ML023310575
| 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 Government Auditing Standards and 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 ELECTRIC PLANT:
In-service Accumulated depreciation Nuclear fuel, at amortized cost Construction work-in-process OTHER ASSETS AND INVESTMENTS:
Long-term investments Noncurrent receivables Investments in associated organizations Special deposits Decommissioning fund CURRENT ASSETS:
Cash and cash equivalents Short-term investments Accounts receivable Accounts receivable - affiliated companies, net Interest receivable Other current assets DEFERRED CHARGES:
Regulatory asset (Note 1)
Deferred loss on debt extinguishment (Note 6)
Debt issuance costs Preliminary project costs Other 2001 2000
$1,437,108
$1,434,279 (648,016)
(617,537) 789,092 816,742 29,968 34,416 2,977 4,591 822,037 855,749 32,002 82,191 13,207 14,952 7,466 7,438 24,886 32,178 57,252 56,180 134,813 192,939 15,668 14,189 10,727 14,264 103,608 120,857 11,494 6,118 1,035 1,155 532 147 143,064 156,730 26,824 3,284 17,463 18,835 7,606 8,084 9,418 9,418 1,839 2,164 63,150 41,785
$1,163,064
$1,247,203 MEMBERS' EQUITY AND LIABILITIES MEMBERS' EQUITY:
Membership fees Patronage capital Net unrealized gain (loss) on available-for-sale securities LONG-TERM DEBT CURRENT LIABILITIES:
Current maturities of long-term debt Accounts payable Accrued interest Other accrued expenses DEFERRED CREDITS AND OTHER LIABILITIES:
Reserve for decommissioning Accrued Department of Energy assessment Other noncurrent liabilities COMMITMENTS AND CONTINGENCIES (Notes 7, 8, 9, 10 and 11) 2001 2000
$1 1
22,112 22,112 290 22,403 (89) 22,024 983,737 1,024,194 40,454 40,423 174 11,855 92,906 57,252 4,057 2,709 64,018 47,482 62,868 15,838 11,560 137,748 56,180 4,548 2,509 63,237
$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
$659,818
$664,894 $635,772 OPERATING REVENUES OPERATING EXPENSES:
Fuel and purchased power Other production expenses Depreciation and amortization Administrative and general General taxes OPERATING MARGIN OTHER INCOME (EXPENSE):
Interest and dividend income Other INTEREST CHARGES:
Interest expense Debt fees and expenses NET MARGIN CHANGE IN NET UNREALIZED GAIN (LOSS) ON AVAILABLE-FOR-SALE SECURITIES COMPREHENSIVE INCOME (LOSS)
MEMBERS' EQUITY, beginning of year MEMBERS' EQUITY, end of year 379 9,951 379 9,951 22,024 12,073
$ 22,403
$ 22,024 The accompanying notes to financial statements are an integral part of these statements.
422,790 105,942 36,226 21,375 11,648 597,981 61,837 5,859 (126) 5,733 65,252 2,318 67,570 0
428,593 105,162 36,676 20,510 12,061 603,002 61,892 6,989 1,421 8,410 68,133 2,169 70,302 0
409,451 100,489 36,036 17,700 12,262 575,938 59,834 7,909 3,550 11,459 69,064 2,229 71,293 0
(10,495)
(10,495) 22,568
$ 12,073
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 Adjustments to reconcile net margin to net cash and cash equivalents provided by operating activities:
Depreciation and amortization Amortization of nuclear fuel Amortization of regulatory liability Amortization of deferred revenues Interest on decommissioning fund Deferred charges Other noncurrent assets and liabilities Changes in other operating assets and liabilities:
Accounts receivable Interest receivable Accounts payable Accrued interest Other Net cash and cash equivalents provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to electric plant Increase in decommissioning fund Decrease in long-term investments Decrease in deferred revenue fund (Increase) decrease in short-term investments Other, net Net cash and cash equivalents provided by (used in) investing activities CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of long-term debt Extinguishment of long-term debt Proceeds from issuance of long-term debt Net cash and cash equivalents used in financing activities NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS CASH AND CASH EQUIVALENTS, beginning of year CASH AND CASH EQUIVALENTS, end of year SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest Income taxes 0
0 $
0 40,138 14,626 0
0 1,072 (25,518) 1,945 11,873 120 (22,445)
(15,664)
(88) 40,382 14,577 (19,180) 0 4,513 (2,559)
(4,356)
(23,280)
(145) 16,035 (1,283)
(197) 38,461 15,273 (17,211)
(6,234) 3,684 (959)
(3,248)
(12,207) 220 313 16,014 298 6,059 24,507 34,404 (17,140)
(1,072) 51,061 0
3,044 7,013 (22,414)
(4,513) 9,171 0
(1,857) 8,193 (16,836)
(3,684) 30,000 6,234 4,469 (3,315) 42,906 (11,420) 16,868 (47,486) 0 0
(35,786)
(108,150) 104,370 (47,486)
(39,566) 1,479 (26,479) 14,189 40,668
$15,668
$ 14,189
$80,699
$ 69,247 0
0 (29,103) 0 0
(29,103) 22,169 18,499
$40,668
$52,884 0
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 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)
NRUCFC note, interest payable semi-annually at 9.05%, principal payments due in 2020 through 2024 NRUCFC note advances, interest and principal payable quarterly through June 14, 2023, interest rate of 6.0% and 5.88% at December 31, 2001 and 2000, respectively Less - Current maturities
$ 919,159
$ 966,629 99,400 4,970 662 1,024,191 (40,454)
$ 983,737 99,400 4,970 677 1,071,676 (47,482)
$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:
We have audited the accompanying balance sheets of Piedmont Municipal Power Agency (the "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 with auditing standards generally accepted in the United States of America. 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 the Agency, as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in note 2 to the financial statements, the Agency changed its method of accounting for derivative instruments in 2001.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplementary information included in Schedules I and 2 is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.
