See accompanying notes to financial statements.

3

PIEDMONT MUNICIPAL POWER AGENCY Statements of Cash Flows Years ended December 31, 2001 and 2000 (Dollars in thousands) 2001 2000 Cash flows from operating activities:

$ 7,315 2,835 Revenues over expenses Adjustments to reconcile revenues over expenses to net cash provided by operating activities:

Depreciation and amortization 39,016 39,050 Cumulative effect of a change in accounting principle (4,392)

Net increase in fair value of investments and derivative instruments (4,853) (12,196)

Net expenses recoverable from future (21,368) (23,409)

Participant billings Reserve for decommissioning 3,910 4,392 Decrease (increase) in:

1,617 (1,741)

Participant accounts receivable (1,191) (2,426)

Other accounts receivable 12 (869)

Accrued interest receivable (16) (202)

Materials and supplies Increase (decrease) in:

2,156 3,264 Accounts payable 1,455 1,832 Accrued interest payable 23,661 10,530 Net cash provided by operating activities Cash flows from investing activities:

Purchase of investment securities (1,647,834) (1,712,993) 1,663,475 1,733,205 Proceeds from sales and maturities of investment securities (1,462) (807)

Expenditures for electric plant in service (4,726) (10,033)

Expenditures for nuclear fuel 9,453 9,372 Net cash provided by investing activities Cash flows from financing activities: (21,200)

Payment of bond principal (16,025) 1,792 1,833 Defeasance losses Other (142)

(14,375) (19,367)

Net cash used in financing activities 18,739 535 Net increase in cash 7,637 7,102

• Cash at beginning of year (note 7)

$ 26,376 7,637 Cash at end of year (notes 6 and 7)

Supplemental disclosure of cash flow information:

$ 65,641 69,392 "Cashpaid during the year for interest

$ 25,903 21,397 Cash received during the year for investment income See accompanying notes to financial statements.

4

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(1) Description of the Entity, Industry Restructuring Developments, and Related Uncertainties Description of the Entity Piedmont Municipal Power Agency (Agency) was incorporated in 1979 under the South Carolina Joint Municipal Electric Power and Energy Act. The Act, adopted April 1978, enabled the formation, by South Carolina municipalities and municipal commissions of public works, of a joint agency to plan, finance, develop, own and operate electric generation and transmission facilities. Ten municipal utility systems (Participants) comprise the Agency's membership. The Participants, located in northwestern South Carolina, are the cities of Abbeville, Clinton, Easley, Gaffney, Greer, Laurens, Newberry, Rock Hill, Union and Westminster.

The Agency and Duke Power Company (Duke) are parties to agreements giving the Agency a 25%

undivided ownership interest in Catawba Nuclear Station Unit 2 (Project). Duke is the operating owner of the Project. The Agency's Project power output entitlements (approximately 286 MW) come from Catawba Nuclear Station Units I and 2; subject to the terms of the "Catawba Reliability Exchange" under which the Agency pays 12.5% of the costs and receives 12.5% of the power output associated with each of these 1,145 MW units. Additionally, the terms of the "McGuire Reliability Exchange" allow transfers of energy between the Agency's resulting entitlements from the Catawba Units and Duke's two nuclear units at McGuire Nuclear Station. The operating licenses for Catawba Unit I and Unit 2 expire on December 6, 2024 and February 24, 2026, respectively.

Industry RestructuringDevelopments andRelated Uncertainties During the 113th General Assembly of the South Carolina legislature (which included calendar years 1999 and 2000) both the South Carolina Senate and House of Representatives considered deregulation legislation. House Bill 3902 was introduced during the 1999 session and Senate Bill 1168 was introduced early in the 2000 session. Neither bill was passed.

As a result of deregulation in California and the problems that have occurred, the Agency does not expect to see any deregulation activity during the current session of the South Carolina legislature (which includes calendar years 2002 and 2003) unless an initiative is passed at the federal level. The Agency will continue to monitor deregulation activity both on the national and state level.

The Agency has developed a strategic plan to help guide it through the potential industry changes that includes periodic reviews of the recoverability of regulatory assets and the impact of such recovery on the Agency's rates. The Agency's management is participating in the deregulation debate, both on the national and state level.

In the event that the electric utility industry is restructured, the Agency and the Participants can expect to have as their major competition the investor owned utilities and rural electric cooperatives presently operating in South Carolina and independent power producers, power marketers and others that may offer retail and wholesale services in South Carolina after restructuring The Participants' present retail electric rates are higher, on average, than the present retail electric rates of the area's investor owned utilities.

5 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

The Agency's present charges to the Participants, together with planned withdrawals from the Rate Stabilization Account, are sufficient to recover all of the Agency's current costs of supplying the Participant's bulk power supply. Currently each Participant is able, and under its Power Sales Agreements is required, to set its rates at levels necessary to pay all the costs of its electric utility system, including the Agency's charges for supplying power to the Participants. However, studies by the Agency show that, in a deregulated electric utility industry, anticipated market-based retail rates would be lower than those that the Participants would need to charge in order to pay the Agency's charges and to cover all of the other costs and expenses of their electric utility systems, giving rise to stranded investments of the Agency and the Participants and the need for stranded investment recovery by the Agency and the Participants.

For the Agency and the Participants to be competitive in a deregulated retail electric utility industry, the Agency and the Participants must recover the Agency's substantial stranded investments in the Project.

The Agency expects that the methods by which it and the Participants may recover some or all of these stranded investments would come from the legislative initiatives. As a result of the foregoing described uncertainties, including the inability to predict the outcome of the legislative process, no assurance can be given that the Agency and the Participants would be able to recover, in whole or in part, these stranded investments in the event of deregulation of the retail electric utility industry.

(2) Summary of Significant Accounting Policies Basis of Accounting The Agency's accounting records are maintained on an accrual basis in conformity with accounting principles generally accepted in the United States of America and substantially in conformity with the Federal Energy Regulatory Commission's Uniform System of Accounts.

The Agency follows the accounting practices set forth in Statement of Financial Accounting Standards No. 71 (SFAS No. 71), Accounting for the Effects of Certain Types of Regulation, as amended. This standard requires entities to capitalize or defer certain costs or revenues based on the Agency's ongoing assessment that it is probable that such items will be recovered through future revenues based on the rate making authority of the Agency's Board of Directors.

The ability of the Agency to continue to meet the criteria to account for its operations pursuant to SFAS No. 71 depends primarily upon the pace of the State of South Carolina in allowing deregulation of the generation portion of the utility industry. SFAS No. 71 requires entities to capitalize or defer certain costs or revenues based on the Agency's ongoing assessment that it is probable that such items will be recovered through future revenues. The criteria require consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized cost.

If the Agency no longer applied SFAS No. 71 due to competition, regulatory changes or other reasons, the Agency would make certain adjustments. These adjustments could include the write-off of all or a portion of its regulatory assets and liabilities. These adjustments also could lead to the evaluation of utility plant.

contracts and commitments and the recognition, if necessary, of any losses to reflect market conditions.

6 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

The Agency's General Bond Resolution requires that its rate structure be designed to produce revenues sufficient to pay operating, debt service and other specified costs. The Agency's Board, which is comprised of representatives of the Participants, is responsible for reviewing and approving the rate structure. The application of a given rate structure to a given period's electricity sales may produce revenues not intended to pay that period's costs, and conversely, that period's costs may not be intended to be recovered in period revenues. The affected revenues and/or costs are, in such cases, deferred for future recognition. The ultimate recognition of deferred items is correlated with specific future events; primarily payment of debt principal.

UnamortizedDebt Issuance Costs Unamortized debt issuance costs at December 31, 2001 and 2000 of $18,666 and $19,908, respectively, (net of accumulated amortization of $21,556 and $20,171, respectively) are being amortized over the term of the related debt.

Costs on Advance Refundings of Debt Costs on advance refundings of debt at December 31, 2001 and 2000 of $162,344 and $173,400, respectively, (net of accumulated amortization of $137,409 and $126,352, respectively) have been deferred in accordance with SFAS No. 71 and are being amortized over the term of the debt issued on refunding.

Discounts on Bonds Payable The discounts on bonds payable at December 31, 2001 and 2000 of $47,882 and $50,628, respectively, (net of accumulated amortization of $42,094 and $39,348, respectively) are being amortized on the bonds outstanding method which approximates the effective interest method.

Premiums on Bonds Payable The premiums on bonds payable at December 31, 2001 and 2000 of $1,066 and $1,230, respectively, (net of accumulated amortization of $1,288 and $1,124, respectively) are being amortized on the bonds outstanding method which approximates the effective interest method.

Income Taxes The Agency is recognized as a public utility for federal income tax purposes. As such, gross income of the Agency is excluded from federal income taxes under Internal Revenue Code section 115.

Cash Flows For purposes of the statements of cash flows, the Agency considers interest-bearing deposits with banks and Duke to be cash.

7 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

MarketableDebt Securities As authorized by the General Bond Resolution, investment securities at December 31, 2001 consist only of direct obligations of the United States government and obligations of United States government agencies.

These investments are uninsured and unregistered and are held by the Agency's trustees in the Agency's name.

Marketable debt securities are recorded at fair value. Unrealized holding gains and losses on marketable debt securities are included in income. Interest income is recognized when earned.

Utility Plant Electric plant in service, including unclassified assets, is stated at cost and is depreciated on a straight-line basis at rates calculated to depreciate the composite assets over their respective estimated useful lives.

Depreciation begins when assets are placed into service. The Agency's annual provision for depreciation expressed as a percentage of the average balance of depreciable utility plant was 3.3% for 2001 and 2000.

Materialsand Supplies Materials and supplies inventories are stated at lower of cost or market using the average cost method.

Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Actual results could differ from those estimates.

FinancialReporting Under Governmental Accounting Standards Board (GASB) Statement No. 20, Accounting and Financial Reportingfor ProprietaryFunds and Other Governmental Entities that Use ProprietaryFundAccounting, the Agency has adopted the option to apply Financial Accounting Standards Board (FASB) statements and interpretations that do not conflict with or contradict GASB pronouncements.

Revenue Recognition The Agency recognizes revenue on sales when the electricity is provided to and used by the customers.

8 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

Recently Issued Pronouncements In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires the Agency to record the fair alue of an asset requirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Agency is required to adopt SFAS No. 143 on January 1, 2003. The Agency will record a corresponding asset which will be depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. Any such adjustments for changes in the estimated future cash flows will also be capitalized and amortized over the remaining life of the asset.

Derivative FinancialInstruments In June 1998 the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities" (SFAS No. 133). In June 2000 the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activity, an Amendment of SFAS 133" (SFAS No.

138). SFAS No. 133 and SFAS No. 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values. SFAS No. 133 and SFAS No. 138 are effective for of all fiscal years beginning after June 30, 2000; the Agency adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001.

In accordance with the transition provisions of SFAS No. 133, the Agency recorded a cumulative-effect adjustment of $4,392 in the statement of revenues and expenses to recognize at fair value all derivatives outstanding at that date.

All derivatives are recognized on the balance sheet at their fair value. The Agency has not designated any of its derivatives as hedges. Changes in the fair value of derivative instruments are reported in current period revenues and expenses.

9 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

For the year ended December 31, 2000, prior to the adoption of SFAS No. 133, the Agency entered into interest rate swap agreements and forward delivery contracts. For interest rate swaps, the differential to be paid or received is accrued and recognized in other income (expense) and may change as market interest rates change. For forward delivery contracts, the interest to be received is accrued and recognized in interest income. If a swap or forward delivery contract is terminated prior to its maturity, the gain or loss is recognized immediately.

(3) Power Sales Agreements CatawbaProjectPower Sales Agreements The Agency and each Participant are parties to Catawba Project Power Sales Agreements (Sales Agreements). These Sales Agreements oblige the Agency to provide each Participant a share of Project power output and, in turn, each Participant must pay its share of Project costs. Participants make their payments on a "take-or-pay" basis whether or not the Project is operable or operating. Such payments are not subject to reduction or offset and are not conditioned upon performance by the Agency or any given Participant. The Sales Agreements are in effect until the earlier of August 1, 2035, or the completion of payments on the bonds and satisfaction of obligations under the Project agreements.

The Participants' Shares of the Agency's Catawba Project Output are as follows:

City of Abbeville 2.68%

City of Clinton 7.84%

City of Easley 13.24%

City of Gaffney 10.05%

City of Greer 9.34%

City of Laurens 6.49%

City of Newberry 10.47%

City of Rock Hill 28.04%

City of Union 10.01%

City of Westminster 1.84%

100.00%

Supplemental Power Sales Agreements The Agency and each Participant are also parties to Supplemental Power Sales Agreements (Supplemental Agreements) under which each Participant has agreed to pay, in exchange for supplemental bulk power supply, its share of supplemental bulk power supply costs. A Participant may terminate its Supplemental Agreement with ten years advance notice.

lO (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(4) Project Agreements Project Agreements between the Agency and Duke consist of the Catawba Nuclear Station Purchase, Construction and Ownership Agreement (the Purchase Agreement), the Catawba Nuclear Station Operating and Fuel Agreement (the Operating Agreement), and the Catawba Nuclear Station Interconnection Agreement (the Interconnection Agreement).

PurchaseAgreement This agreement between the Agency and Duke provides for the purchase of the Catawba Project by the Agency. It also details Duke's responsibilities, as engineer-contractor, for construction, initial fueling, and placing the Catawba Nuclear Station into commercial operation.

OperatingAgreement This agreement, between the Agency and Duke, provides for Duke, as operator for the Agency, to be responsible for the operation, maintenance, and fueling of Catawba and for making of renewals, replacements and capital additions. In addition, the Operating Agreement provides for decommissioning of Catawba at the end of its useful life pursuant to the terms of a decommissioning agreement, separate from the Operating Agreement.

InterconnectionAgreement This agreement, between the Agency and Duke, provides for interconnection of the Agency's ownership share of Catawba Unit 1 with the Duke system. As part of the Interconnection Agreement, the Agency is allowed to exchange capacity and output of four nuclear units. The agreement also provides for sale by the Agency of surplus energy to Duke and third parties. It also makes provision for the purchase of supplemental capacity and energy, transmission services and reserve purchases.

In December 1997, the Agency's Board of Directors voted to issue notice, pursuant to the contract, to cancel the lnterconnection Agreement with Duke. The cancellation is effective January 1, 2006.

I1I (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(5) Utility Plant Original costs of major classes of the Agency's electric plant in service at December 31, 2001 and 2000 are as follows:

2001 2000 Land $ 336 336 Structures and improvements 157,032 157,032 Reactor plant equipment 248,023 248,023 Turbo generator units 69,270 69,270 Accessory electric equipment 50,623 50,623 Miscellaneous plant equipment 16,757 16,757 Station equipment 5,477 5,477 Transmission equipment 1,242 1,240 Other 1,897 1,883 Unclassified 4,171 3,851

$ 554,828 554,492 Unclassified assets are in service but not yet classified to specific plant accounts.

Nuclear fuel at December 31, 2001 and 2000 of $32,076 and $37,658, respectively, represents costs associated with acquiring and processing reload fuel assemblies as well as the cost of nuclear fuel in the reactor. Nuclear fuel is amortized based on bum rates using a unit of production basis. The Agency regularly writes off fully amortized nuclear fuel costs when fuel batches are replaced during core refueling operations. Fully amortized fuel costs of $10,308 and $9,534 were written off during 2001 and 2000, respectively.

A summary of accumulated depreciation and amortization at December 31, 2001 and 2000 are as follows:

2001 2000 Accumulated depreciation of electric plant in service $ 266,487 247,847 Accumulated amortization of nuclear fuel 18,367 21,718

$ 284,854 269,565 12 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(6) Restricted Funds The General Bond Resolution, Project agreements, and Agency policies restrict the use of bond proceeds, Agency revenues, and Agency funds on hand. Certain restrictions define the order in which available funds may be used to pay costs; other restrictions require minimum balances or accumulation of balances for specific purposes. At December 31, 2001 and 2000, the Agency was in compliance with all such restrictions and held the following restricted assets:

2001 2000 Fair Amortized Fair Amortized value cost value cost Debt service - bond principal $ 19,370 19,370 16,021 16,025 Debt service - bond fixed rate interest 29,550 29,550 30,513 30,518 Debt service - bond retirement 1 1 1 1 Debt service reserve 85,328 83,850 84,601 83,850 Reserve and contingency 8,616 8,385 8,548 8,385 Decommissioning 40,142 39,329 35,536 35,419 Special reserve 15,263 15,000 15,160 15,000

$ 198,270 195,485 190,380 189,198 Funds are comprised of:

Marketable debt securities 196,634 193,849 189,079 187,897 Accrued interest receivable 2,928 2,928 2,500 2,500 Due to revenue fund (1,292) (1,292) (1,199) (1,199)

$ 198,270 195,485 190,380 189,198 Restricted funds include $19,251 and $0 of cash at December 31, 2001 and 2000, respectively. The cash at December 31, 2001 is uninsured and uncollateralized.

(7) Revenue Fund Assets and Liabilities Revenue fund assets and liabilities are used in the Agency's day-to-day operations. The assets are allocated for the following purposes:

2001 2000 Fair Amortized Fair Amortized value cost value cost Working capital $ 76,283 74,895 65,953 65,402 Derivative financial instruments 4,832 Fuel acquisition 30,503 30,503 28,271 28,271 Rate stabilization 160,957 155,781 174,320 171,118

$ 272,575 261,179 268,544 264.791 13 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

The revenue fund includes $7,125 and $7,367 of uninsured and uncollateralized cash at December 31, 2001 and 2000, respectively. Liabilities of $12,455 and $10,299 at December 31, 2001 and 2000, respectively, will be paid out of working capital assets.

(8) Net Expenses Recoverable from Future Participant Billings As described in notes 1 and 2, rates charged to Participants are structured to systematically provide for debt requirements and operating costs of the Agency. The expenses and revenues excluded from rates are deferred to such periods as they are intended to be included in rates.

Net expenses recoverable from future Participant billings:

2001 2000 Change (Cumulative Totals)

Items to be recovered in future Participant billings:

Interest expense $ 331,796 329,373 2,423 Depreciation expense 282,818 265,340 17,478 Amortization of redemption and defeasance 138,463 127,264 11,199 losses Amortization of bond discounts and debt 63,526 59,559 3,967 issuance costs Nuclear fuel expenses 873 873 Letter of credit fees 5,649 5,649 Other 2,392 2,392 825,517 790,450 35,067 Items reducing future Participant billings:

Investment income $ (76,528) (76,528)

Increase in fair value of investments and derivative instruments (14,182) (4,937) (9,245)

Rate stabilization (revenue received to reduce future billings to Participants) (513,888) (503,107) (10,781)

(36,751) (35,425) (1,326)

Reserve and contingency deposits

$ (641,349) (619,997) (21,352)

Revenues (expenses) recognized:

Interest, depreciation, amortization expense included in Participant billings for debt principal payments $ (129,043) (109,674) (19,369) 358,106 331,989 26,117 Rate stabilization draws applied to expenses Reserve and contingency revenue applied to 5,618 4,713 905 expenses Net costs recoverable from future

$ 418,849 397,481 21,368 Participant billings 14 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

The following expenses will be recognized in future periods when rates charged to Participants produce revenues sufficient to retire the debt that funded those costs:

" Interest expense on the Agency's bonds and variable rate demand obligations along with associated letter-of-credit, banking and re-marketing fees (except interest and fees related to Capital Appreciation Bonds) paid from bond proceeds during a defined "Construction Period," (net of income earned on the temporary investment of those bond proceeds);

"* Interest expense on Capital Appreciation Bonds accrued but not paid until maturity;

"* Amortization of debt issuance expenses, bond discounts, defeasance losses, redemption losses, and organization costs paid from or included in bond proceeds;

"* Depreciation on utility plant constructed with bond proceeds and amortization of nuclear fuel acquired with bond proceeds; and

"* Certain other project costs paid from bond proceeds.

The Agency has also deferred Participant revenues that, during the Construction Period, were established at levels to cover Project costs not paid from bond proceeds, as well as scheduled deposits to a Rate Stabilization account. The revenue associated with those scheduled deposits and the interest income thereon will be recognized when those funds are drawn upon to pay Project costs. Also, certain settlement revenues and excess revenues in certain funds have been transferred to the Rate Stabilization account and have been deferred for recognition until the time the funds are applied to the payment of Project costs.

Revenues or costs associated with increases or decreases in the fair value of investments have been deferred until such time the securities have matured or are sold.

Additionally, the Agency's General Bond Resolution requires Participant revenues to be established at levels sufficient to provide specified deposits into a Reserve and Contingency fund. Monies in that fund are used for the construction or acquisition of utility plant. The recognition of such revenues is deferred until such time as the depreciation is recorded on the assets constructed or acquired with those monies.

15 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(9) Long-term Debt Long-term debt at December 31, 2001 and 2000 consists of the following:

2001 2000 1986 Refunding Series Electric Revenue Bonds, payable in 2025 with interest at 5% $ 33,620 33,620 1986A Refunding Series Electric Revenue Bonds, payable in 2023 and 2024 with interest at 5.75% 103,815 103,815 1988 Capital Appreciation Electric Revenue Bonds, payable annually and from 2010 to 2013 with interest at 7.75% 7,745 7,745 1988A Capital Appreciation Electric Revenue Bonds, payable annually from 2004 to 2015 with interest ranging from 7.3% to 7.65% 4,284 4,284 1991 Refunding Series Electric Revenue Bonds, payable annually from 2005 to 2023 with interest ranging from 4% to 6.85% 213,550 213,550 1991A Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2007 and from 2013 to 2018 with interest ranging from 5% to 6.5% 145,150 146,375 1992 Refunding Series Electric Revenue Bonds, payable annually from 2010 to 2014 with interest at 6.3% 19,940 19,940 1993 Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2025 with interest ranging from 4.9% to 5.6% 77,380 79,795 1996A Refunding Series Electric Revenue Bonds, payable annually from 2013 to 2021 with interest ranging from 6.55% to 6.6% 69,140 69,140 1996B Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2013 with interest ranging from 4.8% to 6.0% 121,790 133,075 16 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands) 2001 2000 1996C Refunding Series Electric Revenue Bonds, payable annually in 2021 to 2022 with variable interest rates (1.55% and 4.75% at December 31, 2001 and 2000, respectively) $ 50,000 50,000 1996D Refunding Series Electric Revenue Bonds, payable annually from 2022 to 2025 with variable interest rates (1.6% and 4.8% at December 31, 2001 and 2000, respectively) 50,000 50,000 1997A Refunding Series Electric Revenue Bonds, payable in 2024 with variable interest rates (1.6% and 5.0% at December 31, 2001 and 2000, respectively) 31,700 31,700 1997B Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2003 and 2016 to 2019 with variable interest rates (1.55% and 4.75% at December 31, 2001 and 2000, respectively) 64,485 65,200 1997C Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2003 and 2016 to 2019 with variable interest rates (1.6% and 5.0% at December 31, 2001 and 2000, respectively) 34,915 35,300 1998A Refunding Series Electric Revenue Bonds, payable annually from 2006 to 2025 with interest ranging from 4.4% to 5.5% 161,380 161,380 1999A Refunding Series Electric Revenue Bonds, payable annually from 2014 to 2016 and 2020 to 2021 with interest at 5.25% 97,510 97,510 Total long-term debt 1,286,404 1,302,429 Less unamortized discount (47,882) (50,628)

Plus unamortized premium 1,066 1,230

$ 1,239,588 1,253,031 The bonds are special obligations of the Agency and are secured by future revenue and pledged monies and securities as provided by the bond resolution 17 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

The bonds generally provide for early redemption beginning ten years after issuance at prices ranging from 100% to 103% of the bond principal amounts.

The Agency has advance refunded certain bond issues as described in note 10.

The following is a summary of total debt service deposit requirements for bonds outstanding at December 31, 2001:

Year Principal Interest Total 2002 $ 20,470 67,905 88,375 2003 20,880 67,804 88,684 2004 23,015 66,601 89,616 2005 24,728 65,314 90,042 2006 31,772 63,854 95,626 2007 33,993 61,975 95,968 2008 43,056 60,139 103,195 2009 37,391 65,641 103,032 2010 37,309 65,634 102,943 2011 39,049 63,773 102,822 2012 38,759 61,839 100,598 2013 52,972 49,509 102,481 2014 57,630 46,338 103,968 2015 61,105 41,780 102,885 2016 64,270 38,546 102,816 2017 67,360 35,303 102,663 2018 68,995 31,916 100,911 2019 80,795 28,132 108,927 2020 85,665 23,396 109,061 2021 90,480 18,889 109,369 2022 92,975 14,619 107,594 2023 100,590 9,902 110,492 2024 93,775 4,681 98,456

$ 1,267,034 1,053,490 2,320,524 The debt service deposit requirements for principal differ from total long-term debt outstanding at December 31, 2001, because the principal payment of $19,370 which is due January 1, 2002, was deposited during 2001. All principal payments are due on January 1 of the year subsequent to the deposit requirement.

18 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(10) In-Substance Debt Defeasance In prior years, the Agency defeased in-substance certain Electric Revenue Bonds by placing the proceeds of new bonds in an irrevocable trust fund to provide for future debt service payments on the old debt.

Accordingly, the trust account asset and the liability for the defeased bonds are not included in the accompanying financial statements. On December 31, 2001, $302,855 of the bonds are considered defeased in-substance.

(11) Reserve for Decommissioning The Agency is in compliance with Nuclear Regulatory Commission requirements for funding future decommissioning costs. Since 1985, the Agency has been making regular deposits to segregated decommissioning accounts. The Agency accrues its decommissioning liability over the life of the Project based on its required funding and interest earnings on the decommissioning funds. Deposits pertaining to contaminated portions of the Project are held by a Trustee. The Agency has custody of funds set aside to decommission non-contaminated portions of the Project. The Agency's share of the total decommissioning costs, based on decommissioning studies completed in 1999, is estimated to be $109,500 (in 1999 dollars). This estimate presumes the Catawba Nuclear Station will be decommissioned as soon as possible following the expiration of its operating licenses in 2024 and 2026.

(12) Employee Benefit Plans The Agency maintains a defined contribution money purchase plan in compliance with Section 401(a) of the Internal Revenue Code. On behalf of all full-time employees, the Agency contributes 10% of base salary into the money purchase plan. Agency contributions totaled $139 and $100 in 2001 and 2000, respectively. Employee contributions may also be made to the Plan, providing combined employer and employee annual contributions do not exceed 25% of eligible employee compensation, or $30, whichever is less.

The Agency also maintains a deferred compensation plan under Section 457 of the Internal Revenue Code.

From time to time, on behalf of selected employees, the Agency contributes to the deferred compensation plan. Employee contributions may also be made to the deferred compensation plan providing combined employer and employee annual contributions do not exceed certain limitations.

Assets of the money purchase plan and deferred compensation plan are held by Prudential Financial, administrator and trustee, for the Agency for the exclusive benefit of the employees.

19 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(13) Disclosures Regarding Fair Value of Financial Instruments Statement of Financial Accounting Standards No. 107 (SIAS No. 107), DisclosureAbout Fair Value of FinancialInstruments, requires disclosure of fair value information about financial instruments whether or not recognized in the balance sheet, for which it is practicable to estimate fair value. Fair value estimates are made as of a specific point in time based on the characteristics of the financial instruments and the relevant market information. Where available, quoted market prices are used. In other cases, fair values are based on estimates using present value or other valuation techniques. These techniques involve uncertainties and are significantly affected by the assumptions used and the judgments made regarding risk characteristics of various financial instruments, discount rates, prepayments, estimates of future cash flows, future expected loss experience and other factors. Changes in assumptions could significantly affect these estimates. Derived fair value estimates cannot be substantiated by comparison to independent markets and, in many cases, may or may not be realized in an immediate sale of the instrument.

Under SFAS No. 107, fair value estimates are based on existing financial instruments without attempting to estimate the value of anticipated future business and the value of the assets and liabilities that are not financial instruments. Accordingly, the aggregate fair value amounts presented do not represent the underlying value of the Agency.

The following describes the methods and assumptions used by the Agency in determining carrying value and estimated fair value of financial instruments:

(a) Cash Carrying value equals estimated fair value.

(b) MarketableDebt Securities Estimated fair value, which is the carrying value, of all marketable debt securities is derived from quoted market prices.

(c) Derivative FinancialInstruments Estimated fair value of derivative financial instruments is derived from current market pricing models.

(d) ParticipantAccounts Receivable, and Other Accounts Receivable Carrying amount approximates fair value due to the short-term nature of these instruments.

(e) Long-term Debt Carrying value of long-term debt coupon securities includes par, less unaccreted discounts, plus unamortized premiums, plus accrued interest payable. Carrying value also includes Capital Appreciation Term Bonds valued at original price plus accreted discount.

Estimated fair value of all long-term debt securities is derived from quoted market prices and includes accrued interest.

20 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

The estimated fair values of the Agency's long-term debt with carrying values different from their estimated fair values at December 31, 2001 and 2000 are as follows:

2001 2000 Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value Electric Revenue Refunding Bonds $ 27,536 30,729 27,235 29,628 1986 1986A Electric Revenue Refunding Bonds 95,573 103,935 95,051 100,952 1988 Electric Revenue Refunding Bonds 22,070 42,342 20,454 39,465 1988A Electric Revenue Refunding Bonds 11,310 20,724 10,502 19,201 1991 Electric Revenue Refunding Bonds 205,403 227,619 204,600 230,539 1991A Electric Revenue Refunding Bonds 145,510 147,695 146,409 161,329 1992 Electric Revenue Refunding Bonds 20,440 21,770 20,425 21,721 1993 Electric Revenue Refunding Bonds 78,143 80,378 80,546 85,196 1996A Electric Revenue Refunding Bonds 71,193 71,853 71,177 71,513 1996B Electric Revenue Refunding Bonds 123,887 127,756 135,355 142,344 1996C/D Electric Revenue Refunding Bonds 100,108 100,108 100,361 100,361 1997A Electric Revenue Refunding Bonds 31,735 31,735 31,816 31,816 1997B/C Electric Revenue Refunding Bonds 99,508 99,508 100,864 100,864 1998A Electric Revenue Refunding Bonds 160,612 160,730 160,385 160,045 1999A Electric Revenue Refunding Bonds 97,461 93,921 97,297 93,955

$ 1,290,489 1,360,803 1,302,477 1,388,929 (14) Nuclear Insurance Nuclear Insurance. Duke Energy owns and operates the McGuire and Oconee Nuclear Stations with two and three nuclear reactors, respectively, and operates and has a partial ownership interest in the Catawba Nuclear Station with two nuclear reactors. Nuclear insurance coverage is maintained in three program areas: liability coverage; property, decontamination and decommissioning coverage; and business interruption and/or extra expense coverage. Certain expenses associated with nuclear insurance premiums paid by Duke Energy are reimbursed by the other joint owners of the Catawba Nuclear Station.

Pursuant to the Price-Anderson Act, Duke Energy is required to insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $9.5 billion.

PrimaryLiability Insurance. The maximum required private primary liability insurance of $200 million has been purchased along with a like amount to cover certain worker tort claims.

21 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

Excess Liability Insurance. This policy currently provides approximately $9.3 billion of coverage through the Price-Anderson Act's mandatory industry-wide secondary insurance program of risk pooling. The $9.3 billion of coverage is the sum of the current potential cumulative retrospective premium assessments of

$88 million per licensed commercial nuclear reactor. This $9.3 billion will be increased by $88 million as each additional commercial nuclear reactor is licensed, or reduced by $88 million for certain nuclear reactors that are no longer operational and may be exempted from the risk pooling insurance program.

Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the nation. If such an incident occurs and public liability damages exceed primary insurance, licensees may be assessed up to $88 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident.

The $88 million amount is subject to indexing for inflation and may be subject to state premium taxes.

Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which provides property and business interruption insurance coverage for Duke Energy's nuclear facilities under the following three policy:

PrimaryProperty Insurance. This policy provides $500 million in a primary property damage coverage for each of Duke Energy's nuclear facilities.

Excess Property Insurance. This policy provides excess property, decontamination and decommissioning liability insurance in the following amounts: $2.25 billion for the Catawba Nuclear Station and $1.5 billion each for the Oconee and McGuire Nuclear Stations.

Business InterruptionInsurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each unit of the McGuire and Catawba Nuclear Stations is insured for up to approximately $4 million per week and the Oconee Nuclear Station units are insured for up to approximately $3 million per week. Coverage amounts per unit decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period and continues at 100% for 52 weeks and 80% for the next 110 weeks.

If NEIL's losses ever exceed its reserves for any of the above three programs, Duke Energy will be liable for assessments of up to five times its annual premiums. The current potential maximum assessments are as follows: Primary Property Insurance - $31 million; Excess Property Insurance - $36 million; Business Interruption Insurance - $29 million.

The other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of any liabilities for retrospective premiums and other premium assessments resulting from the Price-Anderson Act's excess secondary insurance program of risk pooling or the NEIL policies.

22 (Continued)

PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)

(15) Derivative Financial Instruments The Agency has only limited involvement with derivative financial instruments.

In May 2000, the Agency entered into two identical interest rate swap agreements, each with termination dates of January 1, 2024. The Agency's objective for entering into these interest rate swap agreements is to maximize income. Under these fixed to variable interest rate swaps, PMPA receives a fixed rate of 5.93%

through December 31, 2004 and a fixed rate of 5.63% thereafter, while paying a variable rate based on the BMA Municipal Swap Index. The notional amount of each of these agreements is $51,908.

In March, 2001, the Agency entered into an additional interest rate swap with a termination date of January 1, 2021. This swap is designed to mitigate interest rate risk of outstanding variable rate debt during rising interest rate periods and augment expected income during falling interest rate periods. PMPA receives a floating LIBOR rate and pays a floating variable rate based on the BMA Municipal Swap Index. The notional amount of this agreement is $100,000.

The fair value of the three interest rate swap agreements was approximately $3,431 and $3,610 at December 31, 2001 and 2000, respectively. Current market pricing models were used to estimate fair value of interest rate swap agreements. The fluctuation in the fair value of the interest rate swaps was a decrease of $179 in 2001 and is included in net increase in fair value of investments and derivative instruments in the statement of revenue and expenses. Total income from the interest rate swaps was $3,638 and $1,076 in 2001 and 2000, respectively, and is included in other expense, net, in the statements of revenues and expenses.

In October 2000, the Agency entered into a forward delivery agreement with a term of five years. The Agency's objective for entering into this forward delivery agreement is to maximize investment income.

The agreement entitles the Agency to receive interest at a fixed rate of 6.4825% on scheduled monthly deposits into certain debt service principal and interest accounts. The fair value of the forward delivery agreement was approximately $1,401 and $782 at December 31, 2001 and 2000. The fluctuation in the fair value of the forward delivery contract was an increase of $619 in 2001 and is included in net increase in fair value of investments and derivative instruments in the statement of revenue and expenses. Total income from the forward delivery agreement was $214 and $1,158 in 2001 and 2000, respectively, and is included in interest income in the statements of revenues and expenses.

By using derivative instruments the Agency exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative contract is positive, the counterparty owes the Agency, which creates repayment risk for the Agency. When the fair value of a derivative contract is negative, the Agency owes the counterparty and, therefore, does not possess repayment risk. The Agency minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

Market risk is the adverse effect on the value of financial instruments that results from a change in interest rates. The market risk associated with interest-rate contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

23

Supplementary Information 24

Schedule 1 PIEDMONT MUNICIPAL POWER AGENCY Schedule of Revenue and Expenses Per the Bond Resolution and Other Agreements Year ended December 31, 2001 (Dollars in thousands)

Actual Budgeted Actual Revenues Revenues Over and and (Under)

Expenses Expenses Budget Revenue (356)

Sales of electricity to participants $ 117,548 117,904 9,303 8,432 871 Sales of electricity to Duke 6,905 4,364 2,541 Sales of electricity to others 234 Interest income 26,772 26,538 1,207 1,207 Other

$ 161,735 158,445 3,290 Total revenue Expenses.

Catawba operating expenses: 911 Operation and maintenance $ 22,337 21,426 6,958 6,458 500 Nuclear fuel 483 8,744 8,261 Purchased power - Duke (233) 4,385 4,618 Payments in heu of taxes Interconnection services.

Purchased power.

8,213 9,548 (1,335)

Duke 7,549 7,789 (240)

Participants 263 156 107 Other 4,709 4,224 485 Transmission services (122)

Distribution services 1,409 1,531 Administrative and general: (132) 3,943 4,075 Agency 8,483 9,219 (736)

Duke (722) 2,485 3,207 Other Special funds deposits (withdrawals)

Bond fund: (3,751) 84,043 87,794 Deposits from revenues 39 699 660 Liquidity facility fees Reserve and Contingency fund: (372) 8,412 8,784 Deposits from revenue 455 (1,326) (1,781)

Capital additions (7,086) (7,003) (83)

Transfer excess funds Decommissioning fund:

1,324 1,324 Deposits from revenue 235 2,586 2,351 Interest income (1)

Revenue fund 8,088 7,337 (751)

Working capital 805 (4,726) (5,531)

Fuel Rate stabilization 88 Interest income (1) 10,781 10,693 (26,118) (26,117) (1)

Deposits (draws)

Supplemental power reserve. 1,008 33 975 Interest income (1)

Transfer excess funds (1,008) (975) (33)

Other capital transactions 142 Bond: other 142 Plant additions:

1,326 1,781 (455)

Reserve and contingency fund (84) 94 178 General plant 23 43 20 Distribution plant (805) 4,726 5,531 Fuel acquisitions

$ 161,735 158,445 3.290 Total expenses (1) Included in "Revenue Interest Income" 25

V" t ... ( [ ... ["" F... " - F * [7-- VT V-- [7- F -- T [-F.... [...

Schedule 2 PIEDMONT MUNICIPAL POWER AGENCY Schedule of Revenue and Expenses Per the Bond Resolution and Other Agreements Year ended December 31, 2001 (Dollars in thousands)

Funds Reserve and Supplemental Revenue Operating Bond Contingency Decommission Power Principal Working Rate Fuel Interest Capital Stabilization Account Retire Reserve Balances at beginning of year:

Assets S 65,402 171,118 28,271 46,544 83,850 8,385 35,419 15,000 Liabilities (10,299)

Net 55,103 Project revenues Participants - Electric (i) 117,548

- Facilities rent (i) 1,146

- Control services (1) 13

- Other (1) 48 Duke Povser - Electric (i) 9,303 Other - Surplus Electric (I) 6,905 Interest infome (1) 12,397 10,781 2,586 1,008 Project costs (see note)

Operations and maintenance (2) (22,337)

Fuel (3) (6,958) 6,958 Purchased power - Duke (2) (8,744) 1,324 Decommissioning (3) (1,324)

General and administration (2) (11,216)

Payments in lieu of taxes (2) (4,356)

Other (2) (2,485)

Debt service (3) (84,043) 84,043 Liquidity facility fee (3) (699) 699 Reserve and contingency (3) (8,412) 8,412 26

f-, F*- F -- - 1. V - V Schedule 2, Continued PIEDMONT MUNICIPAL POWER AGENCY Schedule of Revenue and Expenses Per the Bond Resolution and Other Agreements Year ended December 31 , 2000 (Dollars in thousands)

Funds Reserve and Supplemental Revenue Operating Bond Contingency Decommission Power Principal Working Rate Fuel Interest Capital Stabilization Account Retirement Reserve Supplemental power costs, Purchased Power - Duke (2) (8,213)

- Participants (2) (7,549)

- Other (2) (263)

"1ransmission services (2) (4,709)

I)istribution services (2) (1,409)

General and administration (2) (1,210)

PaNment in lieu of taxes (2) (30)

Other tund changes Transfers in (out)

Rate stabilization (3) 26,118 (?6,1 18)

Excess funds (3) 8,094 (7,086) (1,008)

Reimbursement (3) 1,326 (1,326)

Payments.

Debt retire/interest (2) (142) (82,365)

Capital additions (2) (1,462) (4,726)

Balance, at December 31, 2001 S 62,440 155,781 30,503 48,921 83,850 8,385 39,329 15,000 Assets S 74,895 Liabilites S (12,455)

(I) Deposited in appropriate fund Note I: In accordance with the Bond Resolution, third party payment requirements (except debt service payments) are (2) Paid to third parties transferred from Revenue Fund (Working Capital) to the Operating Fund and actual disbursements are made from the Operating Fund (3) Transfers between funds 27

F177 Jim I~LIlI

Va EP of Contents An Introduction ............ 3 Letter from the Chairman and CEO ........... 4 ElectriCities Leadership ............ 5 ElectnCities Membership ............ 6 North Carolina Municipal Power Agency Number 1 Message from the Chairman ......... 10 Board of Commissioners ....... 11 Participants ......... 12 Operational Highlights ......... 13 Financial Information ......... 18 Financial Statements ......... 19 Notes to Financial Statements ....... 25 10-Year Statistics ......... 41 North Carolina Eastern Municipal Power Agency Message from the Chairman ......... 44 Board of Commissioners ......... 45 Participants ......... 46 Operational Highlights ......... 47 Financial Information ......... 52 Financial Statements ......... 53 Notes to Financial Statements ........ 59 10-Year Statistics ......... 77 The auditreports of and financial information regardingeach North CarolinaMunicipal Power Agency are included in this report.

Each Power Agency is a separateand distinct legalentity and the inclusion of such information regardingboth entities should not be construed to indicate any relationshipbetween the two 2001 Annual Report I I

)

t 3/4

? C

/

I 7

1 A114 7ll ila l, l a t's fMFN I.I - rIllli

vn 7s i Power It brightens a dark night, keeps us warm in the winter and cools us inthe summer. Itthink entertains us and helps to about ft. It's electncity keep us safe It plays such an integral part in our daily lives, yet most of us rarely We don't give a lot of thought to the power that makes our lives so easy. We don't worry about how we get our electricity, just as long as it's there when we need it. That's where public power communities really shine In the late 19th century, a wonderful Carolina Municipal Power Agency Number 1 invention called electricity was finally were born Today 51 cities across North becoming a useful part of our daily lives But Carolina are partnered with Duke and many power companies weren't willing to CP&L. They have joint ownership in extend lines to smaller, more rural nuclear plants and coal fired plants. It's an communities. They were too far away or arrangement that helped to build new

\,

there were not enough residents to justify the generation for North Carolina It kept the costs. So towns began building their own lights on and helped North Carolina grow electric generating plants and putting up their and prosper own wires and poles. As more cities realized In the 1990's, Congress set the stage the early benefits of citizen ownership of for the 21 cities that buy their power electric systems, more communities wanted it wholesale. The non-power agency cities for themselves Municipally owned have used this new law to search the market electricity gave citizens control of their for better prices, which helps with economic power supply. Neighbors and friends made development and lower electric rates local electric decisions and customer service Today all these public power commu was a top priority. nities continue to shine in North Carolina During the 1970's, North Carolina's and the reasons are simple. Public power is public power towns began joining forces to locally controlled and locally operated.

ensure their residents, businesses and the Friends and neighbors are the utility state had a reliable and plentiful supply of employees The electric revenue stays in power With an energy crisis worsening, town and helps these public power threats of blackouts, and power companies communities grow and prosper. North teetering on bankruptcy, state voters Carolina's Public Power communities are overwhelmingly approved the concept of united in power to ensure they provide their municipal power agencies North Carolina citizens with a safe, secure, and reliable Eastern Municipal Power Agency and North supply of electricity 2001 Annual Report 1 3

Jm!Qlj is Strength A Letter from the Chairman and CEO W e've all heard the old saying, "there isstrength in numbers "That's the whole idea behind ElectriCities A unified group of cities, providing power to their residents with service that issecond to none As we prepare for the coming years, our commitment to our customers must remain our top pnority But to achieve that goal and remain a quality provider of electricity we must be united After six years of intense deregula Now we must stay the course. With a tion debate, customer choice was put on shift away from deregulation, we must the back burner in 2001. The State strengthen our bond with one another. We Legislature was focused on a budget each have individual strengths and chal shortfall and an economy on the downturn. lenges unique to our communities, but when Jesse C. Tilton, III, Meantime our cities were proving what we we combine our resources and the vast Chief Executive Officer have said all along. We are responsible, expertise of those who work for our cities, John T. Walser, Jr., reliable distributors of electricity and good everyone benefits. A unified voice also Chairman, Board of Directors stewards to our bondholders. We are means political clout as we put forth the paying off our debt on schedule. We have positive message that public power is good reduced the rate of transfers and continue for North Carolmal looking for ways to keep our costs down The cities that provide power to their The Power Agency cities as a group are in people want to continue that service because compliance with the Local Government they do it well But the reasons go much Commission (LGC) transfer policy Our deeper. Our city leaders want to ensure a residents have a safe and plentiful supply higher quality of life for their residents not of power. Our utilities are proving that only today, but also well into the future.

neighbors serving neighbors is a good way So to our cities we say, join hands in a to do business. Our cities consistently spirit of unity and togetherness. There is restore power faster than other utilities and nothing like a strong and powerful group to receive high marks when it comes to the show others that our commitment is real and questions and concerns of their customers. our partnership is strong.

4 2001 Annual Report

EleotrOities Leac{w~Dp 2001 Board of Directors John T. Walser, Jr. R.L. Willoughby Winton R. Poole William H. Batchelor Steven K. Blanchard Chairman, Lexington Vice Chairman, Secretary, Cornelius Rocky Mount Fayetteville Washington

........ j.

.gi ILiii 1i g., E';..

Malcolm A. Green Steven L. Harrell Barry C. Hayes Franz F. Holscher J. William McGuinn, Jr.

Greenville Elizal beth City Granite Falls Gastonia High Point Jackk F. Neel Samuel W. Noble Stephen H. Slough Edward A. Wyatt Altbemadle Tarboro Concord Wilson ElectriCities Management Jesse C Tilton, Ill, Chief Executive Officer

• Arthur L Hubert, Jr., Chief Operating Officer Al M Conyers, Chief Financial Officer

• Mark H Otersen, Director, Marketing & Regional Services Alice D Garland, Director, Public Affairs

• Kenneth M Raber, Director, NCEMPA Operations Steve R Shelton, Director, NCMPA1 Operations

• Clay A Norns, Director, Planning 2001 Annual Report 1 5

ElecthCities JLf jfi 1Eo Alphabetical Listing of Member Cities & Towns in 2001 City/Town Year Electric System Established Customers

• Abbeville, SC ...... 1905 ....

. 3,626

• Albemarle.. 1910 . ...... S..... 11,333

• Apex 1917 S... .9,154

• Ayden S......... 1916 ..... 3,695

• Bamberg, SC 1905.. ....

. 1,784

• Bedford, VA.. 1911 ........ ... 6,729

• Belhaven ... S..... 1920 S.... 1,139

• Bennettsville, SC ....... 1903 .....

. 4,950

• Benson .. 1913 ....... ---...... 1,800

• BlackCreek 1922 ..... S....... 685

• Blackstone, VA S....... 1888 --- 2,079

• Bo",tic.. ..... 1920 ....

. 193

• Camden, SC. 1902 ........ S........ 10,000

• Cherryille .. 1920 -- ----. 2,890

• Cla)ton S....... 1913 S....... 4,082

• Clinton, SC .1907 .....

- 4,377

• Concord ... 1901 ........ ... 23,997

• Cornelius .-. ...... 1916 S.... 1,866

• Culpeper, VA ---. -.1934 S.... 3,054

• Dallas ... 1925 ........ . ---....... 2,851

• Danville, VA 1886 --- S..... 48,718

• Drexel S....... 1926 .... 1,236

• Easley, SC --.1911 ----..--- 12,000

• Edenton . 1908 -------- .......... 3,899 SElizabeth City .. 1926 ... 10,717

• Elizabeth City State U[niversity S...... 1891 .... Uniersity

• Elkton, VA 1924.. S....... 1,020

• Enfield .-.. Pnor to 1940 1,538

• Farmville ... S..... 1904 --- 2,888

• Fayetteville Chartered 1905 -----..... 67,128

• Forest City Early l900s .... S....... . 4,732

• Fountain 1903 . .... ... 372

• Franklin, VA 1892 l...... ..... 5,242

• Fremont ... 1918. ..... 869

• Gaffney. SC 1907 -------- 7,300

• Gastonia 1919 --- 25,591

• Gramnte Falls S..... 1923 .... 2,318

• Greenville 1905 S..... 51,662

• Greer, SC 1914 ....... 10,991 lamilton H S.... 1922 --- 254 Htarrisonburg, VA S..... 1957 S....... 16,217

• Hertford 1915 ..... .... 1,271

• High Point 1893 --- 36,033

• Highlands ... 1926 ... 2,519

• Hobgood . -----. 1922 --- 320

• Hookerton 1907 ....... S422 Huntersville 1916 ... 3,125 SKings Mountain S.... 1935 ..... 3,943

• Kinston ... 1897 16,528

• La Grange 1917 ..... 1,524 6 2001 Annual Report

EleotriOties EmEwUNTflw Alphabetical Listing of Member Cities & Towns in 2001 City/Town Year Electric System Established Customers 2,607 Landis ................................ 1919..................

... 5,305 Laurens, SC ................................. . 1922 .....................

....... .... 5,932 Launnburg ............................... 1925 ........... .......

... 18,212 Lexington ...... . ..................... 1904 ......................

2,841 Lincolnton .......... ........... 1900 ........... ............

.. 1,940 Louisburg .................................. 1906.....................

... 1,145 Lucama .................................. 1889 ...................

10,066 Lumberton ............................ 1915 . .....................

302 M acclesfield . ....................... 1928 .............. ..........

1,030 M aiden ................... ....... 1920 .......... ...............

.. 14,341 M anassas, VA ...................................... 1912. ........... ..............

...... 8,176 M artinsville, VA .............................. 1900 ........... ............

9,304 M onroe ............................. 1900 .......................

8,045 Morganton ........................ 1899 .................. ......

...... 4,173 M urphy ................................. 1953.......... ..........

...... 16,821 New Bern ......................................... 1901 ............

.... 7,054 New River Light & Power (Boone) ...................... 1915 ......................

.... 4,789 Newberry, SC ........... ............. 1923 .....................

.4,401 Newton .......... ................. 1896 ................. .......

.... 527 Pikeville .................................. 1918 . ............... ......

...... 730 Pinetops .................... ............... 1925 .....................

.... 2,373 Pinevtle ........................... 1939 .......................

1,916 Red Springs ...................... 1910 .....................