K~t~G, L CP 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 Utility plant (note 5):
Electric plant in service Nuclear fuel Construction work-in-progress Less accumulated depreciation and amortization Net utility plant Restricted funds (note 6)
Revenue fund assets (note 7)"
Cash Marketable debt securities Accrued interest receivable Due from restricted funds Participant accounts receivable Other accounts receivable Materials and supplies Derivative financial instruments Total revenue fund assets Other assets:
Unamortized debt issuance costs Net costs recoverable from future Participant billings (note 8)
Costs on advance refundings of debt Other Total other assets Liabilities and Retained Earnings Long-term debt (notes 9 and 10)
Bonds Unamortized discounts Unamortized premiums Restricted fund liabilities Accrued interest payable Reserve for decommissioning (note 11)
Revenue fund liabilities - accounts payable (note 7)
Retained earnings Commitments and contingencies (notes 14 and 15) 2001 554,828 32,076 2,516 589,420 (284,854) 304,566 198,270 7,125 236,190 3,610 1,292 8,992 4,792 5,742 4,832 272,575 18,666 418,849 162,344 2,521 602,380 1,377,791 1,286,404 (47,882) 1,066 1,239,588 50,901 39,329 90,230 12,455 35,518 1,377,791 See accompanying notes to financial statements.
2000 554,492 37,658 1,407 593,557 (269,565) 323,992 190,380 7,637 235,722 4,050 1,199 10,609 3,601 5,726 268,544 19,908 397,481 173,400 2,693 593,482 1,376,398 1,302,429 (50,628) 1,230 1,253,031 49,446 35,419 84,865 10,299 28,203 1,376,398
PIEDMONT MUNICIPAL POWER AGENCY Statements of Revenues and Expenses and Changes in Retained Earnings Years ended December 31, 2001 and 2000 (Dollars in thousands)
Operating revenues:
Sales of electricity to Participants Sales of electricity to other utilities Other Total operating revenues Operating expenses:
Operation and maintenance Nuclear fuel amortization Purchased power (note 4)
Transmission Distribution Administrative and general Depreciation Decommissioning Payments in lieu of property taxes Total operating expenses Net operating income Other income (expenses):
Interest income Net increase in fair value of investments and derivative instruments Interest expense Amortization expense Other expense, net Total other expenses, net Revenues under expenses before deferred items Net expenses recoverable from future Participant billings (notes 2 and 8)
Revenues over expenses before cumulative effect of a change in accounting principle Cumulative effect of a change in accounting principle (note 2)
Revenues over expenses Retained earnings at beginning of year Retained earnings at end of year 2001 117,548 16,208 1,207 134,963 22,337 6,958 24,769 4,709 1,409 12,426 18,656 3,910 4,385 99,559 35,404 26,772 4,853 (69,587)
(13,402)
(2,485)
(53,849)
(18,445) 21,368 2,923 4,392 7,315 28,203 35,518 See accompanying notes to financial statements.
3 2000 118,082 14,475 1,204 133,761 22,311 6,692 26,875 4,466 1,639 11,956 18,792 4,392 4,550 101,673 32,088 27,848 12,196 (73,735)
(13,566)
(5,405)
(52,662)
(20,574) 23,409 2,835 2,835 25,368 28,203
PIEDMONT MUNICIPAL POWER AGENCY Statements of Cash Flows Years ended December 31, 2001 and 2000 (Dollars in thousands)
Cash flows from operating activities:
Revenues over expenses Adjustments to reconcile revenues over expenses to net cash provided by operating activities:
Depreciation and amortization Cumulative effect of a change in accounting principle Net increase in fair value of investments and derivative instruments Net expenses recoverable from future Participant billings Reserve for decommissioning Decrease (increase) in:
Participant accounts receivable Other accounts receivable Accrued interest receivable Materials and supplies Increase (decrease) in:
Accounts payable Accrued interest payable Net cash provided by operating activities Cash flows from investing activities:
Purchase of investment securities Proceeds from sales and maturities of investment securities Expenditures for electric plant in service Expenditures for nuclear fuel Net cash provided by investing activities Cash flows from financing activities:
Payment of bond principal Defeasance losses Other Net cash used in financing activities Net increase in cash Cash at beginning of year (note 7)
Cash at end of year (notes 6 and 7)
Supplemental disclosure of cash flow information:
"Cash paid during the year for interest Cash received during the year for investment income 2001 7,315 39,016 (4,392)
(4,853)
(21,368) 3,910 1,617 (1,191) 12 (16) 2,156 1,455 23,661 (1,647,834) 1,663,475 (1,462)
(4,726) 9,453 (16,025) 1,792 (142)
(14,375) 18,739 7,637 26,376 65,641 25,903 See accompanying notes to financial statements.
4 2000 2,835 39,050 (12,196)
(23,409) 4,392 (1,741)
(2,426)
(869)
(202) 3,264 1,832 10,530 (1,712,993) 1,733,205 (807)
(10,033) 9,372 (21,200) 1,833 (19,367) 535 7,102 7,637 69,392 21,397
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 Restructuring Developments and Related 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.
(Continued) 5
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.
(Continued) 6
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.
Unamortized Debt 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.
(Continued) 7
PIEDMONT MUNICIPAL POWER AGENCY Notes to Financial Statements December 31, 2001 and 2000 (Dollars in thousands)
Marketable Debt 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.
Materials and 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.
Financial Reporting Under Governmental Accounting Standards Board (GASB) Statement No. 20, Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities that Use Proprietary Fund Accounting, 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.
(Continued) 8
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 Financial Instruments 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.
(Continued) 9
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 Catawba Project Power 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.
(Continued) lO
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).
Purchase Agreement 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.
Operating Agreement 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.
Interconnection Agreement 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.