2,500 Richlands, VA ............................. 1922......... ......... .....

..... 1,220 Robersonville .................................... 1919 ....................

... 26,642 Rock Hill, SC ............................ 1911 ......................

.... 29,097 Rocky Mount .................... 1902 .............. .......

..... .. 1,630 Scotland Neck ........ . .......... .... 1903 ................

...... ... 2,705 Scima .............................. 1913 ................

..... 1,596 Sharpsburg ................................... 1920 ....................

... 8,136 Shelby .............................. 1912 .......................

4,568 Smuthfield ............ .......... 1912 ................... ......

.... 2,086 Southport . ....................... 1916................... .....

..... 1,203 Stantonsburg . ................................. 1920 ...................

... 12,501 Statesville ................................... 1889 ................ . ......

.5,797 Tarboro ....... ....................... 1897 ..................... .....

tal customers UNC-Chapel Hill ....................... 1895 ............ Umversity and 430 campus rei University UNC-Greensboro .................................. 1919. ............... .....

7,025 Union, SC .................................. 1896 ........... ....... ...... ...

564 Wakefield, VA ...... .................. 1920 .................. ....... .....

.... 4,900 1909 ........... ....... ....

Wake Forest ...........................

1922......... .......

S...... 135 W alstonburg ............ ....................

... 12,384 Washington ............. ........................... 1903 .................. ......

.2,966 Waynesvtlle ................................ 1923 ...................... ......

.... 2,086 Western Carolina University . ...... .. ....... . 1920 ............... .......

..... 1,808 Westminster, SC ................... ...... 1921 .......... ....... .....

30,990 W ilson .. . . ..................... . .............. 1892 . ............ . ...... ....... . ....

1,758 W indsor ................................... 1920 ......... ............ .....

1,985 W interville ............................ . 1900 ...................

2001 Annual Report 1 7 I

T A TA 0 1111 '1I's

!IiIT,TT---Iýl Toýr:l im

I T-he Customer is F Chairman Letter to Stakeholders N orth Carolina appeared to be on the fast track to electnic deregulation during the year 2000 The likelihood that electnc industry restructunng was imminent compelled us to devote much of our time and energy prepanng for it Now, one year later, nearly everything has %khendemand is high, as well as support our sales changed. of energy to the vi holesale market. As a result of Due to events m California, deregulation this endeavor, we anticipate a savings in was put on hold early in 2001 Although we supplemental power purchases of $10 million continue to keep an eye on how restructunng is over the next 10 years progressing in other states, we are now able to Last summer Duke filed a peution Aith the refocus our attention on our customers and on Nuclear Regulatory Commission to renew the Richard L. Thomas providing the best possible service for them. operating licenses for both McGuire and CataA ba Mayor, Lexington As members of the public power nuclear stations Approval of its license extension Chairman, NCMPA1 community, we maintai an enviable position. would allow the Cata\vba Plant to continue Individually, we have the autonomy to determine operations into the 2040's, assuring our member how best to serve the customers in our cities and cities and their customers a safe, reliable, and towns At the same time, our membership in this economical power supply for many years to come.

"fratemity" enables us to partner with other public Effective January 1,2001, NCMPA1 power mumcipalities on projects that achieve entered into the \vholesale market for its savings and other benefits for consumers supplemental power Contracts with Georgia The past year is notable largely because of Power Company through 2005 and one year deal%

the many cost saving regional opportumties we with Dynegy and Entergy-Koch Trading provided reconized. The collaborative efforts that ensued for power supply " hen requirements were in resulted in several significant accomplishments excess of the Cataw ba project during 2001. Later, that will benefit the members of NCMPAI for in the fall, NCMPA1 contracted for our 2002 years to come. summer power supply needs with EKT and Aquila.

Together with Cayenta and ElectnCities, Finally, we issued an RFP in 2001 that offers we began offenng our members a new Customer more structured sales of our Catavi ba resource It Information System (CIS) The CIS will help also examines replacing that power with peaking cities streamline their btlhng procedures and power from the wholesale market At the end of increase efficiency through a program designed the year, we were in negotiations for new power specifically for municipalities It will also allow supply arrangements.

the cities that comprise NCMPA 1 to share These are but a few of our many successes common software, staff expertise, and support. tn 2001. 1believe our willingness to unite on these We are in the process of installing 10 diesel important issues made each of them not just a generators in cities throughout western North possibilhty - but a reality That's %i hy "United in Carolina as part of our distnbuted generation Power" is not just a slogan, but rather is an apt project. These generators will better enable us to description of the good we can accomplish when meet peak demand during the summer months we join together.

10 2001 Ainual Report

NCMPAl LafelflEp 2001 Board of Commissioners

• 2001 Officers Richard L. Thomas Morris A. Baker Arnold J. Koonce, Jr.

Chairman Vice-Chairman Secretary-Treasurer Mayor, Lexington Town Manager, Drexel Mayor, High Point Commissioners and Alternate Commissioners Alternate commissioner'snames appearinItalics

- Albemarle - Drexel

• Huntersville - Maiden - Pineiflle Mr Raymond I Allen Mr Moms A.Baker Mr Alex Bamette Mr Kevm C Sanders Mayor George Fowler FirstAlternate vacant Mr Benny7J Onrers Mr JerryE Cox Mr Kent M Auton Ms MaryAnn Creech Mr Jack E Ned

- Gastonia - Landis - Monroe

• Shelby

- Bostic Mr Franz E Holscher Mr Tommy Branch Mr Donald D Mitchell Mr Pete Gilbert Commissioner Vacant Mr Bob W*lkerson FirstAlternate Vacant Mr RobertJ Smith Mr Jay C Stowe Mr James Monvrw AMr S.Douglas Spell Ms Betsy Fonvtelle

• Granite Falls

• Lexington

• Cherrnyille Ms Lmda K. Story Mayor Richard L Thomas - Morganton

• Statemille Mr Jerry J Hudson Dr Caryl B. Burns Mr C PhillipHeag Sr Mr Dan Brown Mr Arthur E Peterson Mayor Wade H Strouipe, Jr Mayor Barry C. Hayes Mr L Klynt Ripple Ms. Sally W.Sandy Mr Herbert "Jim" Lawron Mr Steve B Settlemyer AMrLarry M Cranford

• Cornelius - High Point

• Lincolnton Mr James R. Bensman Mayor Arnold J. Koonce, Jr. Mr. Stephen H Peeler - Newton FirstAlternate Vacant Mr.Stnbling P Boynton Mr Jeff B. Emory Mr Edward F Burchins AMr Thurman Ross, Jr Mayor Bobby G Hutt FirstAlternate Vacant 2001 Annual Report 1 11

ECecT c System TDO City/Town Established Revenues Customers  % Ownership

• Albemarle.. . .. .. .. 1910 . 2001 -$23,363,586 ...... . 11,333 .. .. 7.604%

2000 -$23,824,196

"*Bostic . .. S.. .. ... 1920 ............ 2001- $248,991 193.. S.. .. ... .. 0.087%

2000- $243,359

"*Cherryville . .1920 ...... . 2001 - $4,458,395 .2,890 1.579%

2000- $4,610,124

"*Cornelius .. .1916 .... .. ... 2001 - $2,898,686 1,866 0.362% ..

2000- $2,812,310

"*Drexel 1926 .. ... ... .. 2001- $1,697,006. 1,236 ..0507% ..

2000- $1,660,610

"*Gastonia .. ...... 1919 ...... 2001--$55,587,515. 25,591 17 121%

2000 -$56,861,182

"*Granite Falls. ... ... . ..S1923. .. 200 1 -- $4 ,102,7 8 1 2,318 0912%

2000- $4,226,271

"*High Point .. ... ... S1893 ... 2001 - $80,765,534 36.033 ..

. .. ... . 18960%

2000-$78,419,127

"*Huntersville . 1916 ........... 2001-- $4,659,163 3,125 0623%

2000-- $3,974,221

"*Landis . 1919 ....... .. 2001 - $3,840,410 2,607. 1 130%

2000-- $3,485,020

"*Lexington. 1904 .. ......... 2001 -$41,458,163 ...... ... 18,212. S.. . ... 12934%

2000 -$41,001,556

"*Lincolnton. 1900 .......... 2001 - $5,463,620 2,841 S.. .. . .. .. 1608%

2000-- $5,450,148

"*Maiden 1920 ........... 2001 - $5,260,709 ..... 1,030 1.289%

2000-- $5,396,878

"*Monroe 1900 ............ 2001 -$33,666,778 9,304.. .. 10038%

2000 -$33,739,383

"*Morganton.. .... .. .. 1899 ......... ... 2001 -$21,752,955 .. 8,045 6.735%

2000 -$22,022,361

"*Newton. S.. .. .. 1896 .. .. ... ... 2001 - $7,830,840 ... .. .4,401 .. .. .. ... 2115%

2000-- $7,513,216

"*Pineville .1939 .... .. 2001 - $8,788,260. .2,373 .0536%

2000-- $8,231,250

"*Shelby .. S... .. 1912 ........... 2001--$14,466,423. 8,136 .. .... .5996% ..

2000 -$14,753,612

"*Statesxille .. S... .. 1889 ... .. ... ... 2001 --$31,136,866.. 12.501 .9864%

2000 -$30,736,338 12 2001 Annual Report

Operational OfljUQ Plant Informatic Capacity* Availability*

Factor% Factor%

"*Catawba Unit I 1009 99.6

"*Catawba Unit 2 86.7 85.7

"*McGuire Unit 1 90.1 88 0

"*McGuire Unit 2 102.7 1000

• These numbers are reportedby Duke to the NuclearRegulatory Commission in the units' December 2001 OperatingData Report Catawba Unit I did not have a refueling outage in 2001. The next refueling outage is scheduled for April 27, 2002.

Catawba Unit 2 began a refueling outage on September 15, 2001 that ended on October 23 The next refueling outage for Unit 2 is scheduled to begin in March 2003.

McGuire Unit 1began a refueling outage on March 9, 2001 that ended on April Making upgrades and keeping up with repairs means safe and reliable power 17 The next refuelng outage for the unit is It also ensures the electric distnbution system will remain a valuable part of scheduled to begin September 13, 2002 the community McGuire Unit 2 did not have a refueling outage in 2001. Unit 2 began a refueling Company for the purchase of 125 MW from Duke Electric Transmission in outage February 22, 2002 that is scheduled to which began on January 1,2001. NCMPA1 accordance with Duke's Open Access end on March 25.

Catawba Unit 1 and McGuire Unit 2 also has the right to schedule and receive Transmission Tariff To effectuate this new placed in the top 50 nuclear units in the 42 MVW of power from the Southeastern service, all the required agreements and Power Administration. In addition, amendments to existing agreements have world based upon gross generation in 2001.

NCMPA1 purchased 50 MW of firm been filed and approved by the Federal Catawba Unit 1 and McGuire Unit 2 were capacity from Dynegy Power Marketing, Energy Regulatory Commission.

15th and 24th, respectively Inc., from their Rockingham County North On January 1, 2001, NCMPA1 also New Supplemental Power and Carolina Units 1 through 4 and 50 MW of became responsible for scheduling and Transmission Arrangements System Firm Energy delivered to the Duke delivering power for all of its requirements On January 1, 2001, NCMPA1 no control area from Entergy-Koch Trading, above its Catawba Project entitlements longer purchased power from Duke Energy from their Dayton Power and Light NCMPAI has entered a two-year contract for its requirements above its Catawba Company Resources for June 1, 2001 with Entergy-Koch Trading to serve as Project entitlement. To meet its supplemental through August 31, 2001. NCMPAI's resource manager Entergy power requirements, NCMPA1 has entered a NCMPAI also purchases transmission Koch Trading has the responsibility of five-year contract with Georgia Power services for its native load requirements managing and marketing all of NCMPAI's 2001 Annual Report i 13

Operational I I distnbuted generation The project consists of ten 1,825 kW generators located at city delivery points. The generators are scheduled to be available for service by June 1,2002 Also, NCMPA1 has been successful in placing under contract approximately 45 MW of generation owned by cities and retail customers This generation is available for NCMPAI power supply during times of high demand and spiking sxholesale prices Load Management More than $8,000,000 worth of savings were passed on to customers as a result of NCMPA I's load management operations. These efforts successfully reduced an a%erage of 85 MW of peak demand each month NCMPA1 has 75% ownership of Catawba Nuclear Station Unit 2 located on Lake Wylie in South Carolina The unit began commercial operation in 1986 Economic Development NCMPA1 has two employees that work on-site at Catawba The western cities continue success with industry recruitment and expansion of surplus energy. For 2001, NCMPAI had 2001 Submitting the applications for the their existing businesses. In 2001, NCMPA1 revenues of $36 3 million from surplus four very similar units together is projected members added 1,023 new jobs to their energy sales to provide significant cost savings as communities with investments totaling In addition, Entergy-Koch Trading is compared to separate applications for each $207,655,165. New load added to the responsible for scheduling the delivery of Station Duke believes that the Cataw*ba Agency totaled more than 15 MW.

energy to meet NCMPA l's energy and McGuire applications are on track and NCMPA1 staff continues efforts with the requirements aboxe its Catawba Project proceeding basically as expected. Duke Department of Commerce and the Regional entitlement. NCMPA I's Peak Demand previously submitted applications for Partnerships to further the strategic load in 2001 was 989 MW Operating License Extensions for its three growsth efforts in our communities Oconee Units on July 6, 1998 The NRC Advertising and direct mail was Catawba and McGuire Operating approved the 20 year License Extensions for focused on automotive, pharmaceutical and License Extension the Oconee Units on May 23, 2000 medical instruments, boat manufacturers/

Duke Energy submitted concurrent suppliers, high technology, electronics, applications for Operating License Distributed Generation telecommunications, biotechnology, rubber Extensions for all four units at the Catawba The decision was made in 2001 to and plastics, research and development, and and McGuire Nuclear Stations on June 13, construct 18 25 MW of disel fueled software development industries. There 14 2001 Annual Report

Operational EuDl gllQe were approximately 90 inquiries made which resulted in numerous site visits.

Marketing During 2001, NCMPA1 and its participants continued efforts to strengthen business relationships with their largest industrial and commercial customers. The customer retention program is designed to help industries and businesses in member communities to become more efficient consumers of electricity.

The largest industrial and commercial customers provide vital jobs and a broader tax base to the communities where they are located. Helping these customers improve their operational efficiencies helps to ensure these companies will prosper in the member cities The customer retention program Pbhic power crews are at work no matter what the weather. In most cases includes innovative rates, educational electricity is restored faster in public power communities because the crews live in opportunities on such subjects as electric the towns where they work.

motors and drives, predictive maintenance, compressed air, and our Energy Solutions combined electric department celebrated its daily operations. Customers have already Partner (ESP) program. ESP offers alliance four year anniversary and achievements with seen improvements in bill information, partnerships that have been formed to provide an employee appreciation luncheon. Among format, and payment options. Further solutions to our members' customers' needs other achievements in 2001, the department improvements are expected as both towns Our lead backup generation partner sold over received the highest safety award given by transition to a new computer and billing 1,000 kW of new generation to NCMPA1 the NC Association of Municipal Electric system in the future.

customers in 2001. OtherESP solutions Systems for working in excess of 35,000 The HuntersvillelComelius merger has include lighting, demand controllers, and hours without an accident or injury. been successful and shows that power quality. Reduced operating costs and economies regionalization of electric systems is possible of scale from double-digit load growth have and economical for customers and towns Huntersville & Cornelius enabled both towns to reduce electric rates.

The merger of Huntersville and As both towns and the region continue to Customer Retention Program Cornelius electric operations in 1997 grow and best practices are implemented, 2001 saw ongoing efforts by NCMPA1 continues to show reduced operating costs, operating costs continue to decline. and its participants to strengthen business exceptional customer service, and value for Providing safe, responsive, and value relationships with their largest industrial and customers of the towns. In July 2001, the added customer service is emphasized in commercial customers NCMPA1 continues 2001 Annual Report 1 15

Qperational ]ITI to expand the lex el of energy information available to these customers through its Customer Billing System.

Retail Billing Services NCMPAI expanded its retail billing services to the cities this year by 20 percent for a total of 300 accounts in the Customer Billing System. NCMPA1 uses this system to provide retail billing assistance and load profile data for the cities' largest customers in the Customer Retention Program. In 2001, NCMPA 1 further extended the service to new industrial and commercial customers on innovative retail rates that could not be easily accommodated by the billing systems in the cities NCMPAI is currently providing city staff members with intemet access to the customer metering and billing data Through a secure extranet site, Customers in public power towns can take care of business locally (usually town authorized city staff members can view their hall) They can also pick up the phone and deal with a real live person, instead of an city's customers' usage history and other automated system related information The Agency will begin marketing access to the site by the custom Wholesale Rates Regulatory Commission regulations require ers themselves in 2002. Information The Agency had a 2% wholesale rate that these plants have a professional security gathered from real time meters that is increase this year. NCMPA I developed staff and demonstrate they can withstand an maintained in the data warehouse will wholesale rate alternatives to meet its future attack from a group armed with automatic provide customers with useful information power supply needs. weapons, explosives and insider assistance concerning their usage patterns and billing Under the contractual arrangement with history, thus enabling them to make more Security NCMPA1, Duke Energy handles all issues efficient use of their energy resources. Following the terrorist attacks on the of security in accordance with federal NCMPA1 also provides retail-billing World Trade Center and the Pentagon on regulations Duke is closely coordinating services for the Toxkn of Pineville through September 11, 2001, the nation's nuclear with federal, state, and local authorities and its Huntersville/Cornehus office power plants have come under scrutiny they have taken and will continue to take Huntersville/Cornelius office staff work about Nkhether they could withstand a appropriate steps to ensure safety and with the toA n each month in processing terrorist stnke As a result of the 9/11 security at the CataA ba Nuclear Station billing information for approximately 2,600 eN ents, nuclear power plants across the Unit 2 in which NCMPAI has 75 percent customers United States have upgraded their already o%%nership impressive security measures Nuclear 16 2001 Annual Reporl

Operational Highlights NCMPAI Participant Energy Usage Forecast for 2002 is from Sept 2001 Load Forecast 4S Jan Feb Ma. Apr May Juine July Au, Sept Oct Nov.

SActua, 2000 SActual2001 SFoecast2002 NCMPAI Participant CP Demand NOTE: At Power Agency Delivery Level - (Billing Point) including SEPA

• Forecast for 2002 is frm Sept 2001 Load Forecast C

lit Jan Feb Mar Apr. May June July Aug Sept Oct. Nov Dec.

SAua 12000 - Acut 2001 - Threcast 2002 NCWIPAI Economic Development

$207 nfIlion 2,000 201M loo0

%0¢ 10¢ 2000 2001 20M0 2001 2000 2001 Investments in Millions Megawatt Growth Number of New Jobs 2 Aniual C1 u~ort 17

t iE3 ,,

Ff7~r--2 ~TII nfrmallom Investment Portfolio Statistics Debt Outstaniding NCMPA1 Bonds Outstanding Earnings Debt Outstanding 12/31

• Series 1985B $80,575,000 Eamnngs* incoine Rate of Retum WeightedAverage ° Senes 1988 $5,526,000 Balance Interest Comt

• 2001 $51,850,000 6.06%

• 2000 $55,857,000 6.37% Fixed Rate Bon ds

• Series 1990 $18,410,000

• 2001 $2,2 12,436,000 5.97%

Market Value as of 12/31

• 2000 $2,2 71,884,000 601%

• Series 1992 $1,033,855,000 tVaue 4veruge Matunt* - Series 1993 $484,550,000

• 2001 $948,926,000 45 years NCMPA1 Bonid Reconciliation

• Senes 1995A $79,440,000

• 2000 $959,519,000 5 1 years

"* Bonds Outstainding

• Series 1997A $97,775,000 Transactions 12/31/00 $2,271,884,000

- Senes 1998A $128,365,000 NmbdJer Amount

"* Matured

• 2001 1/1/01 - 59,448,000

• Series 1999A $83,340,000 670 $9,685,535,000

• 2000 643 $7,450,227,000

"* Bonds - Senes 1999B $200,600,000

• For Earnings and Market thlue, asnotnts ttu hude Outstanding ui onwefrma and nuta!ei vahle of %ecunties hekl in the 12/31/01 $2,212,436,000 decommnusousng t nat 18 2@C1 Anrual Report

Independent Auditors' EowI:t W e have audited the accompanying balance sheets of North Carolina Municipal Power Agency Number 1 as of December 31, 2001 and 2000, and the related statements of revenues and expenses and changes in retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Agency's management Our responsibility isto express an opinion on these financial statements based on our audits We conducted our audits in accordance reasonable basis for our opinion. Our audits were made for the purpose of with auditing standards generally accepted In our opinion, the financial statements forming an opinion on the basic financial in the United States of America Those referred to above present fairly, in all statements taken as a whole. The supplementary standards require that we plan and perform material respects, the financial position of information included in the Schedules of the audit to obtain reasonable assurance North Carolina Municipal Power Agency Revenues and Expenses per Bond Resolution about whether the financial statements are Number 1as of December 31, 2001 and and Other Agreements and Schedules of 2000, and the results of its operations and its Changes in Assets of Funds Invested is free of material misstatement. An audit cash flows for the years then ended in presented for purposes of additional analysis includes examining, on a test basis, evidence supporting the amounts and conformity with accounting principles and is not a required part of the basic disclosures in the financial statements An generally accepted in the United States of financial statements. Such information has audit also includes assessing the accounting America been subjected to the auditing procedures principles used and significant estimates As discussed in note B to the financial apphed in the audit of the basic financial made by management, as well as evaluating statements, the Agency changed its method of statements and, in our opinion, is fairly stated the overall financial statement presentation. accounting for derivative financial instruments in all material respects in relation to the basic We believe that our audits provide a in2001 financial statements taken as a whole.

Raleigh, North Carolina

• March 29, 2002 2001 Annual Report 1 19

tC)cj AC1'jV7; S heets (SOOOs)

December 31, 2001 2000 Assets

"*Electric Utility Plant Electric plant in service, net of accumulated depreciation of $601,818 and $562,787 $ 844,504 $ 887,345 Construction %N ork in progress 12,952 4,551 Nuclear fuel, net of accumulated amortization of $101,233 and $81,266 41,830 46,648 899,286 938,544

"*Non-Utility Property and Equipment, net 2,108 2,180

"*Special Funds Invested (Notes C and E).

Bond fund 319,704 318,661 Reserve and contingency fund 20,270 17,229 Special reserve fund 1,104 1,028 341,078 336,918

"*Trust for Decommissioning Costs (Notes D and E) 128,263 119,769

"*Operating Assets Funds invested (Notes C and E)

Revenue fund 251,680 249,769 Operating fund 91,759 109,418 Supplemental fund 143,055 150,614 486.494 509,801 Participant accounts receivable 19,280 19,905 Operating accounts receivable 2,677 5,996 Prepaid expenses 39,025 39,157 Denvatie financial instruments (Note B) 12,149 559,625 574,859

"* Deferred Costs Unamortized debt issuance costs 33.715 35,758 Costs of advance refundmgs of debt 254,745 277,712 Costs to be reco~ered from future billings to participants (Note D) 439.400 430,594 727 860 744,064

$2,658,220 $2,716,334 See accompan)iingnoteofioinancal statements 20 2001 Annjal Report

n fVl© Sheets (Sooos)

December 31, 2001 2000 Liabilities and Retained Earnings

"*Long-Term Debt Bonds, net of unamortized discount (Note E) $2,051,926 $2,105,735

"*Special Funds Liabilities:

Construction payable 3,100 Current maturities of bonds (Note E) 59,508 59,448 Accrued interest on bonds 57,858 62,273 120,466 121,721

"*Liability for Decommissioning Costs 117,553 103,600

"*Operating Liabilities:

Accounts payable 11,660 1,952 13,382 14,480 Accrued taxes 25,042 16,432

"*Deferred Revenues (Note D) 335,833 361,446

"*Commitments and Contingencies (Note F)

"*Retained Earmngs 7,400 7,400

$2,658,220 $2,716,334 2001 Annual Report 1 21

Statements of 1i1 )

4:t7 An And Changes in Retained Earnings (SO00s)

Year Ended December31, 2001 2000

• Operating Revenues Sales of electricity to participants $261,063 $261,921 Sales of electncity to utilities 62,616 55,759 Other rexenues (Note G) 775 7,266 324,454 324,946

"*Operating Expenses Operation and maintenance 76,708 83,348 Nuclear fuel 26,505 27,286 Interconnection sen ices:

Purchased power 49,766 45,730 Transmission and distribution 11,225 14,109 Other 113 134 61,104 59,973 AdministratiNe and general 29,584 30,851 Gross receipts and excise taxes 11,188 10,968 Property tax 12,518 12,920 Depreciation 50,069 51,233 267,676 276,579

"*Net Operating Income 56,778 48,367

"*Interest Charges (Credits)

Interest expense 117,123 123,028 Amortization of debt refunding costs 22,967 23,606 Amortization of debt discount and issuance costs 7,743 7,583 Gain on redemption of bonds (43)

Net increase in fair value of investments and derivative financial instruments (6,823) (35,406)

Investment income (42,463) (48,612) 98,547 70,156

"*Net Cost to be Recovered From Future Billings to Participants (Note D) 34,419 21,789

"*Revenues (Under) Over Expenses Before Cumulative Effect of a Change in Accounting Principle (7,350) 0

"*Cumulative Effect of a Change in Accounting Principle (Note B) 7,350

"*Excess of Revenues Over Expenses 0 0

"*Retained Earnings, Beginning of year 7,400 7,400

"* Retained Earnings, End of year $ 7,400 $ 7,400 See accomnp;anvng note v to financial statements 22 2001 Anqual Report

Statements of

($ooos)

Year EndedDecember 31, 2001 2000

" Cash Flows from Operating Activities Receipts from sales of electricity $ 327,907 $ 315,463 775 7,266 Receipts from other revenues (181,696) (204,420)

Payments of operating expenses 146,986 118,309 Net cash provided by operating activities

" Cash Flows from Capital and Related Financing Activities:

(121,538) (118,286)

Interest paid (30,859) (29,122)

Additions to electric utility plant and non-utility property and equipment (59,448) (55,283)

Bonds retired (211,845) (202,691)

Net cash used for capital and related financing activities

"*Cash Flows from Investing Activities.