(Continued)
I1I
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 Structures and improvements Reactor plant equipment Turbo generator units Accessory electric equipment Miscellaneous plant equipment Station equipment Transmission equipment Other Unclassified 336 157,032 248,023 69,270 50,623 16,757 5,477 1,242 1,897 4,171 554,828 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:
Accumulated depreciation of electric plant in service Accumulated amortization of nuclear fuel 2001 2000 266,487 247,847 18,367 21,718 284,854 269,565 (Continued) 336 157,032 248,023 69,270 50,623 16,757 5,477 1,240 1,883 3,851 554,492 12
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 Debt service - bond principal Debt service - bond fixed rate interest Debt service - bond retirement Debt service reserve Reserve and contingency Decommissioning Special reserve Funds are comprised of:
Marketable debt securities Accrued interest receivable Due to revenue fund Fair value 19,370 29,550 1
85,328 8,616 40,142 15,263 198,270 196,634 2,928 (1,292) 198,270 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 Derivative financial instruments Fuel acquisition Rate stabilization 76,283 4,832 30,503 160,957 74,895 30,503 155,781 65,953 28,271 174,320 272,575 261,179 268,544 13 Amortized cost 19,370 29,550 1
83,850 8,385 39,329 15,000 195,485 193,849 2,928 (1,292) 195,485 Fair value 16,021 30,513 1
84,601 8,548 35,536 15,160 190,380 189,079 2,500 (1,199) 190,380 Amortized cost 16,025 30,518 1
83,850 8,385 35,419 15,000 189,198 187,897 2,500 (1,199) 189,198 65,402 28,271 171,118 264.791 (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 Depreciation expense Amortization of redemption and defeasance losses Amortization of bond discounts and debt issuance costs Nuclear fuel expenses Letter of credit fees Other Items reducing future Participant billings:
Investment income Increase in fair value of investments and derivative instruments Rate stabilization (revenue received to reduce future billings to Participants)
Reserve and contingency deposits Revenues (expenses) recognized:
Interest, depreciation, amortization expense included in Participant billings for debt principal payments Rate stabilization draws applied to expenses Reserve and contingency revenue applied to expenses Net costs recoverable from future Participant billings 331,796 282,818 138,463 63,526 873 5,649 2,392 825,517 (76,528)
(14,182)
(513,888)
(36,751)
(641,349)
(129,043) 358,106 5,618 418,849 329,373 265,340 127,264 59,559 873 5,649 2,392 790,450 2,423 17,478 11,199 3,967 35,067 (76,528)
(4,937)
(503,107)
(35,425)
(619,997)
(109,674) 331,989 4,713 397,481 (9,245)
(10,781)
(1,326)
(21,352)
(19,369) 26,117 905 21,368 (Continued) 14
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.
(Continued) 15
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 (Continued) 16
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) 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) 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) 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) 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) 1998A Refunding Series Electric Revenue Bonds, payable annually from 2006 to 2025 with interest ranging from 4.4% to 5.5%
1999A Refunding Series Electric Revenue Bonds, payable annually from 2014 to 2016 and 2020 to 2021 with interest at 5.25%
Total long-term debt Less unamortized discount Plus unamortized premium 50,000 50,000 31,700 64,485 34,915 161,380 97,510 1,286,404 (47,882) 1,066 1,239,588 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 (Continued) 50,000 50,000 31,700 65,200 35,300 161,380 97,510 1,302,429 (50,628) 1,230 1,253,031 17
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:
Principal 20,470 20,880 23,015 24,728 31,772 33,993 43,056 37,391 37,309 39,049 38,759 52,972 57,630 61,105 64,270 67,360 68,995 80,795 85,665 90,480 92,975 100,590 93,775 1,267,034 Interest 67,905 67,804 66,601 65,314 63,854 61,975 60,139 65,641 65,634 63,773 61,839 49,509 46,338 41,780 38,546 35,303 31,916 28,132 23,396 18,889 14,619 9,902 4,681 1,053,490 Total 88,375 88,684 89,616 90,042 95,626 95,968 103,195 103,032 102,943 102,822 100,598 102,481 103,968 102,885 102,816 102,663 100,911 108,927 109,061 109,369 107,594 110,492 98,456 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.
(Continued)
Year 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 18
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.
(Continued) 19
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), Disclosure About Fair Value of Financial Instruments, 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)
Marketable Debt Securities Estimated fair value, which is the carrying value, of all marketable debt securities is derived from quoted market prices.
(c)
Derivative Financial Instruments Estimated fair value of derivative financial instruments is derived from current market pricing models.
(d)
Participant Accounts 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.
(Continued) 20
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 estimated fair values at December 31, 2001 and 2000 are as follows:
2001 Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Electric Revenue Refunding Bonds Carrying Amount 27,536 95,573 22,070 11,310 205,403 145,510 20,440 78,143 71,193 123,887 100,108 31,735 99,508 160,612 97,461
$ 1,290,489 Estimated Fair Value 30,729 103,935 42,342 20,724 227,619 147,695 21,770 80,378 71,853 127,756 100,108 31,735 99,508 160,730 93,921 1,360,803 values different from their 2000 Carrying Amount 27,235 95,051 20,454 10,502 204,600 146,409 20,425 80,546 71,177 135,355 100,361 31,816 100,864 160,385 97,297 1,302,477 Estimated Fair Value 29,628 100,952 39,465 19,201 230,539 161,329 21,721 85,196 71,513 142,344 100,361 31,816 100,864 160,045 93,955 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.
Primary Liability 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.
(Continued) 1986 1986A 1988 1988A 1991 1991A 1992 1993 1996A 1996B 1996C/D 1997A 1997B/C 1998A 1999A 21
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:
Primary Property 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 Interruption Insurance. 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.
(Continued) 22
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)
Revenue Sales of electricity to participants Sales of electricity to Duke Sales of electricity to others Interest income Other Total revenue Expenses.
Catawba operating expenses:
Operation and maintenance Nuclear fuel Purchased power - Duke Payments in heu of taxes Interconnection services.
Purchased power.
Duke Participants Other Transmission services Distribution services Administrative and general:
Agency Duke Other Special funds deposits (withdrawals)
Bond fund:
Deposits from revenues Liquidity facility fees Reserve and Contingency fund:
Deposits from revenue Capital additions Transfer excess funds Decommissioning fund:
Deposits from revenue Interest income (1)
Revenue fund Working capital Fuel Rate stabilization Interest income (1)
Deposits (draws)
Supplemental power reserve.