9,490,720 7,412,283 Sales and maturities of investment securities Purchases of investment securities (9,466,442) (7,374,575) 40,585 46,645 Investment earnings receipts from non-construction funds 64,863 84,353 Net cash provided by investing activities

"*Net Increase (Decrease) in Operating Cash 4 (29)

• Operating Cash, Beginning of year 1 30

$ 5 $ 1

"*Operating Cash, End of year See accompanyingnotes to financialstatements.

2001 Annual Report 123

NI I, t.,10 i]r3o}.

(>

($OOOs)

Year Enided Deaember31, 2001 2000

• Reconciliation of Net Operating Income to Net Cash Provided by Operating Activities Net Operating Income $ 56,778 S 48,367 Adjustments:

Depreciation 50,069 51,233 Amortization of nuclear fuel 26,505 27,286 Changes in assets and liabilities:

Decrease (increase) in participant accounts receivable 625 (617)

Decrease (increase) in operating accounts receivable 3,319 (1,908)

Decrease in prepaid expenses 132 1,709 Increase (decrease) in accounts payable 10,656 (8,239)

(Decrease) increase in accrued taxes (1,098) 478 Total Adjustments 90,208 69,942 Net Cash Pro- ided by Operating Actix ities $146,986 $118,309 See accompanying notev tofinancialstatements 24 2001 Annjal Reoort

Rao+/- to Financial Statements Years Ended December 31, 2001 and 2000 A. GENERAL MATTERS powersystem and the Agency's project andfor to purchase from the Agency its all-require the exchange of powerbetween Unit I and ments bulk power supply, in excess of power Unit2 of the station and between the Catawba allotments from the Southeastern Power North Carolina Municipal Power Agency wuits andDuke's McGuire NuclearStation. The Administration (SEPA), which includes its total Number 1(Agency) is ajoint agency organized agreement alsoprovidesfor the purchase and share of project output (as defined by the and existing pursuant to Chapter 159B of the sale of capacity andenergy, and the transmis Project Power Sales Agreement) The Agency General Statutes of North Carolina to enable sion ofenergy to the Agency's participants is obligated to provide all electrc power municipalities owning electric distribution As part of the InterconnectionAgreement, required by each participant at the respective systems, through the organization of the the Agency agreed to sell back to Duke, on a delivery points. Each participant is obligated to Agency, to finance, construct, own, operate, take-or-pay basis, capacityfrom each Catawba pay its share of the operating and debt service and maintain electric generation and transrrUs unit in decreasingamounts In calendaryears costs of the project.

sion facilities. The Agency has nineteen 2001 and2000, the Agency retained100 percent The Agency's participants receive their members (participants) with interests ranging and approximately98percent, respectivel, of total electric power, exclusive of power from 0 0869% to 18.9600%, which receive theAgency's shareof the station'saggregate allotments from SEPA, from the Agency Such power from the Agency availablecapadity On January 1,2001, the sell power is provided by project output together back arrangementterminated with supplemental purchases of power. In The Project The Operationand FuelAgreement accordance with an agreement between the The Agency has entered into several providesfor Duke to operate,maintain,andfuel Agency and Duke, beginning January 1,2001, agreements with Duke Energy Corporation the station, to make renewals,replacements, the Agency began making its supplemental (Duke) which govern the purchase, ownership, and capitaladditionsas approvedby the purchases from another source construction, operation, and maintenance of the Agency,; andfor the ultimatedecommissioning To meet its supplemental power project.

of the station at the end of its usefid life. requirements, the Agency has entered a five The Purchase,Construction,and The Agency's acquisition of its ownership year contract with Georgia Power Company Ownership Agreementprovides, among other interest is being financed by electnc revenue for the purchase of 125 MW. In addition, the things,forthe Agency to purchase a 75%

bonds pursuant to Resolution No. R-16-78, as Agency purchased 100 MW from two undivided ownership interest in Unit 2 of the amended, (resolution) of the Board of suppliers for June through August.

CatmabaNuclearStation (station) anda Commissioners of the Agency. The resolution Pursuant to two "Reliability Exchanges" 37.5% undividedownership interest in certain established special funds to hold proceeds from contained inthe Interconnection Agreement, supportfactlities of the station (project) debt issuance, such proceeds to be used for costs project output is provided in essentially equal However bY' virtue of variousprovisionsin the of acquisition and construction of the project, amounts from Catawba Unit 2 and three other InterconnectionAgreement and the Operation and to establish certain reserves. The resolution nuclear units (Catawba Unit 1,McGuire andFuelAgreement,the Agency (1) bearsthe also established special funds in which project Unit 1,and McGuire Unit 2) inoperation on costs ofacquisition,construction,operation, revenues are deposited and from which project the Duke system, all of similar size and andmaintenance of 37.5% of Unit I and operating costs, debt service, and other specified capacity. The reliability exchanges are intended 37.5% of Unit 2, and(2) has the same payments relating to the project are made. to make more reliable the supply of capacity proportionaterightto the output ofand bears The Agency has entered into a Project and energy to the Agency in the amount to the risks associatedwith the lack ofoperation Power Sales Agreement and a Supplemental which the Agency is entitled pursuant to its ofsuch units.

Power Sales Agreement with each participant ownership interest inCatawba Unit 2, and to The InterconnectionAgreement provides These agreements provide for each participant mitigate potential adverse economic effects on for the interconnectionbetween Duke's electric 2001 Annual Report 125

7-3 (conmtinm eci the Agency and the participants from community, and electric powA er marketers. The The Board of Commissioners of the unscheduled outages of Cata\x ba Unit 2. Study Commission is charged ýkith examining Agency, inconjunction %N ith the Board of Correspondingly, the Agency bears nsls the cost, adequacy, availability, and pricing of Directors of ElectnCities of North Carolina, resulting from unscheduled outages of any electric rates and service inNorth Carolina to Inc, has developed a strategic plan to address Cata\x ba or McGuire Unit detemiine whether legislation is necessary to deregulation Inaddition, the Agency assure an adequate and reliable source of periodically reviews its regulatory assets and ElectriCities of North Carolina, Inc. electncity and economical, fair, and equitable the impact of recovenng such assets on ElectnCities of North Carolina, Inc rates for all consumers of electricity inNorth Agency rates Also, the Agency's manage (ElectriCities), organized as ajoint municipal Carolina ment and Board are participating inthe assistance agency under the General Statutes of After much discussion and negotiations, deregulation debate, both on the national and North Carolina, is a public body and body the Study Commission presented a report to the state levels corporate and politic created for the puipose of General Assembly inMay 2000 which For further discussion about deregulation proiding aid and assistance to municipalities included recommendations for full retail choice and the possible effects on rates and deferred inconnection \Nith their electnc systems and to no later that January 1,2006 with fifty percent expenses, see Note D joint agencies, such as the Agency The Agency of each power supplier's customer load ha ing has entered into a management agreement with the option of retail choice on January 1,2005 B. SIGNIFICANT ACCOUNTING ElectriCities Under the current management The report indicated that the Study Cominus POLICIES agreement, ElectriCities is required to provide sion would then make recommendations on all personnel and personnel sen ices necessary how to address other aspects of deregulation Basis of Accounting for the Agency to conduct its business in an such as stranded costs recovery, the Agency's The accounts of the Agency are economic and efficient manner debt, consumer protection, environment and maintained on the accrual basis, inaccordance altemative energy, tax laws, transmission and xxith the Unifomi System of Accounts of the Industry Restructuring distribution, and any other areas xxhIch need to Federal Energy Regulatory Commission, and Developments and Related be addressed are inconformity with accounting principles Uncertainties In early 2001, the Study Commission generally accepted in the United States of Federal regulations have been passed determined that because of Califomia's America (GAAP) The Agency has adopted which encourage N% holesale competition circumstances, North Carolina would take a the pnnciples promulgated by the Govern among utility and non-utility power producers "goslow" attitude toward deregulation No mental Accounting Standards Board (GASB)

Similar regulations ar contemplated for retail recommendations were made to the General and Statement of Financial Accounting competition at both the federal and state level Assembly dunng 2001 and none are antici Standard (SFAS) No 71 "Accounting for the However, because of other states' experiences pated in2002 Effects of Certain T* pes of Regulation:' as with deregulation, momentum has slowed Because the Study Commission does not amended. This standard allows utilities to siggificantly mNorth Carolina. intend to make any recommendation to the capitalize or defer certain costs and/or In 1997, the North Carolina General General Assembly dunng 2002, and because revenues based upon the Agency's ongoing Assembly created the "'StudyCommission on the General Assembly is not bound by the assessment that it is probable that such items the Future of Elector Service inNorth work of the Study Commission, and because will be recovered through future revenues.

Carolina" (Study Commission) The Study other entities are able to propose legislation on In the future, issues of competitive Commission is compnsed of 30 members, this issue, the Agency cannot predict NN hether market forces and restructuring inthe electoc representing lawmakers, the North Carolina there NN ill be any legislative initiatiN es, xxhat the utility industry might require the reduction in municipal, coopemtix e,and private electnc results of legislative initiatives will be, or the carrying value of the Agency's regulatory utilities, electric consumers, the environmental  %% hether any such legislation will become law assets unless appropriate action is taken to 26 2001 Anrvjal Report

[k~Qe (continued) assure the recovery of these regulatory assets, capitalized until such time as the cores are payment to DOE for the Catawba station and even in a market environment. placed in the reactor. No interest is capitalized bills the co-owners monthly for their proportion on fuel cores When placed in the reactor, they ate share. The Agency's payments to Duke Financial Reporting are amortized and charged to fuel expense on were approximately $870,000 and $843,000 in Under GASB Statement No. 20, the units of production method. Amounts are 2001 and 2000, respectively, and were recorded "Accounting and Financial Reporting for removed from the books upon disposal of the as fuel expense.

Proprietary Funds and Other Governmental spent nuclear fuel. Nuclear fuel expense Under provisions of the Nuclear Waste Entities that Use Proprietary Fund Accounting," includes a provision for estimated spent nuclear Policy Act of 1982, Duke, on behalf of all co the Agency has adopted the option to apply fuel disposal costs which is being collected owners of the Catawba station, has entered into Financial Accounting Standards Board (FASB) currently from members. Amortization of contracts with the DOE for the disposal of spent statements and interpretations that do not nuclear fuel costs includes estimated disposal nuclear fuel. The DOE failed to begin accepting conflict with or contradict GASB pronounce costs of $6,544,000 and $6,357,000 for the the spent nuclear fuel on January 31, 1998, the ments years ended December 31, 2001 and 2000, date provided by the Nuclear Waste Policy Act respectively. and Duke's contract with the DOE. In 1998, Electric Plant in Service The Energy Policy Act of 1992 established Duke, on behalf of all co-owners, filed a claim All expenditures associated with the a fund for the decontamination and decommis with the United States Court of Federal Claims development and construction of the Agency's sioning of the Department of Energy's (DOE) against the DOE for damages arising out of the ownership interest in the Catawba station, uranium ennchment plants. Nuclear plant DOE's failure to begin accepting the spent including interest expense net of investment licensees are subject to an annual assessment for nuclear fuel Claimed damages are intended to income on funds not yet expended, have been 15 years based on their pro rata share of past recover costs incurred and to be incurred as a recorded at original cost and are being enrichment services Duke makes the annual result of the DOE's partial material breach of its depreciated on a straight-line basis over the average composite life of each unit's assets. At December 31, 2001, the remaining composite December 31, average life for Catawba's assets was 18 years.

Original costs of major classes of the Agency's Electric Plant In Service ($O00s) 2001 2000 electric plant in service at December 31, 2001 Land $ 19,768 $ 19,768 and 2000 are shown inthe chart at right.

Structures and improvements 384,096 389,198 Reactor plant equipment 593,955 594,893 Construction Work in Progress Turbo generator units 165,145 165,145 All expenditures related to capital Accessory electric equipment 123,497 123,576 additions are capitalized as construction work in Miscellaneous plant equipment 48,690 48,731 progress until such time as they are completed Station equipment 10,959 10,959 and transferred to Electric Plant in Service. No S Unclassified 100,212 97,862 interest is capitalized on capital additions.

1,446,322 1,450,132 Depreciation expense is recognized on these

- Accumulated depreciation (601,818) (562,787) items after they are transferred

$ 844,504 $ 887,345 Nuclear Fuel All expenditures related to the purchase Unclassifiedassets are in service but not yet classifiedto specific plant accounts.

and construction of nuclear fuel cores are 2001 Annual Report 1 27

N contract, including costs associated with Financial Reporting for Certain Investments All derivatives are recognized on the securing additional spent fuel storage capacity and for External Investment Pools," xxhich balance sheet at their fair value estimated based requires investments in marketable debt on current market pricing models The Agency Non-Utility Property and secunties to be reported at fair value. has not designated any of its denvatives as Equipment hedges Changes inthe fair value of derivative Expenditures related to purchasing and Derivative Financial Instruments instruments are reported incurrent-penod installing an in-house computer,jointly owned InJune 1998, the FASB issued SEAS No revenues and expenses with North Carolina Eastern Municipal Power 133, "Accounting for Denvative Instruments For the year ended December 31, 2000, Agency (NCEMPA), haxe been capitalized and and Certain Hedging Activities" (SFAS No prior to the adoption of SFAS No. 133, the are fully depreciated In addition, the Agency 133). InJune 2000, the FASB issued SFAS Agency entered into interest rate swap has purchased vanous computer equipment for No 138, "Accounting for Certain Denvauie agreements For interest rate swaps, fair value its load management and telemetry programs, Instruments and Certain Hedging Activities, an \Nhich would be paid or received if the swap

",hich are being depreciated oxer the estimated Amendment of SEAS 133" (SFAS No 138) were terminated isaccrued and recognized in useful life of the equipment Also included are SFAS No. 133 and SEAS No 138 require that 'Net increase infair valuc of investments and the land and administratixe office building all derivative instruments be recorded on the denvative financial instruments" and may jointly owned with NCEMPA and used by both balance sheet at their respective fair values. change as market interest rates change. If a agencies and ElectnCities. The administrative SEAS No 133 and SFAS No 138 are effective swap contract isterminated pnor to its office building is being depreciated over 37 1/2 for all fiscal years beginning after June 30, matunty, the gain or loss is recognized years on a straight-line basis 2000 The Agency adopted SEAS No. 133 and immediately.

Non-Utility Property and Equipment SEAS No 138 on January 1,2001 In The Agency has only limited involve onginal costs at December 31, 2001 and 2000 accordance with the transition provisions of ment xxith den\ati\ e financial instruments In are shom% n in the chart beloxx. SFAS No 133, the Agency recorded a December 1999, the Agency entered into an cumulative-effect-adjustment of $7,350,000 in interest rate swap agreement wvith a temlnation Investments the statement of revenues and expenses to date of December 2009 The Agency's The Agency implemented the provisions recognize at fair value all denvatives objective for entenng into the interest rate swap of GASB Statement No 31, "Accounting and outstanding at that date agreement is to synthetically cown et a portion of its fixed rate debt to vanable rate debt over the life of the swap Under the fixed to variable interest rate swap, NCEMPA receives a fixed Non-Utility Property rate of 4.984% through December 2009, \Nhile December31, and Equipment ($O00s) 2001 paying a variable rate based on the BMA 2000 Municipal Swap Index Interest paid and

"* Land $ 710 receix ed under the swap agreement increases

$ 710

"* Structures and improvements 1,499 and decreases, respectively, interest expense 1,499

"*Computer equipment 1,000 The net effect was to reduce interest expense 998

"* Telemetry equipment 745 by $4,674,000 and $1,706,000 in2001 and 645 3,954 2000. respectiely The notional anmount of this 3,852

"* Accumulated depreciation agreement is$200,600,000 (1,846) (1,672)

$ 2,108 The fair value of the interest rate swap

$ 2,180 agreement was approximately $12,149,000 and $7,350,000 at December 31,2001 and 28 2001 Aqnual Report

e (continued) 2000, respectively. Current market pricing To satisfy the NRC's financial capability (SFAS No. 143) SFAS No. 143 requires the models were used to estimate the fair value of regulations, the Agency established an external Agency to record the fair value of an asset the interest rate swap agreement. The fluctuation trust fund (the Decommissioning Trust) retirement obligation as a liability inthe period inthe fair value of the interest rate swaps was an pursuant to a trust agreement with a bank. The inwhich it incurs a legal obligation associated increase of $4,799,000 in2001 and is included Agency's certification of financial capability with the retirement of tangible long-lived assets in "Increase in fair value of investments and requires that the Agency make annual deposits that result from the acquisition, construction, derivative financial instruments" in the to the Decommissioning Trust which, together development and/or normal use of the assets statement of revenues and expenses with the investment earnings and amounts The Agency is required to adopt SFAS No 143 By using derivative instruments, the previously on deposit inthe trust, are anticipated on January 1,2003. The Agency will record a Agency exposes itself to credit risk and market to result insufficient funds being held inthe corresponding asset which will be depreciated risk. Credit risk is the failure of the counterparty Decommissioning Trust at the expiration of the over the life of the asset. Subsequent to the to perform under the terms of the derivative current operating licenses for the Catawba Units initial measurement of the asset retirement contract. When the fair value of the derivative (currently 2024 for Unit I and 2026 for Unit 2) obligation, the obligation will be adjusted at the contract is positive, the counterparty owes the to meet the Agency's share of decommissioning. end of each period to reflect the passage of time Agency, which creates repayment risk for the Estimates of the future costs of decommis and changes inthe estimated future cash flows Agency When the fair value of a derivative sioning the units are based on the most recent underlying the obligation. Any such adjust contract is negative, the Agency owes the site specific study which was conducted in ments for changes inthe estimated future cash counterparty and, therefore, does not possess 1999. The Agency's portion of decommission flows will also be capitalized and amortized repayment risk. The Agency minimizes the ing costs, including the cost of decommission over the remaining life of the asset. Manage credit or repayment risk by entering into ing plant components not subject to radioactive ment is currently evaluating what impact, if any, transactions with high-quality counterparties. contamination, is $355,690,000, stated in1999 SFAS No 143 will have on the Agency's Market risk is the adverse effect on the dollars. financial statements.

value of financial instruments that results from a The Decommissioning Trust is irrevocable InAugust 2001, the FASB issued SFAS change ininterest rates The market nsk and funds may be withdrawn from the trust No 144, "Accounting for the Impairment or associated with interest-rate contracts is solely for the purpose of paying the Agency's Disposal of Long-Lived Assets" (SFAS No.

managed by establishing and monitonng share of the costs of nuclear decommissioning 144) Effective for fiscal year 2002, SFAS No parameters that limit the types and degree of Under the NRC regulations, the Decommission 144 addresses financial accounting and market risk that may be undertaken. ing Trust is required to be segregated from reporting for the impairment or disposal of long Agency assets and outside the Agency's lived assets and supersedes SFAS No. 121, Decommissioning Costs administrative control. The Agency is deemed to "Accounting for the Impairment of Long-Lived U S.Nuclear Regulatory Commission have incurred and paid decommissionig costs Assets and for Long-Lived Assets to Be (NRC) regulations require that each licensee of a as deposits are made to the Decommissioning Disposed Of'. SFAS No. 144 states the required commercial nuclear power reactor furmish to the Trust. In addition to the Decommissioning accounting for disposing of long-lived assets NRC certification of its financial capability to Trust certain reserve assets are anticipated to be whether previously held and used or newly meet the costs of nuclear decommissioning at available to satisfy the Agency's total decom acquired, and broadens the presentation of the end of the useful life of the licensee's facility. missioning liability discontinued operations to include more As a co-licensee of Catawba Unit 2, the Agency disposal transactions. The implementation of is subject to these requirements and therefore Recently Issued Pronouncements SFAS No. 144 is expected to have no material has furmshed certification of its financial In June 2001, the Financial Accounting impact on the Agency's financial position or capability to fund its share of the costs of nuclear Standards Board (FASB) issued SFAS No. 143, results of operations.

decommissioning of the Catawba Station. "Accounting for Asset Retirement Obligations" 2001 Annual Report 1 29

->1(conf' ed)

Nuclear Relicensing In lieu of a franchise or prix ilege tax, the States (U S ),2) obligations of any agency of In June 2001, Duke filed an applicafion Agency pays to North Carolina an amount the U S or corporation wholly owned by the with the NRC to renew the operating license equal to 3 22% of the gross receipts fmm sales U S , 3) direct and general obligations of the for the Cataxsba units. of eleetnctty to participants Electric utility State of North Carolina or any political property is located in South Carolina and subdivision thereof %N hose secunties are rated Deferred Costs subject to South Carolina property tax An "-A' or better, 4) repurchase agreements %% ith Unamortized debt issuance costs, shown electric power excise tax equal to 05% (5/10 the Bond Fund Trustee, Construction Fund net of accumulated amortization of mill) for each kilowatt-hour of electrc power Trustee, or any govemment bond dealer

$13,205,000 and $11,161,000 at December 3 1, sold for resale within South Carolina is also reporting to the Federal Reserve Bank of New 2001 and 2000, respectiely, are being paid York xshIch mature Nx ithin nine months from amortized on the interest method over the term the date they were entered into and are of the related debt. Costs of advance refundings Statements of Cash Flows collateralized by preN iously descnbed of debt, shown net of accumulated For purposes of the statements of cash obligations, and 5)bank time deposits amortization of $178,597,000 and flows, operating cash consists of unrestricted evidenced by certificates of deposit and

$155,630,000 at December 31, 2001 and 2000, cash included in the line item on the balance bankers' acceptances.

respectively, are deferred and amortized over sheets "operating assets funds invested" Bank time deposits may only be in the term of the debt issued on refunding. banks N% ith capital stock, surplus, and Deferred revenues and costs to be recovered Use of Estimates undix ided profits of $20 000,000 or from future billings to participants aam not The preparation of financial statements in $50,000,000 for North Carolina banks and amortized but Aill be either refunded to or conformity with GAAP requires management out-of-state banks, respectively, and the recoN ered from participants through future to make estimates and assumptions that affect Agency's investments deposited in such rates (See Note D) the reported amount of assets and liabilities banks cannot exceed 50% and 25%,

and disclosures of contingent assets and respectively, of such banks' capital stock, Discounts on Bonds liabilities at the date of the financial statements surplus, and undivided profits Discounts (net of premiums) on bonds, and the reported amounts of revenues and The resolution permits the Agency to shown net of accumulated amortization of expenses dunng the reporting period- Actual establish official depositones xith any bank

$46,888,000 and $41,189,000, at December results could differ from those estimates or trust company qualified under the laws of 31, 2001 and 2000 respectively, are amortized North Carolina to receive deposits of public over the tenns of the related bonds in a manner Reclassifications moneys and ha\ ing capital stock, surplus, and which yields a constant rate of interest Certain 2000 amounts hax e been undivided profits inexcess of $20,000,000 reclassified to conform with 2001 All depositories must collateralize Taxes classifications The reclassifications had no public deposits inexcess of federal depository Income of the Agency is excludable from effect on excess of revenues over expenses or insurance coverage The Agency's deposito federal income tax under Section 115 of the retained earnings as previously reported nes use the pooling method, a single financial Internal Rex enue Code. Chapter 159B of the institution collateral pool. Under the pooling General Statutes of North Carolina exempts the C. INVESTMENTS method, a depository establishes a single Agency from property and franchise or other escrow account on behalf of all governmental pnvilege taxes In lieu of North Carolina The resolution authonzes the Agency to agencies. Collateral is maintained with an property taxes, the Agency pays an amount invest in 1)direct obligations of, or obligations eligible escrow agent inthe name of the State

%x hich would otherx ise be assessed on the non of mhich the principal and interest are Treasurer of North Carolina based on an utility property and equipment of the Agency unconditionally guaranteed by the United approx ed averaging method for demand 30 2001 Annual Repod

RaJQ (continued) deposits and the actual current balance for time of under-collateralization At December 31, securities are held by the broker or dealer, or by deposits less the applicable federal depository 2001 and 2000 the Agency had $6,000 and its trust department or agent inthe Agency's insurance for each depositor. Responsibility for $100,000, respectively, covered by federal name. Category 3 includes uninsured and sufficient collateralization of these excess depository insurance. unregistered investments for which the deposits rests with the financial institutions that The Agency's investments are securities are held by the broker or dealer, or by have chosen the pooling method. Because of categorized to give an indication of the level of its safekeeping department or agent, but not in the mabihty to measure the exact amount of nsk assumed by the Agency at year-end the Agency's name. All investments, except collateral pledged for the Agency under the Category 1includes investments that are repurchase agreements, are considered pooling method, the potential exists for under insured or registered or for which the securities Category 1. Repurchase agreements are collateralization. However, the State Treasurer are held by the Agency or its agent in the considered Category 3.The Agency's enforces strict standards for each pooling Agency's name. Category 2 includes uninsured investments are detailed in the chart below.