Interest income (1)
Transfer excess funds Other capital transactions Bond: other Plant additions:
Reserve and contingency fund General plant Distribution plant Fuel acquisitions Total expenses Actual Revenues and Expenses 117,548 9,303 6,905 26,772 1,207 161,735 22,337 6,958 8,744 4,385 8,213 7,549 263 4,709 1,409 3,943 8,483 2,485 84,043 699 8,412 (1,326)
(7,086) 1,324 2,586 7,337 (4,726) 10,781 (26,118) 1,008 (1,008) 142 1,326 94 43 4,726 161,735 (1)
Included in "Revenue Interest Income" 25 Budgeted Revenues and Expenses 117,904 8,432 4,364 26,538 1,207 158,445 21,426 6,458 8,261 4,618 9,548 7,789 156 4,224 1,531 4,075 9,219 3,207 87,794 660 8,784 (1,781)
(7,003) 1,324 2,351 (751)
(5,531) 10,693 (26,117) 975 (975) 1,781 178 20 5,531 158,445 Actual Over (Under)
Budget (356) 871 2,541 234 3,290 911 500 483 (233)
(1,335)
(240) 107 485 (122)
(132)
(736)
(722)
(3,751) 39 (372) 455 (83) 235 8,088 805 88 (1) 33 (33) 142 (455)
(84) 23 (805) 3.290
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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 Balances at beginning of year:
Assets Liabilities Net Project revenues Participants - Electric
- Facilities rent
- Control services
- Other Duke Povser - Electric Other Surplus Electric Interest infome Project costs (see note)
Operations and maintenance Fuel Purchased power - Duke Decommissioning General and administration Payments in lieu of taxes Other Debt service Liquidity facility fee Reserve and contingency Revenue Operating Bond Principal Working Rate Fuel Interest Capital Stabilization Account Retire Reserve S
65,402 (10,299) 55,103 (i)
(i)
(1)
(1)
(i)
(I)
(1)
(2)
(3)
(2)
(3)
(2)
(2)
(2)
(3)
(3)
(3) 117,548 1,146 13 48 9,303 6,905 12,397 (22,337)
(6,958)
(8,744)
(1,324)
(11,216)
(4,356)
(2,485)
(84,043)
(699)
(8,412) 171,118 28,271 46,544 83,850 10,781 6,958 84,043 699 26 Reserve and Contingency 8,385 Decommission 35,419 2,586 Supplemental Power 15,000 1,008 1,324 8,412
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 Supplemental power costs, Purchased Power Duke Participants
- Other "1
ransmission services I)istribution services General and administration PaNment in lieu of taxes Other tund changes Transfers in (out)
Rate stabilization Excess funds Reimbursement Payments.
Debt retire/interest Capital additions Balance, at December 31, 2001 (2)
(2)
(2)
(2)
(2)
(2)
(2)
(3)
(3)
(3)
(2)
(2)
Revenue Operating Bond Principal Working Rate Fuel Interest Capital Stabilization Account Retirement Reserve (8,213)
(7,549)
(263)
(4,709)
(1,409)
(1,210)
(30) 26,118 8,094 1,326 (142)
(1,462)
S 62,440 S
74,895 S
(12,455)
(?6,1 18)
Reserve and Contingency Supplemental Decommission Power (7,086)
(1,326)
(4,726) 155,781 30,503 (82,365) 48,921 83,850 8,385 39,329 (1,008) 15,000 (I)
Deposited in appropriate fund (2) Paid to third parties (3) Transfers between funds Note I:
In accordance with the Bond Resolution, third party payment requirements (except debt service payments) are transferred from Revenue Fund (Working Capital) to the Operating Fund and actual disbursements are made from the Operating Fund 27 Assets Liabilites
F177 Jim I~ I LIl
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 audit reports of and financial information regarding each North Carolina Municipal Power Agency are included in this report.
Each Power Agency is a separate and distinct legal entity and the inclusion of such information regarding both entities should not be construed to indicate any relationship between the two 2001 Annual Report I I
)
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7 7ll ila l
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7s Power It brightens a dark night, keeps us warm in the winter and cools us in the summer. It entertains us and helps to keep us safe It plays such an integral part in our daily lives, yet most of us rarely think about ft. It's electncity 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 invention called electricity was finally becoming a useful part of our daily lives But many power companies weren't willing to extend lines to smaller, more rural communities. They were too far away or there were not enough residents to justify the costs. So towns began building their own electric generating plants and putting up their own wires and poles. As more cities realized the early benefits of citizen ownership of electric systems, more communities wanted it for themselves Municipally owned electricity gave citizens control of their power supply. Neighbors and friends made local electric decisions and customer service was a top priority.
During the 1970's, North Carolina's public power towns began joining forces to ensure their residents, businesses and the state had a reliable and plentiful supply of power With an energy crisis worsening, threats of blackouts, and power companies teetering on bankruptcy, state voters overwhelmingly approved the concept of municipal power agencies North Carolina Eastern Municipal Power Agency and North Carolina Municipal Power Agency Number 1 were born Today 51 cities across North Carolina are partnered with Duke and CP&L. They have joint ownership in nuclear plants and coal fired plants. It's an arrangement that helped to build new generation for North Carolina It kept the lights on and helped North Carolina grow and prosper In the 1990's, Congress set the stage for the 21 cities that buy their power wholesale. The non-power agency cities have used this new law to search the market for better prices, which helps with economic development and lower electric rates Today all these public power commu nities continue to shine in North Carolina and the reasons are simple. Public power is locally controlled and locally operated.
Friends and neighbors are the utility employees The electric revenue stays in town and helps these public power communities grow and prosper. North Carolina's Public Power communities are united in power to ensure they provide their citizens with a safe, secure, and reliable 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 is strength in numbers "That's the whole idea behind ElectriCities A unified group of cities, providing power to their residents with service that is second 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 tion debate, customer choice was put on the back burner in 2001. The State Legislature was focused on a budget shortfall and an economy on the downturn.
Meantime our cities were proving what we have said all along. We are responsible, reliable distributors of electricity and good stewards to our bondholders. We are paying off our debt on schedule. We have reduced the rate of transfers and continue looking for ways to keep our costs down The Power Agency cities as a group are in compliance with the Local Government Commission (LGC) transfer policy Our residents have a safe and plentiful supply of power. Our utilities are proving that neighbors serving neighbors is a good way to do business. Our cities consistently restore power faster than other utilities and receive high marks when it comes to the questions and concerns of their customers.
Now we must stay the course. With a shift away from deregulation, we must strengthen our bond with one another. We each have individual strengths and chal lenges unique to our communities, but when we combine our resources and the vast expertise of those who work for our cities, everyone benefits. A unified voice also means political clout as we put forth the positive message that public power is good for North Carolmal The cities that provide power to their people want to continue that service because they do it well But the reasons go much deeper. Our city leaders want to ensure a higher quality of life for their residents not only today, but also well into the future.
So to our cities we say, join hands in a spirit of unity and togetherness. There is nothing like a strong and powerful group to show others that our commitment is real and our partnership is strong.
4 2001 Annual Report Jesse C. Tilton, III, Chief Executive Officer John T. Walser, Jr.,
Chairman, Board of Directors
John T. Walser, Jr.
Chairman, Lexington Malcolm A. Green Greenville EleotrOities Leac{w~Dp 2001 Board of Directors R.L. Willoughby Winton R. Poole William H. Batchelor Steven K. Blanchard Vice Chairman, Secretary, Cornelius Rocky Mount Fayetteville Washington Steven Elizal Jack Alt L. Harrell Barry C. Hayes Franz F. Holscher J. William McGuinn, Jr.
beth City Granite Falls Gastonia High Point k F. Neel Samuel W. Noble Stephen H. Slough Edward A. Wyatt bemadle 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
- j.
.gi g., E';..
I Liii 1i
ElecthCities jfi JLf 1Eo Alphabetical Listing of Member Cities
& Towns in 2001 City/Town
- Abbeville, SC
- Albemarle..
- Apex
- Ayden
- Bamberg, SC
- Bedford, VA..
- Belhaven
- Bennettsville, SC
- Benson..
- BlackCreek
- Blackstone, VA Bo",tic..
- Camden, SC.
- Cherryille
- Cla)ton
- Clinton, SC
- Concord
- Cornelius
- Culpeper, VA
- Dallas
- Danville, VA
- Drexel
- Easley, SC
- Edenton SElizabeth City..
- Elizabeth City State U
- Elkton, VA
- Enfield
- Farmville
- Fayetteville
- Forest City
- Fountain
- Franklin, VA
- Fremont
- Gaffney. SC
- Gastonia
- Gramnte Falls
- Greenville
- Greer, SC H lamilton H tarrisonburg, VA
- Hertford
- High Point
- Highlands
- Hobgood
- Hookerton Huntersville SKings Mountain
- Kinston
- La Grange 6
2001 Annual Report
[niversity Year Electric System Established
...... 1905 1910.......
1917 S.........
1916 1905..
1911 S.....
1920
....... 1903 1913.......
1922 S.......
1888 1920 1902........
1920 S.......
1913
.1907 1901 1916 1934 1925........
1886 S.......
1926 1911 1908 1926 S......
1891 1924..
Pnor to 1940 S.....
1904 Chartered 1905 Early l900s....
1903 l......
1892
... 1918.
1907 1919 S.....
1923 1905 1914 S....
1922 S.....
1957 1915.....
1893 1926 1922 1907.......
1916 S....
1935 1897 1917 Customers 3,626 S..... 11,333 S...
.9,154 3,695 1,784
... 6,729 S....
1,139 4,950 1,800 S.......
685 2,079 193 S........
10,000 2,890 S.......
4,082 4,377
... 23,997 S....
1,866 S....
3,054 2,851 S.....
48,718 1,236 12,000 3,899 10,717 Uniersity S.......
1,020 1,538 2,888 67,128 S.......
.4,732 372 5,242 869 7,300 25,591 2,318 S..... 51,662 10,991 254 S.......
16,217 1,271 36,033 2,519
--- 320 S422 3,125 3,943 16,528 1,524
EleotriOties EmEwUNTflw Alphabetical Listing of Member Cities
& Towns in 2001 City/Town Year Electric System Established C
Landis................................
1919..................
Laurens, SC
. 1922 Launnburg...............................
1925 Lexington......
1904......................
Lincolnton 1900...........
Louisburg 1906.....................
Lucama 1889 Lumberton............................
1915.
M acclesfield 1928..............
M aiden
....... 1920..........
M anassas, VA......................................
1912.
M artinsville, VA..............................
1900 M onroe.............................
1900.......................
Morganton 1899..................
M urphy 1953..........
New Bern 1901 New River Light & Power (Boone)......................
1915 Newberry, SC 1923.....................
Newton..........
1896.................
Pikeville 1918 Pinetops 1925 Pinevtle...........................
1939.......................
Red Springs 1910.....................
Richlands, VA 1922.........
Robersonville....................................
1919 Rock Hill, SC............................
1911 Rocky Mount 1902..............
Scotland Neck
.... 1903................
Scima 1913 Sharpsburg...................................
1920 Shelby..............................
1912.......................
Smuthfield............
1912...................
Southport.
1916...................
Stantonsburg.
1920 Statesville...................................
1889 Tarboro..............................
1897.....................
UNC-Chapel Hill 1895............
Umversity and 430 campus rei UNC-Greensboro 1919.
Union, SC..................................
1896 Wakefield, VA......
1920..................
Wake Forest...........................
1909...........
W alstonburg 1922.........
W ashington 1903 W aynesvtlle................................
1923 Western Carolina University 1920...............
Westminster, SC
...... 1921..........
W ilson...
1892.
W indsor 1920 W interville............................
1900...................
2001 Annual Report 1 7 I
ustomers 2,607
... 5,305 5,932 18,212 2,841
.. 1,940
... 1,145 10,066 302 1,030
.. 14,341
...... 8,176 9,304 8,045 4,173 16,821 7,054 4,789
.4,401 527
...... 730 2,373 1,916 2,500 1,220 26,642 29,097
.. 1,630 2,705 1,596 8,136 4,568
.... 2,086 1,203 12,501
.5,797 tal customers University 7,025 564 4,900 S......