method depository, which minimizes any risk and unregistered investments for which the Investments ($O00s) December31, 2001 December 31, 2000 Cost Basis Market Value CostBasis Market Value

"*Repurchase agreements $243,387 $243,387 $ 226,083 $226,083

"*U.S. government securities 4,992 5,175 10,371 10,469

"*U.S. government agencies 461,644 468,661 425,613 425,718

"*Municipal bonds 26,313 27,492 26,220 27,241

"*Collateralized mortgage obligations 74,861 75,948 149,480 150,251 811,197 820,663 837,767 839,762

"*Decommissioning Trust securities 117,544 128,263 103,588 119,757

"*Operating cash 5 5 1 1

"*Restricted cash 1 1 204 204

"*Accrued interest 6,903 6,903 6,764 6,764

"*Total funds invested $935,650 $955,835 $ 948,324 $ 966,488 Consisting of:

"*Special funds invested $341,078 $336,918

"*Decommissioning Trust 128,263 119,769

"*Operating assets 486,494 509,801

$955,835 $ 966,488 In accordancewith the provisionsof the resolution,the collateralunder the repurchaseagreementsis segregatedandheld by the trusteefor theAgency 2001 Annual Report 1 31

-5

.1 Costs to be Recovered from Year Ended December 31, Inception to December31, Future Billings to Participants ($O00s) 2001 2000 2001 2000

"*Net deferred interest $ (161) $ (741) $153,689 $153,850

"*Amortization of debt discount and issuance costs 7,743 7,583 88,782 81,039

"*Depreciation 50,069 51,233 727,129 677,060

"*Amortization of debt refunding costs 22,967 23,606 243,627 220,660

"*Participant billing offsets (57,639) (56,213) (748,187) (690,548)

"*Increase in fair value of investments and denvative financial instruments (14,173) (35,406) (32,336) (18,163)

"*Training costs 6,696 6,696

$ 8,806 $ (9,938) $439,400 $ 430,594 Deferred Revenues ($O00s)

"*Net special funds (withdrawals)/deposits $(44,977) $(53,044) $103,431 $148,408

"*Restricted investment income 19,364 21,317 357,188 337,824

"*Rate stabilization funds used for other than operations (121,840) (121,840)

"*Special funds excess valuations (2,946) (2,946)

$(25,613) $(31,727) $355,833 $ 361,446 Net Costs to be Recovered from Future Billings to Participants ($O00s) $34,419 $21,789 D. COSTS TO BE RECOVERED FROM available for operations The differences Supplemental Reserve Account, are sufficient FUTURE BILLINGS TO PARTICIPANTS between debt principal maturities (adjusted for to recover all of the Agency's current annual AND DEFERRED REVENUES the effects of premiums, discounts, and costs of the participants' bulk poNser needs.

amortization of deferred gains and losses) and Each participant is required under the power Rates for power billings to participants straght-line depreciation and amortization and sales agreements to set its rates for its are designed to cover the Agency's debt interest income recognition are recogmzed as customers at le%els sufficient to pay all its costs requirements, operating funds, and reserves as costs to be recovered from future billings to of its electric utility system, including the specified by the resolution and power sales participants. Funds collected through rates for Agency's charges for bulk power supply. All agreements Straight-line depreciation and reserve accounts and restricted investment participants have done so amortization are not considered inthe cost of income are recognized as deferred revenues. In a deregulated electric utility industry, service calculation used to design rates In The Agency's present charges to the the participants can expect to have as their addition, certain earnings on bond resolution participants, together with planned withdrawals major competition the investor-owned utilities funds are restrcted to those funds and not from the Rate Stabilization Fund and (IOUs) and rural electnc cooperatives presently 32 2001 AnnuA ReIoo

R5@Qa (continued) operating inNorth Carolina and power annual basis and are reviewed quarterly. If they This statement also imposes stricter criteria for marketers and others that begin serving North are determined to be inadequate to cover the regulatory assets by requiring that such assets Carolina retail customers after deregulation The Agency's current annual costs, rates may be be probable of future recovery at each balance participants' retail electric rates are higher, on revised. sheet date. Upon adoption, and to date, SIAS average, than the retail electric rates of the IOUs The recovery of outstanding amounts No. 121 has had no effect on the Agency's currently serving North Carolina. associated with costs to be recovered from financial position See discussions of SFAS Agency studies indicate that ina market future billings to participants will coincide with No. 144 at Note B,Recently Issued Pronounce environment, the participants may not be able to the retirement of the outstanding long-term ments.

charge rates sufficient to meet their obligations debt of the Agency barring a change in to the Agency as well as cover the costs of their regulation. A change in regulation could E. BONDS distribution systems This would give rise to directly affect the recoverabihty of these costs, stranded investments of the Agency and the resulting inimpairment of these assets and The Agency has been authorized to issue need for stranded investment recovery in a reexamination of these assets in accordance Catawba Electric Revenue Bonds (bonds) in deregulated environment The Agency expects with SFAS No 121, "Accounting for the accordance with the terms, conditions, and that the methods by which it will recover some Impairment of Long-Lived Assets and for limitations of the resolution. The total to be or all of its stranded investments will come from Long-Lived Assets to Be Disposed Of' (SPAS issued is to be sufficient to pay the costs of the legislative initiatives discussed in Note A. No 121). The Agency follows the accounting acquisition and construction of the project, as However, no assurances can be given that the requirements of SFAS No. 121. This statement defined, and/or for other purposes set forth in Agency will be able to recover, in pail or m requires the long-lived assets be reviewed for the resolution. Future reftindlngs may result in whole, these stranded investments. impairment whenever events or changes in the issuance of additional bonds All rates must be approved by the Board of circumstances indicate that the carrying The following shows bond activity during Commissioners Rates are designed on an amount of an asset may not be recoverable 2001.

• Bonds Outstanding at December 31,2000 $ 2,271,884,000

• Principal payments January 1,2001 (59,448,000)

• Bonds Outstanding at December 31, 2001 $ 2,212,436,000 The various issues comprising the outstanding debt are asfollows (in thousands of dollars)"

December31, 2001 2000

"*Series 1985B 6% matunng in 2020 with annual sinking fund requirements beginning in 2018 $80,575 $80,575

"*Series 1988 Zero coupon priced to yield 7.5% to 7.6% maturing annually from 2002 to 2003 5,526 8,289

"*Series 1990 4,515 5,680 6.8% to 6.9% maturing annually from 2002 to 2003 Zero coupon priced to yield 6 75% maturing in 2004 3,670 3,670 7% maturing in 2014 10,225 10,225 18,410 19,575 2001 Anual Report 33

v~(continuLed)

December 31, 2001 2000

" Series 1992 5 75% to 8% maturing annually from 2002 to 2011 $ 383,385 $ 421,350 Zero coupon pnced to yield 6 55% to 6 7% maturing annually from 2008 to 2012 100,000 100,000 5.75% maturing in 2015 with annual sinking fund requirements beginning in 2013 191,030 191,030 6 25% maturing in 2017 with annual sinking fund requirements beginning in 2016 86,610 86,610 6 2% matunng in 2018 83,540 83,540 5 75% matunng in 2020 with annual sinking fund requirements beginning in 2019 123,990 123,990 6% Indexed Caps Bonds matunng in 2012 65,300 65,300 1,033,855 1,071,820 "Series1993 4 1% to 5 5% matunng annually from 2002 to 2010 165,020 179,550 PARS/INFLOS matunng in 2012 with annual sinking fund requirements beginning in 2011 with linked interest rate of 5 5% 54,800 54,800 5% matunng in 2015 with annual sinking fund requirements beginning in 2013 103,050 103,050 5% matunng in 2018 with annual sinking fund requirements beginning 2016 91,680 91,680 PARS/INFLOS matunng in 2020 with annual sinking fund requirements beginning in 2018 Nth linked interest rate of 5 6% 70,000 70,000 484,550 499,080

"* Series 1995A 5 1% to 5 2% matunng annually from 2007 to 2008 15,185 15,185 5.375% matunng in 2020 with annual sinking fund requirements beginning in 2019 64,255 64,255 79,440 79,440

"* Series 1997A Redeemed 2,805 5% to 5 125% matunng annually from 2009 to 2011 21,115 21,115 5 125% matunng in 2015 with a sinking fund requirement in 2012 19.235 19,235 5 125% matunng in 2017 with annual sinking fund requirements beginning in 2016 57,425 57,425 97,775 100,580

" Series 1998A 4.5% to 5.5% maturing annually from 2002 to 2015 33,150 33,370 5.125% maturing in 2017 with annual sinking fund requirements beginning in 2016 49,810 49,810 5% matunng in 2020 with annual sinking fund requirements beginning in 2018 45,405 45,405 128,365 128,585 34 2001 Annual Reoorl

Mato (continued)

December31, 2001 2000

• Series 1999A 5.75% to 6% maturing annually from 2007 to 2010 $ 83,340 $ 83,340

• Series 1999B 6.125% to 6 625% maturing annually from 2006 to 2010 54,035 54,035 6.375% maturing in 2013 with annual sinking fund requirements beginning in 2011 33,585 33,585 6.5% maturing in 2020 with annual sinking fund requirements beginning in 2014 112,980 112,980 200,600 200,600 2,212,436 2,271,884 Less: Current matunties of bonds 59,508 59,448 Unamortized discount 101,002 106,701

$2,051,926 $2,105,735 The table on page 36 is a sunimary of debt (subsequently paid at maturity or refunded), bonds are no longer considered outstanding service requirements for bonds outstanding at 1985B, 1988,1990, 1992, 1993, 1995A, obligations of the Agency.

December 31, 2001 and reflects principal debt 1997A, 1998A, and 1999A bonds were used Interest on the bonds is payable semi service included in the designated year's rates. In to establish trusts for advance refunding of annually. Certain of the following bonds are accordance with the resolution, these moneys $3,417,280,000 of previously issued bonds At subject to redemption pnor to maturity at the are deposited into the Bond Fund for payment of December 31, 2001, $3,137,470,000 of these option of the Agency, on or after the following the following year's current maturities. Current bonds have been redeemed. Under these dates at a maximum of 102% of the respective maturities of $59,508,000 at December 31, 2001 Refunding Trust Agreements, obligations of, principal amounts:

were collected through rates dunng 2001 and or guaranteed by, the United States have been deposited monthly into the Bond Fund to make placed in irrevocable Refunding Trust Funds Series 1985B January 1, 1996 the January 1,2002 principal payment. maintained by the Bond Fund Trustee. The Series 1990 January 1, 2000 The fair market value of the Agency's government obligations in the respective Series 1992 and 1993 January 1, 2003 long-tenm debt was estimated using a yield Refunding Trust Funds along with the interest Series 1995A January 1, 2006 curve derived from December 31, 2001 and earnings on such obligations, will be sufficient Series 1997A January 1, 2007 2000 market prices for similar securities Using to pay all interest on the refunded bonds when Series 1998A January 1, 2008 these yield curves, market pnces were estimated due and to redeem all refunded bonds at Series 1999B January 1, 2010 to call date, to par call date, and to maturity. The various dates prior to their original maturities, lowest of the three prices was used as the in amounts ranging from par to a maximum The bonds are special obligations of the estimated market price for each individual redemption price of 102%. The monies on Agency, payable solely from and secured maturity and the individual maturities were deposit ineach Refunding Trust Fund, solely by (1)project revenues (as defined by summed to arrive at a fair market value of including the interest earnings thereon, are the resolution) after payment of project

$2,249,935,000 and $2,288,589,000 at pledged solely for the benefit of the holders of operating expenses (as defined by the December 31, 2001 and 2000, respectively. the refunded bonds Since the establishment of resolution) and (2) other monies and securities Certain proceeds of the Series 1984 each Refunding Trust Fund, the refunded pledged for payment thereof by the resolution 2001 Annual Report 1 35

I )! Ii The resolution requires the Agency to Debt Service Deposit Requirements for Bonds (SO00s) deposit into special funds all proceeds of bonds issued and all project revenues (as defined by the resolution) generated as a result of the Year Principal Interest* Total Project Power Sales Agreements and Interconnection Agreement The purpose of the

• 2002 $ 64,323 $ 115,419 $ 179,742 individual funds is specifically defined in the resolution

• 2003 68,280 111,917 180,197 F. COMMITMENTS AND

• 2004 70,665 108,211 178,876 CONTINGENCIES

• 2005 87,135 104,285 191,420 ElectriCities

• 2006 93,075 98,483 191,558 The Agency has a contractual agreement

• 2007 98,205 92,648 190,853 with ElectnCities %x hereby ElectnCities provides, at cost, general management sen ices

• 2008 102,565 88,509 191,074 to the Agency This agreement continues

• 2009 through December 31 2004, and is automati 107,195 86,664 193,859 cally renewed for successive three-year penods

• 2010 112,500 81,834 194,334 unless temuinated by one year's notice by either party pnor to the end of the contract temi

• 2011 118,520 76,051 194,571 For the years ended December 31, 2001

• 2012 125,165 69,795 194,960 and 2000, the Agency paid ElectnCities

$4,867,000 and $4,801,000, respectively

• 2013 132,460 62,762 195,222 Insurance

• 2014 139,775 55,208 194,983 The Price-Anderson Act limits the public

• 2015 148,210 47,466 195,676 liability for a nuclear incident at a nuclear genera unit to S9540,000,000, xxhich

• 2016 156,655 39,039 195,694 anlount is to be covered by private insurance

• 2017 165,880 30,569 196,449 and agreements of indemnity with the NRC.

Such pnvate insurance and agreements of

• 2018 176,010 20,598 196,608 indemnity are carried by Duke on behalf of all co-oNN nets of the station The temis of this

• 2019 186,310 10,302 196,612 coverage require the ow ners of all licensed facilities to prox ide up to $88,100,000 per year Total $2,152,928 $1,299,760 $3,452,688 per unit owned (adjusted annually for inflation) in the ex ent of any nuclear incident invok ing

• Assumes a 4 97% interest ratefor the 1999B SWAP any licensed facility in the nation, x iLthan annual maximum assessment of $10,000,000 36 2C01 Anrual Report

Ra e(continued) per unit owned. If any such payments are required, the Agency would be hable for 37.5%

of those payments applicable to the station.

Property damage insurance coverage presently available for the station has a maximum benefit limited to $2,750,000,000.

Such available coverage has been obtained.

Catawba License Extension Project In 1999, Duke requested approval of the expenditure of funds for a capital addition relating to Duke's seeking an extension of the NRC operating license for the Catawba Station. The Agency questioned the appropriateness of allocating any portion of the costs to the Agency inlight of uncertainty regarding the potential effect of electnc industry restructuring legislation which might be enacted Thus, the Agency disapproved the capital project inaccordance with Section 2.2(F) of the Restated Operation and Fuel Agreements between Duke and the Agency On January 11, 2002, the Board approved the capital project and authorized Duke to bill the Agency its proportionate share plus interest On March 1,2002, the Agency was billed

$1,947,000 for its proportionate share of these costs through December 31,2001. Such amount is reflected in CWIP and accounts payable at December 31, 2001.

At December 31, 2000, the Agency's unbilled proportionate share of this capital addition was $480,000, plus interest G. OTHER REVENUES Other revenues include $333,000 and

$6,497,000 in2001 and 2000, respectively, which were received from Duke in settlement of arbitration issues.

2001 Annual Report 1 37

(I> NI \( \

K9K 'j f 1y In Assets of Funds Invested (SO00s)

Funds Ini ested Po*i er Jan 1, Billing Inve*izent 2000 Receipts Income D sbu sements Bond Fund Interest account $ 55,537 $ 0 $1,894 $(119,925)

Reserve account 194,896 12,450 Pnncipal account 55,417 1,845 (55,138) 305,850 0 16,189 (175,063)

• Resewne & Contingency Fund 20,390 2,154

• Special Reserve Fund 1,082 68

• Revenue Fund:

Revenue account 26,830 220,533 417 3,081 Rate stabilization account 268,974 14,351 295,804 220,533 14,768 3,081 Operating Fund Working capital account 19,876 5,972 (165.639)

Fuel account 89,576 109,452 0 5,972 (165,639)

Supplemental Fund:

Supplemental account 38,280 40,518 2,496 (11,955)

Supplemental reserxe account 113,781 6,965 152,061 40,518 9,461 (11,955)

$884,639 $261,051 $48,612 $(349,576)

Note. 7he v(hedule above hav been prepared in a(ordance nith the underlmg Bond Rewohltion, and accordmngh, does not reflect the dhange in the fair lalue of hn estmentl av of December31, 2001 and 2000, revpectvelv See a compan ing independent Audttorv' Report 38 2001 Anqial Report

Schedules of @farng In Assets of Funds Invested (S000s)

Funds Funds Invested Power Invested Dec. 31, Billing Investment Dec. 31, Transfers 2000 Receipts Income Disbursements Transfers 2001

$125,090 $ 62596 $ 0 $ 968 $(123,043) $120,349 $ 60,870 (11,320) 196,026 12,227 (11,195) 197,058 57,659 59,783 911 (59,448) 58,369 59,615 171,429 318,405 0 14,106 (182,491) 167523 317,543 (5,585) 16,959 1,906 895 19,760 (107) 1,043 57 1,100 (253,341) (2,480) 230,849 559 28,921 (226,638) 31,211 (31,810) 251515 12,741 (46,680) 217,576 (285,151) 249,035 230,849 13,300 28,921 (273,318) 248,787 178,189 38,398 4,991 (158,690) 147,257 31,956 (18,990 70586 (12,442) 58,144 159,199 108,984 0 4,991 (158,690) 134,815 90,100 (34,667) 34,672 31,085 1,478 (18,754) (21,618) 26,863 (5,118) 115,628 6,622 (8,297) 113,953 (39,785) 150,300 31,085 8,100 (18,754) (29,915) 140,816

$ 0 $844,726 $261,934 $42,460 $(331,014) $ 0 $818,106 Note: The schedule above hasbeen preparedin accordancewith the underlying Bond Resolution, and accordingly,does not reflect the change in the fair value of investments as of December31, 2001 and 2000, respectively See accompanying Independent Auditors' Report 2001 Annual Report 1 39

0_ý __A r

¶ I 1'_'JiF2 7,) '1 3/4, j ' I.,

Per Bond Resolution and Other Agreements (SOOOs)

Year Ended December31, 2001 Year Ended December31, 2000 Project Sipplemental Total Ptvje t Supplemental Total Revenues:

Sales of electncity to participants $ 228,752 $ 32,311 $ 261,063 $ 230,130 $ 31,791 $ 261,921 Sales of electricity to utilities 62,616 62,616 55,759 55,759 Other revenues 661 114 775 7,210 56 7,266 Rate stabilization fund withdrawal 36,679 36,679 45,850 45,850 Fund valuations 14,210 14,210 14,681 14,681 Supplemental Reserve Fund withdrawal 8,298 8,298 7,194 7,194 Investment revenue available for operations 21,562 1.536 23,098 24,732 2,563 27,295 364,480 42,259 406,739 378,362 41.604 419,966 Expenses:

Operation and maintenance 76,708 76,708 83,348 83,348 Nuclear fuel 16,505 16,505 17,286 17,286 Interconnection services Purchased pomer 24,577 25,189 49,766 24,271 21,459 45,730 Transmission and distribution 11,225 11,225 14,109 14,109 Other 113 113 134 134 24,577 36,527 61,104 24,271 35,702 59,973 Administrati e and general - Duke 21,676 21,676 22,367 22,367 Administrative and general -Agency 3,341 3,644 6,985 3,762 3,907 7,669 Miscellaneous Agency expense 923 923 815 815 Gross receipts and excise taxes 10,183 1,004 11,187 9,937 1,031 10,968 Property tax 12,518 12,518 12,920 12,920 Debt service 176,631 161 176,792 183,025 149 183,174 Special funds deposits:

Decommissioning fund 4,233 4,233 4,238 4,238 Reserve and contingency fund 18,108 18,108 17,208 17,208 22,341 22,341 21,446 21,446 364,480 42,259 406,739 378,362 41,604 419,966 Excess of Revenues O er Expenses $ 0 $ 0 $ 0 $ 0 $ 0 $ 0 Note The vcheduie above has been preparedin accomdamue wtth the undelhying Bond Re sohmon, and a(i ordingl; does not meflet tIhe Uhange in the fair ahtme of mnvesuneti* as of De ember31, 2001 and2000, respettively See ticc omnipa ing Independent Anmhtors 'Report 40 20C1 Annual Repcri

Statistical enYtnce Nte Ten Years at a Glance (Unaudited) 2001 2000 1999 1998 1997

"*Megawatt-hour Sales (MWh) 4,638,350 4,749,523 4,567,636 4,496,603 4,223,699 894,324 882,083 842,892 853,384

"*Peak Billing Demand (kW) 856,577

"*Operating Revenues $324,454,000 $324,946,000 $347,476,000 $361,131,000 $367,130,000

"*Excess of Revenues

$o $0 $0 $0 $0 over Expenditures

"*Sales to Utilities (Revenues) $62,616,000 $55,759,000 $85,097,000 $102,551,000 $119,698,000

"*Average Monthly Power 386,529 395,794 380,636 374,717 351,975 Purchases by Cities (MWh)

• Average Monthly

$21,755,000 $21,827,000 $21,734,000 $21,439,000 $20,514,000 Billings to Cities 1996 1995 1994 1993 1992 4,221,890 4,125,029 3,950,370 3,976,104 3,757,172

"*Megawatt-hour Sales (MWh)

"*Peak Billing Demand (kW) 829,245 803,615 752,717 788,060 740,847

$375,577,000 $413,852,000 $540,695,000* $443,511,000 $418,234,000

• Operating Revenues

"*Excess (Deficiency) of

$0 $0 $0 $3,121,000 $(5,799,000)

Revenues over Expenditures

$183,554,000 $237,153,000 $238,954,000 $234,625,000

"*Sales to Utihties (Revenues) $134,453,000

"*Average Monthly Power 351,824 343,752 329,198 331,342 313,098 Purchases by Cities (MWh)

• Average Monthly Billings to Cities $19,942,000 $19,077,000 $17,711,000 $17,046,000 $15,301,000

• Includes $91,005,000 received in settlement of arbitrationissues.

2001 Annual Report 141 I

U k'i I I I I I I I ro I le

20 Yeta.:rs of "I2_:i~v Chairman Letter to Stakeholders o01 might be described as a quiet year for North Carolina's electric utilities After so many years of studying deregulation, the issue was no longer our focus The Study Commission on the Future of Electric Service (SCFES) held only one meeting in 2001 and they decided to delay the proposed start date of deregulation But 2001 was no time to sit idle Our So as you can see, deregulation may cities continued the business of providing have been put on hold in 2001, but our electricity and, as always, we made our business was not Now we face more scheduled debt payment on time and in full challenges We must continue our efforts to NCEMPA was also hard at %Norksecuring a reduce costs and be more efficient to lessen contract for our supplemental power supply the impact of any possible future rate Frederick E. Turnage After going over more than 20 proposals increases We must continually improve and Mayor, Rocky Mount xxith a fine-tooth comb, Ae determined upgrade our systems and keep them in top Chairman, NCEMPA CP&L provided the best opportunity and running order. Past hurricanes hae proven arrangements for our cities. This was a how important that is significant accomplishment as this contract 2001 marked 20 years since our power represents nearly 30 percent of our total agency officially became knoxs n as North energy needs through 2006 Carolina Eastern Municipal Power Agency Our cities Nsere also keeping a close (NCEMPA) It also marks 20 years that eye on proposed clean air legislation Any NCEMPA has supplied all requirements such plan N% ould likely require capital power to all 32 participant cities. Initially, improvements to our coal generating plants. the eastern cities "ere split into two separate We shepherded through privacy legislation power agencies Our coming together back that Awould ensure our customers' sensitive in 1981 made us stronger Today we remain billing information would not get in the united in our efforts to provide electricity to wrong hands We worked to see that our the citizens that call our communities home customers' needs were met and that our and to the businesses that help fuel our distrnbution systems were running well and economy Local control and local operation efficiently of our own electric systems is a positive selling point and with a strong and unified group ot electric cities, it always %ill be.

44 2001 Airuai Report

NCEMPA LsadaNOTEo 2001 Board of Commissioners

• 2001 Officers Mark S. Williams Anne-Marie Frederick E.

Vice-Chairman Knighton Tumage Town Manager, Secretary-Treasurer Chairman Wake Forest Town Manager, Edenton Mayor, Rocky Mount Commissioners and Alternate Commissioners Alternate commissioner'snames appearinitafics

- Farnmille - Hookerton

• New Bern - Smithfield

• Apex Mr Ralph E Puckett Mr PeterT Connet Mr Richard N Hicks Mr R. Scott Spence Mr. Bruce A Radford Mr Robert E Tripp, III Mr J Don Riddle FirstAlternate Vacant Mr WalterB Hartman,JrA Air J Michael Wilson

- Kinston - Pikeville - Southport

- Ayden - Fremont Mr Lyman Galloway Mr. Paul D Fisher Commiassioner Vacant Mr Ralph A.Clark Mr Edwin L Booth Mr.Donald James Mlr. Carey B Washburn FirstAlternate Vacant MayorMichael House FirstAlternate Vacant "Jim"Henry Mr Billy Harvey Air Ronald D WMcker

- Red Springs

- Belhaven - Tarboro

- Greenville - La Grange Mr John McNeil Mr Timothy M. Johnson Mr Samuel W Noble, Jr.