135 12,384
.2,966
.... 2,086 1,808 30,990 1,758 1,985
!IiIT, TT---Iýl Toýr:l im T A T A 0 1111 '1 I's
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 changed.
Due to events m California, deregulation was put on hold early in 2001 Although we continue to keep an eye on how restructunng is progressing in other states, we are now able to refocus our attention on our customers and on providing the best possible service for them.
As members of the public power community, we maintai an enviable position.
Individually, we have the autonomy to determine how best to serve the customers in our cities and towns At the same time, our membership in this "fratemity" enables us to partner with other public power mumcipalities on projects that achieve savings and other benefits for consumers The past year is notable largely because of the many cost saving regional opportumties we reconized. The collaborative efforts that ensued resulted in several significant accomplishments that will benefit the members of NCMPAI for years to come.
Together with Cayenta and ElectnCities, we began offenng our members a new Customer Information System (CIS) The CIS will help cities streamline their btlhng procedures and increase efficiency through a program designed specifically for municipalities It will also allow the cities that comprise NCMPA 1 to share common software, staff expertise, and support.
We are in the process of installing 10 diesel generators in cities throughout western North Carolina as part of our distnbuted generation project. These generators will better enable us to meet peak demand during the summer months
%khen demand is high, as well as support our sales of energy to the vi holesale market. As a result of this endeavor, we anticipate a savings in supplemental power purchases of $10 million over the next 10 years Last summer Duke filed a peution A ith the Nuclear Regulatory Commission to renew the operating licenses for both McGuire and CataA ba nuclear stations Approval of its license extension would allow the Cata\\vba Plant to continue operations into the 2040's, assuring our member cities and their customers a safe, reliable, and economical power supply for many years to come.
Effective January 1, 2001, NCMPA1 entered into the \\v holesale market for its supplemental power Contracts with Georgia Power Company through 2005 and one year deal%
with Dynegy and Entergy-Koch Trading provided for power supply " hen requirements were in excess of the Cataw ba project during 2001. Later, in the fall, NCMPA1 contracted for our 2002 summer power supply needs with EKT and Aquila.
Finally, we issued an RFP in 2001 that offers more structured sales of our Catavi ba resource It also examines replacing that power with peaking power from the wholesale market At the end of the year, we were in negotiations for new power supply arrangements.
These are but a few of our many successes tn 2001. 1 believe our willingness to unite on these important issues made each of them not just a possibilhty -
but a reality That's %i hy "United in Power" is not just a slogan, but rather is an apt description of the good we can accomplish when we join together.
10 2001 Ainual Report Richard L. Thomas Mayor, Lexington Chairman, NCMPA1 I
NCMPAl LafelflEp 2001 Board of Commissioners 2001 Officers Richard L. Thomas Chairman Mayor, Lexington Morris A. Baker Vice-Chairman Town Manager, Drexel Arnold J. Koonce, Jr.
Secretary-Treasurer Mayor, High Point Commissioners and Alternate Commissioners Alternate commissioner's names appear in Italics
- Albemarle Mr Raymond I Allen First Alternate vacant Mr Jack E Ned
- Bostic Commissioner Vacant Mr James Monvrw
- Cherrnyille Mr Jerry J Hudson Mayor Wade H Strouipe, Jr
- Cornelius Mr James R. Bensman First Alternate Vacant AMr Thurman Ross, Jr
- Drexel Mr Moms A. Baker Mr Benny7J Onrers
- Gastonia Mr Franz E Holscher Mr Bob W*lkerson
- Granite Falls Ms Lmda K. Story Dr Caryl B. Burns Mayor Barry C. Hayes
- High Point Mayor Arnold J. Koonce, Jr.
Mr. Stnbling P Boynton
- Huntersville Mr Alex Bamette Mr Jerry E Cox
- Landis Mr Tommy Branch First Alternate Vacant
- Lexington Mayor Richard L Thomas Mr C Phillip Heag Sr Mr L Klynt Ripple
- Lincolnton Mr. Stephen H Peeler Mr Jeff B. Emory Mayor Bobby G Hutt
- Maiden Mr Kevm C Sanders Mr Kent M Auton
- Monroe Mr Donald D Mitchell Mr Robert J Smith AMr S. Douglas Spell
- Morganton Mr Dan Brown Ms. Sally W. Sandy Mr Steve B Settlemyer
- Newton Mr Edward F Burchins First Alternate Vacant
- Pineiflle Mayor George Fowler Ms Mary Ann Creech
- Shelby Mr Pete Gilbert Mr Jay C Stowe Ms Betsy Fonvtelle
- Statemille Mr Arthur E Peterson Mr Herbert "Jim" Lawron AMr Larry M Cranford 2001 Annual Report 1 11
ECecT c System TDO City/Town Established Revenues Customers
% Ownership
- Albemarle..
Bostic.
"* Cherryville
"* Cornelius Drexel Gastonia Granite Falls.
High Point
"* Huntersville Landis
"* Lexington.
"* Lincolnton.
"* Maiden
"* Monroe
"* Morganton..
"* Newton.
"* Pineville
"* Shelby..
"* Statesxille
.. 1910.
2001 -$23,363,586 2000 -$23,824,196 S..
1920............
2001-
$248,991 2000-
$243,359
.1920 2001 -
$4,458,395 2000-
$4,610,124
...1916 2001 -
$2,898,686 2000-
$2,812,310 1926..
2001-
$1,697,006.
2000-
$1,660,610 1919......
2001--$55,587,515.
2000 -$56,861,182 S1923
...... 200 1 -- $4,102,7 8 1 2000-
$4,226,271 S1893 2001 -
$80,765,534 2000-$78,419,127 1916.....
......2001-- $4,659,163 2000-- $3,974,221 1919.......
.. 2001 -
$3,840,410 2000-- $3,485,020 1904 2001 -$41,458,163 2000 -$41,001,556 1900..........
2001 -
$5,463,620 2000-- $5,450,148 1920...........
2001 -
$5,260,709 2000-- $5,396,878 1900............
2001 -$33,666,778 2000 -$33,739,383 1899.........
2001 -$21,752,955 2000 -$22,022,361 S....
1896..
2001 -
$7,830,840 2000-- $7,513,216
.1939 2001 -
$8,788,260.
2000-- $8,231,250 S...
1912...........
2001--$14,466,423.
2000 -$14,753,612 S...
1889........... 2001 -- $31,136,866..
2000 -$30,736,338
. 11,333..
193..
.2,890 1,866 1,236 25,591 2,318 36.033 3,125 2,607.
... 18,212.
2,841 1,030 9,304..
.. 8,045
.4,401
.2,373 8,136 12.501 7.604%
S..
.. 0.087%
1.579%
0.362%
..0507%
17 121%
0912%
. 18960%
0623%
1 130%
S..
... 12934%
S..
.. 1608%
1.289%
10038%
6.735%
... 2115%
.0536%
.5996%
.9864%
12 2001 Annual Report
Operational OfljUQ Plant Informatic
"* Catawba Unit I
"* Catawba Unit 2
"* McGuire Unit 1
"* McGuire Unit 2 Capacity* Availability*
Factor %
Factor %
1009 86.7 90.1 102.7 99.6 85.7 88 0 1000
- These numbers are reported by Duke to the Nuclear Regulatory Commission in the units' December 2001 Operating Data 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 1 began a refueling outage on March 9, 2001 that ended on April 17 The next refuelng outage for the unit is scheduled to begin September 13, 2002 McGuire Unit 2 did not have a refueling outage in 2001. Unit 2 began a refueling outage February 22, 2002 that is scheduled to end on March 25.
Catawba Unit 1 and McGuire Unit 2 placed in the top 50 nuclear units in the world based upon gross generation in 2001.
Catawba Unit 1 and McGuire Unit 2 were 15th and 24th, respectively New Supplemental Power and Transmission Arrangements On January 1, 2001, NCMPA1 no longer purchased power from Duke Energy for its requirements above its Catawba Project entitlement. To meet its supplemental power requirements, NCMPA1 has entered a five-year contract with Georgia Power Making upgrades and keeping up with repairs means safe and reliable power It also ensures the electric distnbution system will remain a valuable part of the community Company for the purchase of 125 MW which began on January 1, 2001. NCMPA1 also has the right to schedule and receive 42 MVW of power from the Southeastern Power Administration. In addition, NCMPA1 purchased 50 MW of firm capacity from Dynegy Power Marketing, Inc., from their Rockingham County North Carolina Units 1 through 4 and 50 MW of System Firm Energy delivered to the Duke control area from Entergy-Koch Trading, from their Dayton Power and Light Company Resources for June 1, 2001 through August 31, 2001.
NCMPAI also purchases transmission services for its native load requirements from Duke Electric Transmission in accordance with Duke's Open Access Transmission Tariff To effectuate this new service, all the required agreements and amendments to existing agreements have been filed and approved by the Federal Energy Regulatory Commission.
On January 1, 2001, NCMPA1 also became responsible for scheduling and delivering power for all of its requirements above its Catawba Project entitlements NCMPAI has entered a two-year contract with Entergy-Koch Trading to serve as NCMPAI's resource manager Entergy Koch Trading has the responsibility of managing and marketing all of NCMPAI's 2001 Annual Report i 13
Operational I
I NCMPA1 has 75% ownership of Catawba Nuclear Station Unit 2 located on Lake Wylie in South Carolina The unit began commercial operation in 1986 NCMPA1 has two employees that work on-site at Catawba surplus energy. For 2001, NCMPAI had revenues of $36 3 million from surplus energy sales In addition, Entergy-Koch Trading is responsible for scheduling the delivery of energy to meet NCMPA l's energy requirements aboxe its Catawba Project entitlement. NCMPA I's Peak Demand in 2001 was 989 MW Catawba and McGuire Operating License Extension Duke Energy submitted concurrent applications for Operating License Extensions for all four units at the Catawba and McGuire Nuclear Stations on June 13, 2001 Submitting the applications for the four very similar units together is projected to provide significant cost savings as compared to separate applications for each Station Duke believes that the Cataw*ba and McGuire applications are on track and proceeding basically as expected. Duke previously submitted applications for Operating License Extensions for its three Oconee Units on July 6, 1998 The NRC approved the 20 year License Extensions for the Oconee Units on May 23, 2000 Distributed Generation The decision was made in 2001 to construct 18 25 MW of disel fueled 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 Economic Development The western cities continue success with industry recruitment and expansion of their existing businesses. In 2001, NCMPA1 members added 1,023 new jobs to their communities with investments totaling
$207,655,165. New load added to the Agency totaled more than 15 MW.
NCMPA1 staff continues efforts with the Department of Commerce and the Regional Partnerships to further the strategic load growsth 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 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 includes innovative rates, educational opportunities on such subjects as electric motors and drives, predictive maintenance, compressed air, and our Energy Solutions Partner (ESP) program. ESP offers alliance partnerships that have been formed to provide solutions to our members' customers' needs Our lead backup generation partner sold over 1,000 kW of new generation to NCMPA1 customers in 2001. OtherESP solutions include lighting, demand controllers, and power quality.
Huntersville & Cornelius The merger of Huntersville and Cornelius electric operations in 1997 continues to show reduced operating costs, exceptional customer service, and value for customers of the towns. In July 2001, the Pbhic power crews are at work no matter what the weather. In most cases electricity is restored faster in public power communities because the crews live in the towns where they work.
combined electric department celebrated its four year anniversary and achievements with an employee appreciation luncheon. Among other achievements in 2001, the department received the highest safety award given by the NC Association of Municipal Electric Systems for working in excess of 35,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> without an accident or injury.
Reduced operating costs and economies of scale from double-digit load growth have enabled both towns to reduce electric rates.
As both towns and the region continue to grow and best practices are implemented, operating costs continue to decline.
Providing safe, responsive, and value added customer service is emphasized in daily operations. Customers have already seen improvements in bill information, format, and payment options. Further improvements are expected as both towns transition to a new computer and billing system in the future.