Mr Mike Taylor Mr T Wa7ye Home Air H Dewitt Hardison Mr Charles E, Davis Mr Andy Hughes Mr Ricky C. Page Ms Nancy M. Jenkins - Robersonville Mr James L Afford

-Benson Mr MalcolmA Green

- Laurinburg Mr John H Pritchard, Jr Mr Keith R. Langdon - Wake Forest

- Hamilton Mr Joseph R. Huffrnan Mr John DavidJenkins MayorDon H. Johnson Mr Mark S Williams Mr Herbert L. Everett MayorAnn B Slaughter

- Rocky Mount Mr Boyce C. Medhn

- Clayton MayorDonald G

- Louisburg Mayor Fredenck E. Tumage Mr. Robert J Ahlert Matthews, III - Washington Mr. C. L Gobble Mr Stephen W Raper AMr RonaldE Gurganus Mr. R. L. Willoughby

• Hertford AMsLots Brown Wheless

- Scotland Neck Mr Keith Hardt

- Edenton Mr John Christensen Air Ray Patterson Mayor Robert B Partim Ms Anne-Mane Knighton MayorJames Sidney - "*ilson

- Lumberton FirstAlternate Vacant FirstAlternate Vacant (Sid)Eley Mr Edward A. Wyatt Mr Harry L Ivey Ar William A Crunmney - Selma Mr Charles W Whitley Jr

• Hobgood Mr W. Todd Powell Commissioner Vacant Mr CharlesW Pittman,IIl

- Elizabeth City Ms Stella Daugherty Mr J Franklin Price FirstAlternate Vacant Mr Steven L Harrell Mayor Thmothy D Purvis Air Brett VanNteuvvenhutse 2001 Annual Report 143

El st System City/Town Established Revenues Customers  % Ownership

• Apex 1917 2001- $13,330,439 9,154 0706%

2000- $13,108,892

• A)den 1916 2001- $9,223,985 3,695 1 134%

2000- $8,571,413

• Belhaven 1920 2001- $2,315,095 1,139 0 409%

2000- $2,376,863

• Benson 1913 2001- $3,578,574 1,800 0577%

2000- $3,467,178

• Clayton 1913 2001- $7,786,644 4,082 0 745%

2000- $7,119,224

• Edenton 1908 2001 -Not Available 3,899 I 596%

2000 -Not Available SElizabeth City 1926 2001- $24,393,759 10,717 4 251%

2000- $23,946,844

• Fanm tile 1904 2001- $5,090,104 2,888 1 290%

2000- $5,184,798

• Fremont 1918 2001- $1,266695 869 0 306%

2000- $1 296,724

• Green ille 1905 2001 -$118,998,891 51 662 16134%

2000- $114,647,018

• Hamilton 1922 2001 - $394,580 254 078%

2000- $396,043

• Hertford 1915 2001- $2,394,564 1 271 0412%

2000- $2,051028

• ltobgood 1922 2001 - $437,477 320 0091 2000- $413,611

• Hookerton 1907 2001- $659,808 422 0155%

2000- $642,728 SKinston 1897 2001- $36,469,351 16,528 8668%

2000- $34,345,917

• La Grange 1917 2001- $2,442,179 1,524 0501%

2000- $2,310,552

• Launnburg 1925 2001- $12,807,234 5,932 2 267%

2000- $12,513,202

• Louisburg 1906 2001- $5,571,964 1,940 0858%

2000- $5,378,600

• Lumberton 1915 2001- $23,295,394 1(1,066 5 157%

2000- $24,519,476

• New Bern 1901 2001- $39,062,539 16,821 6 368%

2000- $38,403,674

• Pjkeudlle 1918 2001- $766,162 527 0 205%

2000- $807,931

• Red Springs 1910 2001- $3,322,061 1 916 0 580%

2000- $3,145,760

• Robersonville 1919 2001- $2,040,817 I 220 0 507%

2000- $2,142,427

• Rocky Mount 1902 2001- $62,597,012 29,097 16026%

2000- $61,493,313

• Scotland Neck 1903 2001- $2,907,077 1,630 0 576%

2000- $3,241,434

• Selma 1913 2001- $5,425,610 2,705 0810%

2000- $5,547,412

• Smithfield 1912 2001- $13,629,585 4,568 2 006%

2000- $12,015,061

• Southport 1916 2001- $4,241,594 2,086 0714%

2000- $3,906,268

• Tarboro 1897 2001- $22,327,554 5,797 4 743%

2000- $21,736,954

• Wake Forest 1909 2001- $9,386,534 4,900 0726%

2000- $8,649,414

• Washington 1903 2001- $23,867,256 12,384 5892%

2000- $23,329,724 SWilson 1892 2001- $93,548,632 30990 15512%

2000- $91,038,001 46 2001 An it,al Reocrt

Operational l Load Management and Power Operations Agency staff and the participants successfully controlled load during each month's peak billing period for 2001. This success translated into power cost savings of over $36 million throughout the year.

The Agency recommended load manage ment an average of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> per month, during approximately four days each month. NCEMPA participants and their customers shed an average of over 190 MW during the peak demand times each year.

Load Side Generation is an integral part of this load shedding process with over 159 MW of generation noticed as of December 2001.

2001 saw the completion of a new 230 kW substation for Lumberton, substation equipment replacement for Neighbors serving neighbors. One of the many advantages of living in a public Louisburg and the development of new power community is knowing the people who run your electric system. It means delivery points for Clayton, Greenville, and local control and fnendly service.

Wake Forest.

Agency and participant staff continued The highest monthly energy consumption Environmental Regulations to develop communication alternatives for 2001 was 720,766 MWh, which was Early in 2001 a coalition of environ for load management operations. The above the old record set in August 1999 of mental groups called upon the North participants and their customers utilize 717,270 MWh. Carolina General Assembly to take action to more than 10 different paging companies The highest Coincident Peak demand reduce air pollution from power plants. In Agency staff makes over 175,000 pages for 2001 (including SEPA) was 1,313 MW April the bill approved by the Senate, the so during August. This broke the old Coincident called "Clean Smokestacks" bill, mandated and e-mail communications through these different companies each year providing Peak record of 1,292 MW set in August 2000. pollution cuts of about 70 percent to be load management recommendations and The average Coincident Peak load factor (net implemented in two stages by 2013. The information, in addition to over 3,000 direct of SEPA) for the year was 83 percent, a slight bill calls for a 72 percent statewide telephone calls change from the 2000 average of 84 percent reduction from 1998 levels of year-round The 2001 maximum Non-Coincident nitrogen oxide (NO.) emissions, a 73 Energy and Demand Peak demand (including SEPA) was percent statewide reduction of sulfur The year's energy consumption was 1,412 MW set in August This was up from dioxide (SO2) emissions, and a 60 percent the previous all time peak of 1,394 MW set in incidental reduction of mercury. If the new 6,787,351 MWh (including SEPA) and was August 1999. Clean Smokestacks Act wins approval in the below last years total of 6,944,631 MWh.

2001 Annual Report 1 47

( ) 2 6 'i I AT-,

t 1 full General Assembly, some pollution reductions may occur, others may not.

The state of North Carolina was not alone in its legislative activity and proposed reductions of pox*er plant emissions On February 14, 2002, the Bush Administration announced the President's climate change policy, the "'Clear Skies" initiative This proposal also establishes a general frame xsoik to reduce power plant emission of NO, SO_, and mercury ox er the next 16 years and will require amending the Clean Air Act As a coal-based power plant owner, both the State and Federal proposals present significant challenges and uncertainties for NCEM PA. As part of long range planning and budgeting to achiexe environmental compliance, NCEMPA and CP&L have woiked toward anticipating regulatory requirements by installing selective catalytic reduction (SCR) technology at Roxboro Unit 4 during 2001 This first SCR installed on an electric generating plant in North Carolina involves injecting ammonia into post-combustion flu gas as a catalyst, to break doss n NO, into nitrogen and water, thereby curtailing the formation of ground level ozone SCR technology, along with recently installed low NO, burners, will minimize NO, emissions from Roxboro Unit 4 by more than 85 percent and moxe the Agency well along to meeting both State and Federal compliance deadlines Economic Development TOP Top-notch customer service is a priority and one of the many benefits of living in a public power community BOTTOM Public power crews make repairs The Eastern North Carolina cities and replace older equipment to ensure citizens and businesses have a reliable continue their successful industrial recruit ment and expansion of existing businesses source of power NCENIPA members added 1.881 new jobs in 48 200' Annjal Repao

Operational K 2001 to their communities with investments totaling $169,980,000. New load added to 110ý 4_

0 the Agency totaled more than 12 MW.

NCEMPA staff and city representatives continue to work closely with the Depart ment of Commerce and the Regional Partnerships to further the strategic load growth efforts in our communities Advertising and direct mail was focused on automotive, pharmaceutical and medical instruments, boat manufacturers/

suppliers, high technology, electronics, telecommunications, biotechnology, rubber and plastics, research and development, and software development industries. There were approximately 90 inquiries made which resulted in numerous site visits.

Marketing NCEMPA staff and city representatives continue to work closely with commercial and industrial customers to maximize the value of their energy dollars and reduce power costs Our Energy Solutions Partner (ESP) alliance partners sold 36 projects in 2001.

Our lead on-site generation partner sold 9,589 kW of new generation to NCEMPA customers Other ESP solutions include demand controllers for load management, turnkey lighting services, power quality services, and affordable training workshops.

Negotiations with CP&L In October 2001, NCEMPA selected CP&L as its supplemental power supplier.

NCEMPA's current contract with CP&L TOP' NCEMPA has 16 17% ownership in the Shearon Harris Nuclear Plant in expires December 31, 2003 This new Wake County. BOTTOM. NCEMPA has 18.33% ownership of the Brunswick contract will expire December 31, 2006 Nuclear Plant in Southport.

The Agency put out a Request for Proposals 2001 Annual Report 1 49

(r/Ka Nr,,--Ilonal VlrQ /I ,

"RetailBilling operated continuously from March 27, The Retail Billing prox iding 279 days of continuous service as program continued its of December 31, 2001 steady groxh in 2001 SBrunswick Unit I passed the mark

~ ~ Tarboro addedl13 of providing 500 days of continuous service customers and Kinston on August 6 and went on to set a new world increased its pamcipa record on October 27 for the longest continu tion by six At year ous operating run for a GE boiling water end, the program was reactor, breaking Unit 2's record of 581 days serving 139 customers set in 1996. As of December 31, 2001, the in 21 municipalities, unit had provided 647 days of continuous and anticipating the service.

addition of II new - HarrisUnit I completed its customers in Wake refueling and steam generator replacement Forest Customer outage on January 3, 2002 that began on accounts are monitored September 22 A planned power uprate was and billing data also completed during this outage, AhIch dispatched on a timely increased the generating capacity of the basis so that the cities plant by 60 MW, for a total generating can process and capacity of approximately 900 MW prepare their retail bills.

Cities who want to Security receive their billing Following the terrorist attacks on the infom~ation Nia email World Trade Center and the Pentagon on C rews in Clayton make repairs to an ele ctric line can do so, alloy ing September HI,2001, the focus shifted to Clayton's electric system was established in 1913 Today them even faster access another potential target The nation's nuclear the Johnston County town has more than 4 ,000 customers to theirdata To power plants came under scrutiny about maintain data integrity, %N hether they could withstand a terrorist in late 2000 looking for a new supplemental equipment failures are quickly detected and strike As a result of the exents on 9/11, power contract They receixed 22 bids from reported to the cities. nuclear pmoer plants across the United 15 suppliers. The Agency worked through a States have upgraded secunty measures.

short list of bidders in a lengthy process Plant Status Under the contractual arrangement with CP&L provided the best opportunity and best

• Mayo Unit 1 and Roxboro Unit 4 NCEMPA, all issues of security are handled arrangement for the eastern cities completed annual boiler inspection outages by CP&L CP&L is closely coordinating This contract means CP&L will pro%ide in the spnng of 2001 with federal, state and local authorities and additional power kkhen needs exceed the

• Brnswick Unit 2 completed a 31 has taken and continues taking appropriate capacity NCEMPA ass ns The contract day refueling outage and generator rewind steps to ensure safety and security at all the represents 25 to 30 percent of NCEMPA's on March 27, xxhich set a record for the nuclear facilities in which NCEMPA has total energy needs or roughly 1,000 MW shortest refuel outage for Unit 2 The uiit oxx nership 50 1) An~dl Re,-I

Operational Highlights NCEMPA Participant Energy Usage Forenst for 2002 is from Sept 2001 Losad Forecast 1

C l0 Jan

---

Feb Mar Apr. May June mJuly Aug Sept Oct. Nov m Attual 2090 m Actual 2001 WIE rcitq 2002 NCEMPA Participant CP Demand NOTE: At Power Agency Delivey Level - (Billing Point) including SEPA - Foricast for 2032 is firom Sept 2001 Load Forecast 9e00,* -

C" Jan Feb. Ma. Apr. May June July Aug Sept Oct. Nov Deci

- Actual 2000 SActual 2001 Forecasr 2002 NCEMPA Economic Development 2,000 1,760 $17 million less, 2000 2W1 200) 2001 2000 2001 Number of New Jobs Investments in Milions Megawaft Growth c(~Z 2001 Arqual~t r.po 1

1-773 Tfl-ý-Til Investment Portfolio Statistics Debt Outstanding NCEMPA Bonds Outstanding Earnings* Debt Outstanding 12/31 "*Senes 1985G $95,565,000 Jrif Onte Rate of Retini e tihtled -t erige "*Seies 1986A $4,495,000 Balanhe 11thresl CoVI

• 2001 $29,575,000 5 80% " Senes 1988A S28,056,026*"

• 2000 $33,538,000 629% Fixed Rate Bonds

• 2001 $3,204,444,000** 607% " Senes 1989A S83,501,778"

• 2000 $3,271,245,000** 6 12%

Market Value as of 12/31 ' " Senes 1991A $323.751,432 Vliue Aierag'e Alatunnt "*Senes 1993B $1,470-520,000 NCEMPA Bond Reconciliation

• 2001 $593,487,000 5 5 years "*Senes 1993C $274,370,000

• 2000 $646,174,000 5 2 years "* Bonds Outstanding "* Senes 1993D $78,300,000 12/31/00 $3271.245,000**

Transactions "* Senes 1995A S 14,090,000

"* Matured " Senes 1996A $252,495.000 Numntber Amount 1/1/01 66,801.000**

• 2001 633 $8,222,276,000 "*Senes 1996B $136.875,000

• 2000 752 $6,948,522,000 "* Bonds "*Senes 1997A $29,185,000 For EanwngA al Mar'tke %thluetnttit ,inchude intontefarm Outstanding andl nurkr' wtlue tifwr'urrtes held i the demnrrunrtstrrnr Intr 12/31/01 $31204,444.000** "*Senes 1999A $155,000,000

"*Senes 1999B $116,725,000

"* Senes 1999C $6,045,000

" Senes 1999D $135,470,000

• • Does not inchde $979,000an $856,000 for 2001and 2000, teVte ti ely accr ted on the baltau e sheetfor ut rent matutritiesoftie Senes 1988A CapitalAppir, rtation Bondv or

$3,634,099 and $1,148,000for 2001 a(td 2000, wypet tn elv, for the Senes 1989A Capital Appr'ciation Bonds.

52 2001 Annual Renorl

Independent Auditors' RepwuE W e have audited the accompanying balance sheets of North Carolina Eastern Municipal Power Agency as of December 31, 2001 and 2000, and the related statements of revenues and expenses and changes in retained earnings, and cash flows for the years then ended. These financial statements are the responsibility of the Agency's management. Our responsibility is to express an opinion on these financial statements based on our audits We conducted our audits in accordance reasonable basis for our opinion of forming an opinion on the basic financial with auditing standards generally accepted In our opinion, the financial statements statements taken as a whole. The in the United States of America. Those referred to above present fairly, in all supplementary information included inthe standards require that we plan and perform material respects, the financial position of Schedules of Revenues and Expenses per the audit to obtain reasonable assurance North Carolina Eastern Municipal Power Bond Resolution and Other Agreements and about whether the financial statements are Agency as of December 31, 2001 and 2000, Schedules of Changes in Assets of Funds free of material misstatement An audit and the results of its operations and its cash Invested is presented for purposes of includes examining, on a test basis, flows for the years then ended in conformity additional analysis and is not a required part evidence supporting the amounts and with accounting principles generally accepted of the basic financial statements Such disclosures in the financial statements. An in the United States of America. information has been subjected to the audit also includes assessing the accounting As discussed innote B to the financial auditing procedures applied in the audit of principles used and significant estimates statements, the Agency changed its method of the basic financial statements and, in our made by management, as well as evaluating accounting for derivative financial instruments opinion, is fairly stated in all material the overall financial statement presentation in2001. respects in relation to the basic financial We beheve that our audits provide a Our audits were made for the purpose statements taken as a whole.

Raleigh, North Carolina

• March 29, 2002 2001 Annual Report 1 53

(SOOOs)

December 31, 2001 2000 Assets

"*Electric Utility Plant (Note C)

Electric plant in service, net of accumulated depreciation of $679,007 and $629,605 S775,132 $ 788,041 Construction work in progress 9,143 20,213 Nuclear fuel, net of accumulated amortization of $38,319 and $35,612 31,424 28,587 815,699 836,841

"*Non-Utility Property and Equipment, net (Note C) 1,741 1.802

"*Special Funds Invested (Notes D and H)

Construction fund 6,304 Bond fund 371,681 378,804 Reserve and contingency fund 23.026 21,355 Decommissioning fund 4,868 4,748 Special reserve fund 1,033 1,029 400,610 412,240

"*Trust for Decommissioning Costs (Notes D and H) 93,315 86,034

"*Operating Assets Funds invested (Notes D and H)

Re%enue fund 18,474 42,154 Operating fund 46,726 49,854 Supplemental fund 37,416 60,056 102,616 152,064 Participant accounts receivable (Note E) 39,777 36,355 Fossil fuel inventory 6,009 3,831 Prepaid expenses 14,058 13,436 Derivative financial instruments (Note B) 15,681 178,141 205,686

"*Deferred Costs.

Unamortized debt issuance costs 35,957 37,851 VEPCO compensation payment (Note F) 7,773 8,162 Development costs 5,542 5,812 Costs of advance refundings of debt 420,205 454,828 Costs to be recoN ered from luture billings to participants (Note G) 1,458,594 1,468,885 1,928,071 1,975,538

$3,417,577 $3,518,141 See accompani mg noteYtofinanc tal statements.

54 2u5 Annrar Repcrt

BoEallasc Sheets (SOOOs)

December 31, 2001 2000 Liabilities and Retained Earnings

• Long-Term Debt.

Bonds, net of unamortized discount (Note H) $3,061,984 $3,119,976

"*Special Funds Liabilities: 1,821 Construction payables 1,838 64,290 68,805 Current maturities of bonds (Note H) 92,961 99,922 Accrued interest on bonds 159,089 170,548

"*Liability for Decommissioning Costs 90,589 79,350

"*Operating Liabilities:

Accounts payable 17,040 24,232 4,912 6,242 Accrued taxes 21,952 30,474

"*Deferred Revenues (Note G) 60,639 94,469

• Commitments and Contingencies (Notes J and K)

"*Retained Earnings 23,324 23,324

$3,417,577 $3,518,141 2001 Annual Report 1 55

t~~'-ets ci 1  !

And Changes in Retained Earnings ($O00s)

Year Ended December 31, 2001 2000

" Operating Revenues Sales of electricity to participants $ 424,881 $422,935 Sales of electricity to utilities 33279 33,910 458,160 456,845

" Operating Expenses:

Operation and maintenance 38,644 38,934 Fuel 36.148 39,179 Power coordination ser ices Purchased power 107,271 103,062 Transmission and distribution 14,210 16,103 Other 439 240 121,920 119,405 Administratixe and general 26,122 32,929 Amounts in lieu of taxes 3.857 3,991 Gross receipts tax 13,331 13,540 Depreciation and amortization 55.091 54,590 295,113 302,568

"*Net Operating Income 163,047 154,277

"*Interest Charges (Credits)

Interest expense 186,357 196,971 Amortization of debt refunding costs 34,622 35,821 Amortization of debt discount and issuance costs 3,557 3,514 Investment income (23,293) (23,470)

Net increase in fair value of investments and derivative financial instruments (2,755) (22,445)

Net interest capitalized (2,146) 198,488 188,245

"*Net Costs to be Recoxered From Future Billings to Participants (Note F) 23,539 33,968

"*Revenues Oxer (Under) Expenses before Cumulatie Effect of a Change in Accounting Pnnciple (11,902) 0

"*Cumulative Effect of a Change in Accounting Principle (Note B) 11,902

"*Excess of Revenues Over Expenses 0 0

"*Retained Earnings, Beginning of year 23,324 23,324

• Retained Earnings, End of year $ 23,324 $ 23,324 See accolamnin'mg notev tofinan tal statementv.

56 20C1 Annual Report

Statements of

~alseh IF@1Os)

($000s)

Year Ended December31, 2001 2000

"*Cash Flows from Operating Activities:

Receipts from sales of electricity $ 455,042 $ 454,166 (236,392) (228,120)

Payments of operating expenses 218,650 226,046 Net cash provided by operating activities

" Cash Flows from Capital and Related Financing Activities (197,663)

Interest paid (188,704)

(69) (82)

Debt discount and issuance costs paid (44,151) (24,383)

Additions to electric utility plant and non-utility property and equipment (164,242)

(68,805)

Bonds retired or redeemed 565 161 Investment earnings receipts from construction fund (310,568) (385,805)

Net cash used for capital and related financing activities

"*Cash Flows from Investing Activities: 6,892,469 8,136,174 Sales and matunties of investment securities (8,076,798) (6,758,335)

Purchases of investment securities 25,770 23,396 Investment earnings receipts from non-construction funds 159,904 82,772 Net cash provided by investing activities (146) 145

"*Net (Decrease) Increase in Operating Cash 148 3

"*Operating Cash, Beginning of year

$ 2 $ 148

"*Operating Cash, End of year See accompanying notes tofinancial statements 2001 Annual Report 1 57

St-atem-eni~s of I\

(C I' 1-1r-1 It ý I [ If _ ;_

(SOOOs)

Year Ended December 31, 2001 2000 Reconciliation of Net Operating Income to Net Cash Provided by Operating Actix ities:

Net Operating Income $163,047 S154,277 Adjustments:

Depreciation and amortization 55 091 54,590 Amortization of nuclear fuel 14,979 13,030 Changes in assets and liabilities Increase in participant accounts receivable (3,422) (2,645)

(Increase) decrease in fossil fuel stock (2,178) 1,238 Increase in prepaid expenses (622) (1,237)

Decrease in deferred costs 659 659 (Decrease) increase Inaccounts payable (7,574) 4,980 (Decrease) increase in accrued taxes (1,330) 1,154 Total Adjustments 55,603 71,769 Net Cash Pros ided by Operating Activities $218,650 $226,046 See accomJ)anvtIg notev lofinan tal tatementv.

58 2C01 An tll H[eport

R©t(Be to Financial Statements Years Ended December 31, 2001 and 2000 A. GENERAL MATTERS operation, and maintenance of the generating of initial project output. The revenues units in the initial project. Under these received relative to the initial project are North Carolina Eastern Municipal agreements, CP&L manages the construction pledged as security for bonds issued under the Power Agency (Agency) is a joint agency and operation of the generating units in resolution, after payment of initial project organized and existing pursuant to Chapter which the Agency has undivided ownership operating expenses. Each participant is 159B of the General Statutes of North interests. Both CP&L and the Agency have obligated to pay its share of operating costs Carolina to enable municipal electric the right to challenge the allocation of and debt service for the initial project. Under systems, through the organization of the charges for a period extending to April 1 of the Supplemental Power Sales Agreements, Agency, to finance, build, own, and operate the second year after which the challenged the Agency supplies each participant the generation and transmission projects The payment or adjustment was made. additional power it requires in excess of that Agency is comprised of 32 municipal During 2001, the Agency and CP&L provided by output from the initial project electric systems (participants) with interests finalized a new contract for supplemental and from SEPA.

ranging from 0.0783% to 16.1343%, which power purchases by the Agency from CP&L receive power from the Agency. from 2004 to 2006 Purchases under the new Peaking Project Delay Agreement contract will replace purchases under the In 1996, the Agency entered into an Initial Project current contract and the Peaking Project agreement with CP&L to delay the commer The initial project is comprised of the Delay Agreement discussed later. cial operation of the Agency's peaking project Agency's undivided ownership interests in The Agency also entered into agree (subsequently cancelled) until January 1, three nuclear-fueled and two coal-fired ments with CP&L and Virginia Electric and 2004. In return, CP&L will provide capacity generating units presently m commercial Power Company (VEPCO) for the transmis and energy equal to the peaking project at a operation by Carolina Power & Light sion of power to the Agency's participants. price comparable to what it would have cost Company (CP&L). The initial project is The Power Coordination Agreement (1981 to operate the peaking project during the financed under Power System Revenue PCA) obligates CP&L to purchase power delay period (June 1, 1998 to December 31, Bond Resolution No R-2-82 (resolution) from the Agency in specified percentages of 2003). As mentioned previously, the Agency adopted by the Board of Commissioners the Agency's entitlement to such power from and CP&L entered into an agreement in 2001 (board) of the Agency. The resolution Harris Unit 1 (1987-2007). for the replacement of the power provided established special funds to hold proceeds The Agency entered into two power under the Peaking Project Delay Agreement from debt issuance, such proceeds to be sales agreements with each of its participants for 2004 to 2006 used for costs of acquisition and construc for supplying the total electric power tion of the initial project and to establish and requirements of the participants in excess of ElectriCities of North Carolina, Inc.

maintain certain reserves. The resolution Southeastern Power Administration (SEPA) ElectriCities of North Carolina, Inc also established special funds into which allocations With the power generated from (ElectriCities), organized as a joint municipal initial project revenues from participants are the initial project, together with supplemental assistance Agency under the General Statutes to be deposited and from which initial purchases of power from CP&L, the Agency of North Carolina, is a public body and body project operating costs, debt service, and provides the total electric power require corporate and politic created for the purpose other specified payments are to be made. ments of its participants, exclusive of power of providing aid and assistance to municipali The Agency entered into several allotments from SEPA. Under the Initial ties in connection with their electric systems agreements with CP&L which govern the Project Power Sales Agreements, the Agency and to joint agencies, such as the Agency. The purchase, ownership, construction, sells to the participants their respective shares Agency entered into a management agree-2001 Annual Report 1 59

17 onmtimue" ment with ElectriCities Under the current retail choice no later that January 1,2006, For further discussion about deregula management agreement uith the Agency, with fifty percent of each power supplier's tion and the possible effects on rates and ElectriCities is required to prox ide all customers load ha; ing the option of retail deferred expenses,. see Note G.

personnel and personnel services necessary choice on January 1,2005 The report for the Agency to conduct its business in an indicated that the Study Commission wsould B. SIGNIFICANT ACCOUNTING economic and efficient manner then make recommendations dealing \, ith POLICIES how to address other aspects of deregulation Industry Restructuring such as stranded costs recovery, the Basis of Accounting Developments and Related Agency's debt, consumer protection, The accounts of the Agency are Uncertainties environment and alternatie energy, tax naintained on the accrual basis, inaccor Federal regulations have been passed laws, transmission and distribution, and any dance with the Uniform System of Accounts

%%hichencourage ulholesale competition other areas sshich need to be addressed. of the Federal Energy Regulatory Commis among utility and non-utility power In early 2001. the Study Commission sion, and are in conformity with accounting producers Similar regulations are determined that because of California's principles generally accepted inthe United contemplated for retail competition at both circumstances, North Carolina would take a States of America (GAAP) The Agency has the federal and state level. HoNeer, "goslow" attitude toNs ard deregulation. No adopted the principles pronmulgated by the because of other states' experiences with recommendations were made to the General Governmental Accounting Standards Board deregulation, momentum has slowned Assembly during 2001 and none are (GAS B) and Statement of Financial Account significantly in North Carolina. anticipated in 2002 ing Standard (SFAS) No. 71, "Accounting for In 1997, the North Carolina General Because the Study Commission does the Elfects of Certain Types of Regulation,"

Assembly created the "'Study Commission not intend to make any recommendations to as amended This ,,tandard allows utilities to on the Future of Electric Service in North the General Assembly during 2002, and capitalize or deter certain costs and/or Carolina" (Study Commission) The Study because the General Assembly is not bound revenues based upon the Agency's ongoing Commission is comprised of 30 members, by the w,ork ol the Study Commission, and assessment that it is probable that such items representing la%%makers, the North Carolina because other entities are able to piopose %N ill be recovered through future rex enues municipal, cooperative, and private electnc legislation on this issue, the Agency cannot In the future, issues of competitive utilities, electric consumers, the environ predict whether there %x ill be any legislative market forces and retnicturng in the electric mental community, and electric power initiatives, wx hat the results of legislative utility industry might require the reduction in marketers The Study Commission is initiatines wx ill be, or whether any such the carrying value of the Agency's regulatory charged with examining the cost, adequacy. legislation N% ill become law assets unless appropriate action is taken to availability, and pricing of electric rates and The Board of Commissioners of the assure the recoN ery of these regulatory assets, service in North Carolina to determine Agency, inconjunction With the Board ot ex en in a market en%ironment whether legislation is necessary to assure an Directors of ElectriCities of North Carolina, adequate and reliable source of electricity Inc, has developed a strategic plan to Financial Reporting and economical, fair, and equitable rates for address deregulation In addition, the Under GASB Statement No 20, all consumers of electricity in North Agency periodically reviews its regulatory "Accounting and Financial Reporting for Carolina. assets and the impact of reco\ enng such Proprietary Funds and Other Governmental After much discussion and negotia assets on Agency rates. In addition, the Entities that Use Proprietary Fund Account tions, the Study Commission presented a Agency's management and Board are ing", the Agency has adopted the option to report to the General Assembly in 2000. parutcipating in the deregulation debate. apply Financial Accounting Standards Board wshich included recommendations for full both on the national and state level (FASB) statements and interpretations that do 60 2001 Annual Heport

E%!JtR (continued) not conflict with or contradict GASB placed in the reactor, they are amortized to (NRC) approval, the Agency's spent fuel pronouncements fuel expense on the units of production storage facilities are sufficient to handle all method Nuclear fuel expense includes a spent fuel generated by all of the Agency's Electric Plant in Service provision for estimated disposal costs, which nuclear generating units through the All direct and indirect expenditures is being collected currently from participants expiration of their current operating associated with the development and Amortization of nuclear fuel costs in 2001 licenses In 1998, CP&L submitted a construction of the Agency's undivided and 2000 includes a provision of $3,434,000 license amendment application to the NRC ownership interests in five of CP&L's and $3,453,000, respectively, for estimated requesting NRC approval to activate and generating units now in commercial disposal costs. begin using the additional spent fuel storage operation, including interest expense net of The Energy Policy Act of 1992 at the Harris Plant. In December 2000, CP&L investment earnings on funds not yet established a fund for the decontamination received such permission from the NRC.

expended, have been recorded at original and decommissioning of the Department of cost (plus acquisition adjustment) and are Energy's (DOE) uranium enrichment plants. Non-Utility Property and Equipment being depreciated (or amortized) on a Nuclear plant licensees are subject to an All expenditures related to purchasing straight-line basis over the composite annual assessment for 15 years based on their and installing an in-house computer, jointly average life of each unit's assets pro rata share of past enrichment services. owned with North Carolina Municipal At December 31, 2001, the remaining CP&L makes the annual payment to DOE for Power Agency Number 1 (NCMPA 1), have composite average life for Brunswick Units 1 the Brunswick and Harris units and bills the been capitalized and are fully depreciated and 2 was 7 years, Harris Unit 1 was 22 Agency for their proportionate share. The Also included are the land and administra years, Roxboro Unit 4 was 12 years, and Agency's payments to CP&L were approxi tive office building jointly owned with Mayo Unit 1was 14 years mately $756,000 and $742,000 in 2001 and NCMPAI and used by both agencies and 2000, respectively, and were recorded as fuel ElectriCities. The administrative office Construction Work in Progress expense. building is being depreciated over 37 1/2 All expenditures associated with capital Under provisions of the Nuclear Waste years on a straight-line basis additions related to the Agency's undivided Pohcy Act of 1982, CP&L, on behalf of ownership interests in CP&L's generating CP&L and the Agency, has entered into Investments units are capitalized as construction work in contracts with the DOE for the disposal of The Agency has implemented the progress until such time as they are complete, spent nuclear fuel. The DOE failed to begin provisions of GASB Statement No. 31, at which time they are transferred to Electric accepting the spent nuclear fuel in 1998, the "Accounting and Financial Reporting for Plant in Service. No interest is capitalized on year provided by the Nuclear Waste Policy Certain Investments and for External capital additions. Depreciation expense is Act and CP&L's contract with the DOE. Investment Pools," which requires recognized on these items after they are CP&L, on behalf of all co-owners, along investments to be reported at fair value.

transferred with other utilities, have taken steps to force the DOE to take spent nuclear fuel. To date, Derivative Financial Instruments Nuclear Fuel the courts have rejected these attempts In June 1998, the Financial Accounting All expenditures related to the purchase While some utilities have filed actions for Standards Board (FASB) issued SIAS No.

and construction of the Agency's undivided damages inthe United States Court of Federal 133, "Accounting for Derivative Instru ownership interests in nuclear fuel cores at Claims, CP&L has not yet taken such action. ments and Certain Hedging Activities" the nuclear units are capitalized until such The Agency stores all spent fuel within (SFAS No 133). In June 2000, the FASB time as the cores are placed in the reactor. No its facilities. With certain modifications and issued SFAS No. 138, 'Accounting for interest is capitalized on fuel cores. When additional Nuclear Regulatory Commission Certain Denvative Instruments and Certain 2001 Annual Report 161

to (cont ýJec, A

Hedging Actie ities, an Amendment of SFAS entering into these interest rate s%%ap possess repayment risk. The Agency 133" (SFAS No. 138) SFAS No. 133 and agreements is to synthetically corn ert a minimizes the credit or repayment risk by SFAS No 138 require that all derivative portion of its fixed rate debt to variable rate entering into transactions %% ith high-quality instruments be recorded on the balance sheet debt os er the life of the swaps Under these counterpariies at their respective fair values SFAS No 133 fixed to variable interest rate swaps, Market risk is the adverse effect on the and SFAS No. 138 are effective for all fiscal NCEMPA receives a fixed rate of 4 67% salue of financial instruments that results years beginning after June 30, 2000. The and 5 03%, respectively, through the from a change i interest rates. The market Agency adopted SFAS No 133 and SFAS termination dates, Nshile paying a variable iisk associated v,ith interest-rate contracts is No 138 on January 1,2001 In accordance rate based on the BMA Municipal Ssap managed by establishing and monitoring with the transition provisions of SFAS No. Index Interest paid and receised Linder the parameters that limit the types and degree of 133, the Agency recorded a cumulative swap agreements increases and decreases, maiket risk that may be undertaken effect-adjustment of $11.902,000 in the respectively, interest expense The net effect statement of revenues and expenses to was to reduce interest expense S6,409,000 Decommissioning Costs recognize at fair value all derivatives and $2,067,000 in2001 and 2000, respec NRC regulations require that each outstanding at that date. tively The notional amount of each of these licensee ot a commercial nuclear power All derivatives are recognized on the agreements is S 155,000,000 and reactor furnish to the NRC certification of its balance sheet at their fair value estimated S136.970,000, respectively financial capability to meet the costs of based on current market pricing models The The fair value of the two interest rate nuclear decommissioning at the end of the Agency has not designated any of its swap agreement was approxinately useful life of the licensee's facility As a co derivatives as hedges Changes in the fair $15,681,000 and $11,902,000 at December licensee of Brunsssick Units 1and 2 and value of denvati se instruments are reported 31, 2001 and 2000, respectiely Current Harris Unit 1,the Agency is subject to the in current-penod revenues and expenses market pricing models were used to NRC's financial capability regulations, and For the year ended December 31. 2000, estimate the fair -,alue of the interest rate therefore has furnished certification of its prior to the adoption of SFAS No 133, the swap agreements The fluctuation in the fair financial capability to fund its share of the Agency entered into interest rate swap value of the interest rate swaps was an costs of decommissioning those units agreements For interest rate swaps, fair increase of $3,779,000 in 2001 and is To satisfy the NRC's financial capability value which would be paid or received if the included in "Increase in fair value of regulations, the Agency established an SWAP were temiinated is accrued and investments and derivative financial external trust fund (Decommissioning Trust) recognized in "net increase in fair value of instruments" in the statement of resenues pursuant to a trust agreement with a bank imestnents and denvati e financial and expenses. The Agency's certification of financial instruments" and may change as market By using densvati'e instruments, the capability requires that the Agency make interest rates change If a swap contract is Agency exposes itself to credit risk and annual deposits to the Decommissioning terminated prior to its maturity, the gain or market risk. Credit risk is the failure of the Trust xN hich, together skith the investment loss is recognized immediately. counterparty to perfonn under the terms of earnings and amounts previously on deposit The Agency has only limited involve the densvatise contract When the fair value in the trust, are anticipated to result in ment N% ith derivative financial instruments In of the derivati, e contract is positive, the sufficient funds being held inthe Decommis June of 1999 and January of 2000, the counterparty os es the Agency. x% hIch sioning Trust at the expiration of the current Agency entered into two identical interest creates repayment risk for the Agency opei ating licenses for the units (currently rate swap agreements NN ith termination dates When the fair salue of a derivative contract 2014 for Bruns%%ick Unit 2, 2016 for of June 14. 2009 and December 31, 2009, is negatise, the Agency m%es the BrunsN ck Unit 1,and 2026 for Harris respectively. The Agency's objective for counterparty and, therefore, does not Unit I) to meet the Agency's share of 62 20C1 A nual Repol

bKtQ (continued) decommissioning Estimates of the future in the period in which it incurs a legal Fossil Fuel Inventory costs of decommissioning the units are based obligation associated with the retirement of Fossil fuel inventory includes fossil fuel on the most recent site specific study which tangible long-lived assets that result from stock and EPA Clean Air Act Allowances.

was conducted in 1998 The Agency's the acquisition, construction, development Fossil fuel stock and EPA Clean Air Act portion of decommissioning costs, including and/or normal use of assets The Agency is Allowances are each stated at average cost.

the cost of decommissioning plant compo required to adopt SFAS No 143 on January nents not subject to radioactive contamina 1, 2003 The Agency will record a corre Deferred Costs tion, is $67,242,000 for Brunswick Unit 1, sponding asset which will be depreciated Deferred costs are shown net of

$67,040,000 for Brunswick Unit 2, and over the life of the asset Subsequent to the accumulated amortization Unamortized debt

$63,287,000 for Harris, all stated in 1998 initial measurement of the asset retirement issuance costs at December 31, 2001 and dollars obligation, the obligation will be adjusted at 2000, shown net of accumulated amortiza The Decommissioning Trust is the end of each period to reflect the passage tion of $12,961,000 and $11,067,000, irrevocable, and funds may be withdrawn of time and changes in the estimated future respectively, are being amortized on the from the trust solely for the purpose of cash flows underlying the obligation. Any interest method over the term of the related paying the Agency's share of the costs of such adjustments for changes in the debt. Development costs, shown net of nuclear decommissioning. Under the NRC estimated future cash flows will also be accumulated amortization of $5,825,000 and regulations, the Decommissioning Trust is capitalized and amortized over the $5,555,000 at December 31, 2001 and 2000, required to be segregated from Agency assets remaining life of the asset. Management is respectively, are being amortized on a and outside the Agency's administrative currently evaluating what impact, if any, straight-line basis over the forty-year life of control. The Agency is deemed to have SFAS No. 143 will have on the Agency's the initial project. Costs of advance incurred and paid decommissioning costs as financial statements. refundings of debt at December 31, 2001 and amounts are deposited to the Decommissioning In August 2001, the FASB issued 2000, shown net of accumulated amortiza Trust In addition to the Decommissioning SEAS No 144, "Accounting for the tion of $286,036,000 and $251,414,000, Trust, certain reserve assets are anticipated to Impairment or Disposal of Long-Lived respectively, are deferred and are amortized be available to satisfy the Agency's total Assets" (SIAS No 144). Effective for fiscal over the term of the debt issued on refund decommissioning liability year 2002, SEAS No. 144 addresses ing Costs to be recovered from future The Agency determined that it was financial accounting and reporting for the billings to participants and deferred revenues necessary to fund decommissioning costs impairment or disposal of long-lived assets are not amortized but will be either associated with the non-nuclear portion of the and supersedes SFAS No 121, 'Accounting recovered from or refunded to participants Brunswick plant which fell outside the NRC for the Impairment of Long-Lived Assets through future rates (see Note G) requirements Therefore, it also deposits to and for Long-Lived Assets to Be Disposed the Decommissioning Fund, separate from Of'. SFAS No. 144 states the required Discounts on Bonds deposits required to the Decommissioning accounting for disposing of long-lived Discounts on bonds (net of premiums)

Trust. assets whether previously held and used or at December 31, 2001 and 2000 shown net newly acquired, and broadens the presenta of accumulated amortization of $14,026,000 Recently Issued Pronouncements tion of discontinued operations to include and $12,342,000, respectively, are amortized In June 2001, the FASB issued SFAS more disposal transactions The implemen over the terms of the related bonds in a No 143, 'Accounting for Asset Retirement tation of SFAS No 144 is expected to have manner which yields a constant rate of Obligations" (SFAS No. 143). SPAS No. 143 no material impact on the Agency's interest.

requires the Agency to record the fair value financial position or results of operations of an asset retirement obligation as a liability 2001 Annual Report 1 63

©tta (continued)

Taxes nment to make estimates and assumptions for the initial project Current estimates Income of the Agency is excludable that affect the reported amounts of assets indicate the Agency's portion of these costs from income subject to federal income tax and liabilities and disclosures of contingent for 2(X)2 and 2003 will be appmximately under Section 115 ot the Internal Rexenue assets and liabilities at the date of the S34,(00.000 Code Chapter 159B of the General Statutes financial statements and the reported There %%ereno interest costs capitalized of North Carolina exempts the Agency from amounts of revenues and expenses dunng as part of the cost of initial project capital property and franchise or other pfivilege the reporting period. Actual results could additions under construction duiing 2001 and taxes In lieu of property taxes, the Agency differ from those estimates 2000 pays an amount %hich would otherwise be The Agency's agreements "xith CP&L assessed on the real and personal property of Reclassifications specify the purchase of undivided ownership the Agency. In lieu of a franchise or privilege Certain 2000 amounts hax e been interests in nuclear-fuieled and coal-fired tax, the Agency pays an amount equal to reclassified to confomi wNi th 2001 classifica generating units, whInch comprise the initial 3 22% of the gross receipts from sales of tions. The reclassifications had no effect on project, presently in commercial operation as electrcity to participants excess of revenues over expenses or detailed in the table below.

retained earnings as prex iously reported On July 1,2001, CP&L uprated Statements of Cash Flows Brunsx\ ick Unit I to 820 MW from 790 MW For purposes of the statements of cash C. ELECTRIC PLANT IN SERVICE, as a result of plant improvements The flow s, operating cash consists of unrestncted NON-UTILITY PROPERTY AND Agency's ownership entitlement increased ca,,h included in the line item on the balance EQUIPMENT, AND ACQUISITION from 144 8 MW to 150.3 MW sheets "operating assets funds mwested" AND CONSTRUCTION PROGRAM On January I. 2002, CP&L upmted Hams Unit I to 900 MW from 860 MW Use of Estimates Initial Project as a result of plant unproxements. The The preparation of financial statements The Agency has commitments to Agency's ownership entitlement increased in confonnity x ith GAAP requires manage- CP&L in connection %% ith capital additions from 139 I MW to 145 5 MW Maximum Net -- Agency Commercial Dependable Ultimate Operation Capability On nershlp Megawatts

• Coal-Fired Units Roxboro Unit 4 1980 700 MW 12.94% 90 6 MW Mayo Unit I 1983 745 16 17 1205 Total Coal-Fired Capability 211 1

• Nuclear-Fueled Units Brunswick Unit 2 1975 790 1833 1448 Brunswick Unit 1 1977 820 1833 1503 Harris Unit 1 1987 900 1617 1455 Total Nuclear-Fueled Capability 4406 Total of All Units 651.7 MW 64 2001 Annual Report

[Mateo~(continued)

The table at the right (top) shows Unit Projected Design MNDC Agency planned uprates at the Brunswick umts and Date Increase Share the Agency's increase in entitlement as a

• Brunswick Unit 1 2003 41 MW 7.5 MW result of the uprates

• Brunswick Unit 2 2004 62MW 11.3MW

• Brunswick Unit 1 2005 107 MW 19.6 MW Peaking Project

• Brunswick Unit 2 2006 105 MW 19.3 MW Interest costs of $2,147,000 were capitahzed as part of the cost of the peaking project in 2000, net of investment income on unexpended bond proceeds of $2,147,000 No interest was capitalized in 2001. December 31, Electric Plant In Service ($O00s) 2001 2000 Electric Plant in Service Original costs of major classes of the "*Land $ 14,180 $ 14,180

"* Structures and improvements 482,006 481,762 Agency's electric plant in service at

"*Reactor plant equipment 410,283 378,417 December 31, 2001 and 2000 are shown in

"*Turbo generator units 123,396 121,345 the table at the nght (middle).

"* Accessory electric equipment 174,213 173,869

"*Miscellaneous plant equipment 50,720 50,304 Non-Utility Property and Equipment

"*Other 28,026 27,792 Non-Utility Property and Equipment

"*Unclassified 171,315 169,977 original costs at December 31, 2001 and 2000 1,454,139 1,417,646 are shown in the table at the right (bottom).

"*Accumulated depreciation (679,007) (629,605)

D. INVESTMENTS

$ 775,132 $ 788,041 The resolution authorizes the Agency to invest in 1) direct obligations of, or Unclassifiedassets are in service but not yet classifiedto specific plant accounts obhgations of which the principal and interest are unconditionally guaranteed by the United States (U.S.), 2) obligations of any Agency of the U.S or corporation Non-Utility Property December 31, wholly owned by the U.S, 3) direct and and Equipment ($O00s) 2001 2000 general obligations of the State of North

"*Land $ 710 $ 710 Carolina or any political subdivision thereof

"* Structures and improvements 1,491 1,491 whose securities are rated "A" or better, 4)

"*Computer equipment 605 551 repurchase agreements with a member of the 2,806 2,752 Federal Reserve System which are

"*Accumulated depreciation (1,065) (950) collateralized by previously described obhgations, and 5) bank time deposits

$1,741 $1,802 evidenced by certificates of deposit and bankers' acceptances 2001 Annual Report 1 65

Bank time deposits may only be in moneys and has ing capital stock, surplus, State Treasurer of North Carolina based on banks ýxith capital stock, surplus, and and undivided profits aggregating in excess an approsed averaging method for demand undivided profits of $20,000.000 or of $20,000,000 deposits and the actual current balance for

$50.000,000 for North Carolina banks and All depositories must collateralize time deposits less the applicable federal out-of-state banks, respectively, and the public deposits in excess of federal depository insurance for each depositor Agency's ins estments deposited in such depository insurance coserage The Responsibility for sufficient collateralization banks cannot exceed 50% and 25%, Agency's depositories use the pooling of these excess deposits rests with the respectiely, of such banks' capital stock. method, a single financial institution financial institutions that have chosen the surplus, and undivided profits collateral pool Under the pooling method, a pooling method. Because of the inability to The resolution permits the Agency to depository establishes a single escrow measure the exact amount of collateral establish official depositories with any bank pledged for the Agency under the pooling account on behalf of all govemmental or trust company qualified under the laws of agencies Collateral is maintained with an method, the potential exists for under North Carolina to receive deposits of public eligible escrow agent in the name of the collateralization Hosseser. the State Investments ($O00s) December 31, 2001 2000 Cost Marike Cost Maiket Basis Vahle Basis Value

"*Repurchase agreements $107,148 $107,148 $259,353 $259,353

"*U S government securities 7,987 8,280 19,967 20,114

"*U S government agencies 313,771 317,511 168,068 169,739

"*Municipal bonds 39,096 39,930 18,332 19,052

"*Strips 9,232 9,064 15,304 15,280

• Collateralized mortgage obligations 17,366 18,239 76,476 76,602 494,600 500,172 557,500 560,140

"*Decommissioning Trust securities 88,311 93,315 77,080 86,034

• Operating cash 2 2 148 148

"*Restricted cash 5 5 301 301

"*Accrued interest 3,047 3,047 3,715 3,715

"*Total funds invested $585,965 $596,541 $638,744 $650,338

"*Consisting of:

Special funds invested $400,610 $412,240 Decommissioning Trust 93,315 86,034 Operating assets 102,616 152,064

$596,541 $650,338 56 2X(J1 Annual Heport

R,Qt (continued)

Treasurer enforces strict standards for each F. VEPCO COMPENSATION The Agency's present charges to the pooling method depository, which mnni PAYMENT participants, together with planned withdraw mizes any risk of under-collateralization At als from the Rate Stabilization Fund and December 31, 2001 and 2000, the Agency The VEPCO compensation payment Special Supplemental Reserve Account, are had $7,000 and $435,000, respectively, represents compensation to VEPCO for sufficient to recover all of the Agency's covered by federal depository insurance. early termination of service for those current annual costs of the participants' bulk The Agency's investments are participants previously served by VEPCO power needs Each participant is required categorized to give an indication of the level This payment of $15,515,000 and the related under the power sales agreements to set its of risk assumed by the Agency at year-end. capitahzed interest of $33,000 were deferred rates for its customers at levels sufficient to Category I includes investments that are and are being amortized on a straight-line pay all its costs of its electric utility system, insured or registered or for which the basis over 40 years, the expected life of the including the Agency's charges for bulk securities are held by the Agency or its initial project. The balance at December 31, power supply. All participants have done so.

agent in the Agency's name. Category 2 2001 and 2000 is net of accumulated In a deregulated electric utility industry, includes uninsured and unregistered amortization of $7,775,000 and $7,386,000, the participants can expect to have as their investments for which the securities are respectively. major competition the investor-owned held by the broker or dealer, or by its trust utilities (IOUs) and rural electric coopera department or agent in the Agency's name. G. COSTS TO BE RECOVERED tives presently operating in North Carolina Category 3 includes uninsured and FROM FUTURE BILLINGS TO and power marketers and others that begin unregistered investments for which the PARTICIPANTS AND DEFERRED serving North Carolina retail customers after securties are held by the broker or dealer, REVENUES deregulation The participants present retail or by its safekeeping department or agent, electric rates are higher, on average, than the but not in the Agency's name. All invest Rates for power billings to participants present retail electric rates of the IOUs ments except repurchase agreements are are designed to cover the Agency's debt currently serving North Carolina considered Category 1 Repurchase requirements, operating funds, and reserves Agency studies indicate that in a market agreements are considered Category 3. as specified by the resolution and power environment, the participants may not be The Agency's investments are detailed in sales agreements. Straight-line depreciation able to charge rates sufficient to meet their the table at the left. and amortization are not considered in the obligations to the Agency as well as cover In accordance with the provisions of cost of service calculation used to design the costs of their distribution systems. This the resolution, the collateral under the rates. In addition, certain earnings on bond would give rise to stranded investments of repurchase agreements is segregated and resolution funds are restricted to those funds the Agency and the need for stranded held by the trustee for the Agency. and not available for operations The investment recovery in a deregulated differences between debt principal maturi environment The Agency expects that the E. PARTICIPANT ACCOUNTS ties (adjusted for the effects of premiums, methods by which it will recover some or all RECEIVABLE discounts, and amortization of deferred of its stranded investments will come from At December 31,2001, there were gains and losses) and straight-line deprecia the legislative initiatives discussed in Note A

$8,532,000 of unbilled receivables tion and amortization and interest income However, no assurances can be given that the associated with the peaking project benefits recognition are recognized as costs to be Agency will be able to recover, in part or in versus peaking project participant credits. recovered from future billings to partici whole, these stranded investments This receivable will be recovered from the pants Funds collected through rates for All rates must be approved by the Board peaking project participants in 2002 and reserve accounts and restricted investment of Commissioners. Rates are designed on an 2003. income are recognized as deferred revenues. annual basis and are reviewed quarterly. If 2001 Annual Report 1 67

V a -f they are deternmned to be inadequate to Lix ed Assets and for Long-Lived Assets to H. BONDS cover the Agency's current annual costs, Be Disposed Of" This statement requires rates may be rexised the long-ived assets be re%iewed for The Agency has been authorized to The reco ery of outstanding amounts impairment N% henever events or changes in issue Po\k er System ReN enue Bonds associated %% ith costs to be recoxered from circumstances indicate that the carrying (bonds) in accordance with the terms, future billings to participants will coincide amount of an asset may not be recoxerable. conditions, and limitations of the resolution with the retirement of the outstanding long This statement also imposes stricter cntena The total to be issued is to be sufficient to term debt of the Agency barring a change in for regulatory assets by requiring that such pay the costs of acquisition and construction regulation. A change in regulation could assets be probable of future reco, cry at each of the project, as defined, and/or for other directly affect the recoverability of these balance sheet date. Upon adoption, and to purposes set forth in the resolution Future costs, resulting in impairment of these assets date, SFAS No 121 has had no effect on the refundings may result in the issuance of and reexamination of these assets in Agency's financial position. See discussions additional bonds accordance %NithSFAS No 121, of SFAS No 144 at Note B, Recentl) Ahved "Accounting for the Impairment of Long- Pronou( emuent Costs to be Recovered from Future Billings Year Ended Inception to to Participants ($O00s) December 31, December 31, 2001 2000 2001 2000

"* Deferred interest expense $ (3,465) $ 300 $ 656,319 $ 659,784

"*Amortization of debt discount and issuance costs 3,557 3,514 55,827 52,270

"* Net increase in fair value of investments and derivative financial instruments (14,657) (22,445) (26,251) (11,594)

"* Depreciation and amortization 55,091 54,589 827,251 772,428

"* Amortization of debt refunding costs 34,622 35,821 411,049 376,427

"* Participant billing offsets (85,439) (75,002) (510,955) (425,516)

"* New project negotiation and Harris Plant litigation costs 45,086 45,086

$ (10,291) $ (3,223) $1,458,594 $1,468,885 Deferred Revenues (SOOs)

"*Net special funds withdrawals $ (35,503) $(37,062) $ (135,284) $ (99,781)

"* Restricted investment income 1,673 (129) 218,334 216,661

"* Rate stabilization funds used for other than operations (21,839) (21,839)

"* Special funds valuations (572) (572)

$ (33,830) $(37,191) $ 60,639 $ 94,469 Net Costs to be Recovered From Future Billings to Participants (SO00s) $ 23,539 $ 33,968 68 2001 Anwual Retort

I H[ es! (continued)

The following chartshows bond activity during 2001.

" Bonds Outstanding at December 31, 2000 $3,273,249,000 Principal payments January 1,2001 (Includes $2,004,000 in appreciated value on the Series 1988 A and 1989 A Capital Appreciation serial bonds.) (68,805,000)

Transfer from Accrued Interest to Current Maturities of Bonds to reflect the appreciated value of the Series 1988 A and 1989 A Capital Appreciation serial bonds due January 1, 2002 4,613,000

"*Bonds Outstanding at December 31,2001 $3,209,057,000 The various issues comprisingthe outstanding debt are as follows (in thousands of dollars):

December 31, 2001 2000

" Series 1985 G 5.75% maturing in 2016 with annual sinking fund requirements beginning in 2012 $ 95,565 $ 95,565

" Series 1986 A 5% matunng in 2017 with annual sinking fund requirements beginning in 2015 4,495 4,495

" Series 1988 A 7 6% capital appreciation serial bonds maturing in 2002 1,525 1,951 6% maturing in 2026 with annual sinking fund requirements beginning in 2025 27,510 27,510 29,035 29,461

"*Series 1989 A 7.35% to 7.4% capital appreciation serial bonds maturing annually from 2002 to 2003 8,246 6,612 7.5% maturing in 2010 with annual sinking fund requirements beginning in 2009 28,890 28,890 5 5% maturing in 2011 50,000 50,000 87,136 85,502

" Series 1991 A Redeemed 3,260 7.875% maturing in 2002 14,255 14,255 6 25% maturing annually from 2003 to 2006 33,020 33,020 6.3% to 6.4% capital appreciation serial bonds maturing annually from 2004 to 2006 2,376 2,376 6 5%maturing in 2012 with annual sinking fund requirements beginning in 2007 14,910 14,910 6 5% maturing in 2017 with annual sinking fund requirements beginning in 2013 99,755 99,755 6 5% maturing in 2018 28,755 28,755 5.75% maturing in 2019 130,680 130,680 323,751 327,011 2001 Annual Report 169

December 3l, 2001 2000 Series 1993 B 5.5% to 7.25% matunng annually from 2002 to 2009 $ 391,950 $ 396,655 6.25% matunng in 2012 Nith annual sinking fund requirements beginning in 2010 247.815 247.815 6% matunng in 2013 40.345 40,345 6% ,tructured yield curve notes matunng in 2014 55550 55,550 5.5% maturing in 2017 sith annual sinking fund requirements beginning in 2015 146 625 146,625 6% maturng in 2018 97,790 97,790 5 5% maturing in 2021 ith annual sinking fund requirements beginning in 2019 194.510 194,510 6% matunng in 2022 157.740 157,740 6 25% maturing in 2023 105.210 105,210 6% matunng annually from 2025 to 2026 32,985 32,985 1,470.520 1,475,225 Series 1993 C 5% to 7% maturing annually from 2002 to 2007 195,815 225,515 7% maturng in 2013 with annual sinking fuind requirements beginning in 2010 20,965 20,965 5% matunng in 2021 with annual sinking fund requirements beginning in 2014 57,590 57,590 274,370 304,070

" Series 1993 D 5 875% maturing in 2013 % ith annual sinking fund requirements beginning in 2012 27,605 27,605 5 875% maturing in 2014 15,960 15,960 5 6% maturing in 2016 Vith annual sinking fund requirements beginning in 2015 34.735 34,735 78.300 78,300

" Series 1995 A Redeemed 2,520 5 125% matunng in 2012 14,090 14,090 14090 16,610

" Series 1996 A Redeemed 21,530 5 5% to 6% maturing annually from 2004 to 2006 105.805 105,805 5 6% maturng in 2010 1,060 1,060 5 625% to 5 7% maturing annually mrom 2012 to 2016 83,320 83,320 5 625% maturing in 2024 with annual sinking fund requirements beginning in 2017 62,310 62,310 252,495 274,025 70 2001 Awnual Repor'

H a (continued)

December 31, 2001 2000

" Series 1996 B 6% maturing in 2006 $ 12,000 $ 12,000 5 8% maturing in 2016 22,920 22,920 5 875% maturing in 2021 with annual sinking fund requirements beginning in 2020 101,955 101,955 136,875 136,875

" Series 1997 A Redeemed 840 5 375% maturing in 2024 29,185 29,185 29,185 30,025

"*Series 1999 A 5.2% maturing in 2010 5,000 5,000 5.75% maturing in 2026 with annual sinking fund requirements beginning in 2023 150,000 150,000 155,000 155,000

"*Series 1999 B 5 55% to 5 7% maturing annually from 2014 to 2017 40,035 40,035 5.75% maturng in 2024 76,690 76,690 116,725 116,725

"*Series 1999 C (Federally Taxable) 648% to 7.05% maturing annually from 2002 to 2007 6,045 7,390

"*Series 1999 D 5 45% maturing in 2004 with annual sinking fund requirements beginning in 2001 4,500 6,000 6% maturing in 2009 with annual sinking fund requirements beginning in 2005 7,470 7,470 6 45% maturing in 2014 with annual sinking fund requirements beginning in 2010 7,500 7,500 6.7% maturing in 2019 with annual sinking fund requirements beginning in 2015 35,875 35,875 6.75% maturing in 2026 with annual sinking fund requirements beginning in 2020 80,125 80,125 135,470 136,970 3,209,057 3,273,249 Less: Current maturities of bonds 64,290 68,805 Unamortized discount 82,783 84,468

$3,061,984 $3,119,976 2001 Annual Report 1 71

?+T 1

K)

It> N A

7 u,

- N Nj At left is a summary of the debt service Debt Service Deposit Requirements for Bonds ($o00s) deposit requinements for bonds outstanding at December 31, 2001. This table reflects Year Principal Interest* Total pnncipal debt service included in the designated year's rates In accordance with

• 2002 $ 78,776 $ 187,602 $ 266,378 the resolution, these moneys are deposited

• 2003 82,097 180,312 262,409 into the Bond Fund for payment of the following year's current maturities Current

• 2004 90,116 175,969 266,085 maturities of $64,290,000 at December 31,

• 2005 98,368 170,910 269,278 2001 sxere collected through rates during

• 2006 118,070 164,053 282,123 2001 and deposited monthly into the Bond

• 2007 127,100 156,327 283,427 Fund to make the January 1, 2002 principal

• 2008 133,595 147,468 281,063 payment The lair market value of the Agency's

• 2009 118,230 141,072 259,302 long termn debt was estimated using the

• 2010 133,315 135,296 268,611 Dobbins Scale The individual maturities

• 2011 140,711 127,329 268,040 ssere priced and summed to arrive at a fair

• 2012 124,728 118,659 243,387 mai ket value of $3,244,498,000 and

• 2013 142,164 111,295 253,459 $3,360,260,000 at December 31, 2001 and 2000, respecti ely.

• 2014 145,694 102,916 248,610 Certain proceeds of the Series 1985 G,

• 2015 148,180 94,610 242,790 1986A, 1988 A, 1989 A, 1991 A, 1993 B,

• 2016 142,763 86,045 228,808 1993 C, 1995 A. 1996 A, 1997 A, 1999A,

• 2017 144,855 77,664 222,519 1999 B, and 1999 C bonds, %%ereused to establish trusts for refunding

• 2018 156,650 68,849 225,499

$4,297,580,000 of pre%rously issued bonds.

• 2019 168,735 59,806 228,541 At December 3 1, 2001, $3,852,350,000 of

• 2020 178,235 50,169 228,404 these bonds have been redeemed Under

• 2021 170,830 40,188 211,018 these Refunding Trust Agreements,

• 2022 175,625 29,869 205,494 obligations of or guaranteed by, the United States have been placed in irreNocable

• 2023 168,015 19,153 187,168 Refunding Trust Funds maintained by the

• 2024 77,675 9,506 87,181 Bond Fund Trustee The govemment

• 2025 80,240 4,842 85,082 obligations in the Refunding Trust Funds, along with the interest earnings thereon, sill Total $3,144,767 $2,459,909 $5,604,676 be sufficient to pay all interest when due on the refunded bonds and to redeem all

• Assumes a 4 56% interest ratefor the 1999A SWAP and a 517%interest ratefor the refunded bonds still outstanding at 1999D SWAP December 31, 2001 at various dates prior to or on their original maturities at par The monies on deposit in the Refunding Trust 72 2001 AnI uli R'port

[kt~Q (continued)

Funds, including the interest earnings I. SURETY BOND terminated by one year's notice by either thereon, are pledged solely for the benefit of party prior to the end of any contract term.

the holders of the refunded bonds Since the At December 31, 2001, the Agency For the years ended December 31, 2001 establishment of each Refunding Trust had a $10,000,000 surety bond from an and 2000, the Agency paid ElectnCities Fund, the refunded bonds are no longer insurance company for the period June 13, $2,962,000 and $3,047,000, respectively considered outstanding obligations of the 2001 to June 13, 2002 The term of the Agency. surety bond shall continue for consecutive K. CONTINGENCIES Interest on the bonds is payable semi one year terms unless written notice of annually. Certain of the bonds are subject to termination is provided by the Agency or The Price-Anderson Act limits the redemption prior to maturity at the option of CP&L at least 60 days prior to the expira public liability for a nuclear incident at a the Agency, on or after the following dates, tion of the then current term. In accordance nuclear generating unit to $9,540,000,000, at a maximum of 102 1/2% of the respective with a 2001 agreement between the Agency which amount is to be covered by private principal amounts and CP&L, the surety bond replaces a insurance and agreements of indemnity with

"*Series 1986A January 1, 1996 $12,900,000 letter of credit which expired the NRC. Such private insurance and

"*Series 1988 A January 1, 1998 on April 20, 2001, previously maintained by agreements of indemnity are carried by

"*Series 1989 A January 1, 1999 the Agency in accordance with the initial CP&L on behalf of all co-owners of the

"*Series 1991 A January 1, 2002 project agreements. The surety bond is for initial project. The terms of this coverage

"*Series 1993 B, C, and D CP&L to call upon should the Agency fail to require the owners of all licensed facilities to and Series 1985 G January 1, 2003 make full payment of its monthly obliga provide up to $88,100,000 per year per unit

"*Series 1995 A January 1, 2006 tions under the Operating and Fuel (adjusted annually for inflation) in the event

"*Series 1996AandB January 1, 2007 Agreement of any nuclear incident involving any

"*Series 1997 A January 1, 2008 On each anniversary date of the surety operating facility in the nation, with a

"*Series 1999 A and B January 1, 2009 bond, with 60 days prior notification to the maximum of $10,000,000 per year per unit

"*Series 1999 D January 1, 2010 Agency, CP&L may require an increase in owned in the event of more than one the amount of the surety bond, not to exceed incident. The joint owners of a unit would be The bonds are special obligations of $12,900,000 hable for the amount of any such assessment the Agency, payable solely from and The Agency paid $112,000 for the in proportion to their respective ownership secured solely by (1) revenues (as defined surety bond in 2001 and paid quarterly interests.

by the resolution) after payment of commitment fees of $43,000 and $131,000 The Price Anderson Act expires August operating expenses (as defined by the for 2001 and 2000, respectively, for the 1, 2002. Although several renewal programs resolution) and (2) other monies and letter of credit. are before Congress, the final outcome securities pledged for payment thereof by cannot be predicted.

the resolution. J. COMMITMENTS CP&L carries, for the benefit of the The resolution requires the Agency to owners, property insurance on the various deposit into special funds all proceeds of The Agency has a contractual plants of the initial project. All risk coverage bonds issued and all revenues (as defined by agreement with ElectriCities whereby for the operating units ranges from the resolution) generated as a result of the ElectriCities provides, at cost, general $100,000,000 to $500,000,000 with a Initial Project Power Sales Agreements and management services to the Agency. This deductible of $1,000,000. In addition, nuclear the 1981 PCA. The purpose of the agreement continues through December 31, liability insurance exists in the form and individual funds is specifically defined in 2004, and is automatically renewed for amount necessary to meet the financial the resolution successive three-year periods unless requirements estabhshed by the NRC.

2001 Annual Report 1 73

N In Assets of Funds Invested (SO00s)

Funds unresied Power Billing hn'estment Jan 1,2000) Receqnt hic ome Disbwsementv

" Construction Fund Initial project construction account $ 13,609 $ 0 $ 360 $ (7,457)

Peaking constucion account 93769 (3) 9)

107,378 0 (374) (100,491)

" Bond Fund:

Interest account 91,747 2,869 (192,418)

Reserve account 210,133 13,569 Principal account 59,874 2,112 (59,787)

Peaking interest account 3,287 1 (3,285)

Peaking principal account 2,471 I (2,472)

Peaking reserve account 7,008 8 (6,925) 374,520 0 18.560 (264,887)

" Reserve & Contingency Fund Initial project account 22,759 2,392 (5,880)

Peaking account 705 (13) (692) 23,464 0 2,379 (6,572)

"* Decommissioning Fund 3,915 281

"* Special Reser e Fund 1,093 68

"* Revenue Fund Revenue account 30,832 303,055 1,066 (4,221)

Peaking account 9284 10,489 157 (3,030)

Rate stabilization account - CP&L 34,524 311 Rate stabilization account- VEPCO 8267 224 82,907 313,544 1,758 (7,251)

" Operating Fund:

WVorking capital account 24,674 2,429 (110.758)

Fuel account 34,085 58,759 0 2,429 (110,758)

" Supplemental Fund Supplemental account 18,800 88,089 1,101 (97.378)

CP&L rate stabilization 29,448 1,86 I Special Supplemental Resceu e 18,756 296 (31) 48.248 106,845 39758 49 )

$700,284 $420,389 $28,359 $(587-368)

Note. The schedule above hav beei prepaiedina(tortdtn(e iutit the undetlvying Bond Resoltuomn, and *mordinglx, doe%not mtejie I ttie lhamige uit tle fair value of tm estments mIof December31, 2001 and 2000. repei tn eh/

See tcomnp*n rug hidependent Aduhtoi 5'Report 74 2001 Annual Report

Schedules of ©U'fav9ga In Assets of Funds Invested ($O00s)

Funds Invested PowerBilling Investment Funds Invested Dec.31, 2000 Receipts Income Disbursements Transfers Dec. 31,2001 Transfers

$ (193) $ 6,319 $ 0 $ 162 $ (6,479) $ 0 $ 2 (1) 0 0 (194) 6,319 0 162 (6,479) 0 2 193,066 95,264 1,510 (192,450) 188,925 93249 (11,129) 212,573 12,994 (15,620) 209,947 66,994 69,193 984 (68,805) 63,033 64,405 (3) 0 0 0 0 (91) 0 0 248,837 377,030 0 15,488 (261,255) 236,338 367,601 1,961 21232 1,937 (19,612) 19,128 22,685 0 0 1,961 21,232 0 1,937 (19,612) 19,128 22,685 4,196 238 4,434 (118) 1,043 57 (71) 1,029 (304,082) 26,650 327,716 815 247 (344,551) 10,877 (16,900) 0 0 (23,793) 11,042 28 (4,077) 6,993 (4,023) 4,468 72 (3,935) 605 (348,798) 42,160 327,716 915 247 (352,563) 18,475 108,162 24507 1,829 (110,983) 106,703 22,056 (8,844) 25,241 (935) 24,306 99,318 49,748 0 1,829 (110,983) 105,768 46,362 22,920 33,532 54,050 1,162 (111,189) 58,217 35,772 (6,436) 24,873 1,058 (25,485) 446 (17,490) 1,531 40,294 354 (41,33 847 (1,006) 59,936 94,344 2,574 (111,189) (8,60 37,065

$ 0 $561,664 $422,060 $23200 $(509271) $ 0 $497,653 Note: The schedule above has been preparedin accordance with the underlying Bond Resolution, and accordingly,does not reflect the change in thefair value of wm'estments as of December 31, 2001 and 2000, respectively See accompanyingIndependent Auditors' Report 2001 Annual Report 1 75

A I 1 j" 2 7' Per Bond Resolution and Other Agreements (SO00s)

Year Ended December 31, 2001 1',ar Ended Decembe, 31. 2000 Initial Initial Project Supplemental Total Projei t Squplemental Fatal Revenues:

Sales of electricity to participants 3332,419 $ 92,462 $424.881 S310,514 $112,421 S422,935 Sales of electricity to utilities 33,279 33,279 33,910 33.910 Rate stabilization fund xuithdrawal 8,012 25,485 33.497 27,816 6,435 34,251 Special funds Naluations 4,084 4,084 19,496 19,496 Special supplemental resen e fund withdraxx I 2.000 2,000 0 Other operating re%enues 93 93 164 39 203 Investment reN enue available for operations 20,303 1,579 21,882 24.237 1,620 25,857 398,190 121,526 519,716 416,137 120.515 536,652 Expenses:

Operation and maintenance 38,639 5 38,644 38,930 4 38,934 Fuel 36,148 36,148 34,179 34,179 Po\, er coordination sen ices:

Purchased power 7,624 99.647 107,271 7,090 95,972 103.062 Tran*sission and distribution 14.210 14,210 16,103 16,103 Other 439 439 240 240 7624 114.296 121,920 7.090 112,315 119,405 Adminmstram e and general - CP&L 19,188 19,188 25.671 25,671 Adniinistrati\ e and general -Agency 2,848 4,086 6,934 3,299 3,959 7,258 Amounts in lieu of taxes 3,857 3,857 3,991 3,991 Gross receipts tax 10,704 2,627 13,331 9,998 3.542 13,540 Letters of credit commnitent fees and administrat*xe costs 673 673 128 128 Debt sen ice 248.633 162 248 825 263,025 1,04-4 264,069 Special funds deposits Revenue fund 350 350 (349) (349)

Reserve and contingency fund 25,530 25.530 25,616 25,616 Decomnissioning fund 4,316 4,316 4,210 4,210 29,846 350 30,196 29,826 (349) 29,477 398,190 121,526 519,716 416,137 120,515 536,652 Excess of Revenues Over Expenses $ 0 $ 0 $ 0 S 0 $ 0 $ 0 Note The ri/e/le aboi e har been prepairdn inaroidtan e uitih the undcmlenh Bond Rewhcion, and arroidugh;doer not re/lettiitheangein the fair /ahte of tmiienctis or of Dec ember 3/, 2001 rind 2000, terpettn elv See itironipoiiang *ndependent Anthtor "Repoi t 76 2001 Ann al Report

Statistical jO jD{

Ten Years at a Glance (Unaudited) 2001 2000 1999 1998 1997

"*Megawatt-hour Sales (MWh) 6,765,157 6,924,955 6,569,652 6,556,169 6,273,385

"*Peak Billing Demand (kW) 1,284,897 1,265,241 1,217,221 1,190,030 1,185,129

"*Operating Revenues $458,160,000 $456,845,000 $445,358,000 $449,489,000 $446,742,000

"*Excess (Deficiency) of Revenues over Expenditures $0 $0 $0 ($2,676,000) $0

"* Sales to CP&L (Revenues) $33,279,000 $33,910,000 $36,486,000 $35,027,000 $38,142,000

"*Average Monthly Power Purchases by Cities (MWh) 563,763 577,080 547,471 546,347 522,782

"* Average Monthly Billings to Cities $35,407,000 $35,245,000 $34,073,000 $34,539,000 $34,050,000 1996 1995 1994 1993 1992

"* Megawatt-hour Sales (MWh) 6,291,401 6,142,495 5,810,477 5,865,354 5,509,338

"* Peak Billing Demand (kW) 1,116,786 1,194,209 1,135,450 1,155,200 1,112,185

"*Operating Revenues $460,674,000 $462,664,000 $458,023,000 $444,271,000 $398,585,000

"* Excess of Revenues over Expenditures $0 $0 $0 $20,830,000 $2,000

"*Sales to CP&L (Revenues) $38,416,000 $40,901,000 $61,302,000* $53,609,000* $39,987,000

"* Average Monthly Power Purchases by Cities (MWh) 524,283 511,874 484,206 488,780 459,112

"* Average Monthly Bilhngs to Cities $35,188,000 $35,147,000 $33,060,000 $32,555,000 $29,883,000 V Harris sellback increasedfrom 331/3% in 1992 to 50% in 1993 and 1994 aspart of the Hams litigationsettlement, then reduced to 33 1/3%

The until the sellback ends in 2007.

2001 Annual Report 177

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