The HuntersvillelComelius merger has been successful and shows that regionalization of electric systems is possible and economical for customers and towns Customer Retention Program 2001 saw ongoing efforts by NCMPA1 and its participants to strengthen business relationships with their largest industrial and 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, authorized city staff members can view their city's customers' usage history and other related information The Agency will begin marketing access to the site by the custom ers themselves in 2002. Information gathered from real time meters that is maintained in the data warehouse will provide customers with useful information concerning their usage patterns and billing history, thus enabling them to make more efficient use of their energy resources.
NCMPA1 also provides retail-billing services for the Toxkn of Pineville through its Huntersville/Cornehus office Huntersville/Cornelius office staff work with the toA n each month in processing billing information for approximately 2,600 customers Customers in public power towns can take care of business locally (usually town hall) They can also pick up the phone and deal with a real live person, instead of an automated system Wholesale Rates The Agency had a 2% wholesale rate increase this year. NCMPA I developed wholesale rate alternatives to meet its future power supply needs.
Security Following the terrorist attacks on the World Trade Center and the Pentagon on September 11, 2001, the nation's nuclear power plants have come under scrutiny about Nkhether they could withstand a terrorist stnke As a result of the 9/11 eN ents, nuclear power plants across the United States have upgraded their already impressive security measures Nuclear Regulatory Commission regulations require that these plants have a professional security staff and demonstrate they can withstand an attack from a group armed with automatic weapons, explosives and insider assistance Under the contractual arrangement with NCMPA1, Duke Energy handles all issues of security in accordance with federal regulations Duke is closely coordinating with federal, state, and local authorities and they have taken and will continue to take appropriate steps to ensure safety and security at the CataA ba Nuclear Station Unit 2 in which NCMPAI has 75 percent o%% nership 16 2001 Annual Reporl
Operational Highlights NCMPAI Participant Energy Usage Forecast for 2002 is from Sept 2001 Load Forecast 4S Jan Feb Ma.
Apr SActua, 2000 May Juine July SActual2001 Au, Sept Oct Nov.
SFoecast 2002 NCMPAI Participant CP Demand NOTE: At Power Agency Delivery Level - (Billing Point) including SEPA
- Forecast for 2002 is frm Sept 2001 Load Forecast Jan Feb Mar Apr.
SAua 12000 2000 2001 Number of New Jobs May June July Acut 2001 NCWIPAI Economic Development 201M
$207 nfIlion 10¢ 2000 2001 Investments in Millions Aug Sept Oct.
Nov Threcast 2002 20M0 2001 Megawatt Growth 2
C1 Aniual u~ort 17 lit C
2,000 loo0
%0¢ Dec.
t iE3 Ff7~r--2 ~TII nfrmallom Investment Portfolio Statistics Earnings Eamnngs*
inc oine
- 2001
$51,850,000
- 2000
$55,857,000 Market Value as of 12/31 tVaue
- 2001
$948,926,000
- 2000
$959,519,000 Rate of Retum 6.06%
6.37%
4veruge Matunt*
45 years 5 1 years Transactions NmbdJer Amount
- 2001 670
$9,685,535,000
- 2000 643
$7,450,227,000
- For Earnings and Market thlue, asnotnts ttu hude ui onwefrma and nuta!ei vahle of %ec unties hekl in the decommnusous ng t nat Debt Outstan Debt Outstandi Fixed Rate Bon
- 2001
$2,2
- 2000
$2,2 NCMPA1 Bon
"* Bonds Outstai 12/31/00
"* Matured 1/1/01
"* Bonds Outstanding 12/31/01 iding NCMPA1 Bonds Outstanding ng 12/31
- Series 1985B
$80,575,000 WeightedAverage
° Senes 1988
$5,526,000 Balance Interest Comt ds
- Series 1990
$18,410,000 12,436,000 5.97%
71,884,000 601%
- Series 1992
$1,033,855,000
- Series 1993
$484,550,000 id Reconciliation
- Senes 1995A
$79,440,000 nding
- Series 1997A
$97,775,000
$2,271,884,000
- Senes 1998A
$128,365,000 59,448,000
- Series 1999A
$83,340,000
- Senes 1999B
$200,600,000
$2,212,436,000 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 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 of America 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 Municipal Power Agency Number 1 as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America As discussed in note B to the financial statements, the Agency changed its method of accounting for derivative financial instruments in 2001 Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplementary information included in the Schedules of Revenues and Expenses per Bond Resolution and Other Agreements and Schedules of Changes in Assets of Funds Invested is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures apphed in the audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.
Raleigh, North Carolina March 29, 2002 2001 Annual Report 1 19
AC1'jV7; S heets Assets
"* Electric Utility Plant Electric plant in service, net of accumulated depreciation of $601,818 and $562,787 Construction %N ork in progress Nuclear fuel, net of accumulated amortization of $101,233 and $81,266
"* Non-Utility Property and Equipment, net
"* Special Funds Invested (Notes C and E).
Bond fund Reserve and contingency fund Special reserve fund
"* Trust for Decommissioning Costs (Notes D and E)
"* Operating Assets Funds invested (Notes C and E)
Revenue fund Operating fund Supplemental fund Participant accounts receivable Operating accounts receivable Prepaid expenses Denvatie financial instruments (Note B)
"* Deferred Costs Unamortized debt issuance costs Costs of advance refundmgs of debt Costs to be reco~ered from future billings to participants (Note D)
See accompan)iing noteo fioinancal statements 20 2001 Annjal Report tC)cj (SOOOs) 2001 December 31, 2000
$ 844,504 12,952 41,830 899,286
$ 887,345 4,551 46,648 938,544 2,108 2,180 319,704 20,270 1,104 341,078 128,263 318,661 17,229 1,028 336,918 119,769 251,680 91,759 143,055 486.494 19,280 2,677 39,025 12,149 559,625 33.715 254,745 439.400 727 860
$2,658,220 249,769 109,418 150,614 509,801 19,905 5,996 39,157 574,859 35,758 277,712 430,594 744,064
$2,716,334
n fVl© Sheets (Sooos)
December 31, Liabilities and Retained Earnings
"* Long-Term Debt Bonds, net of unamortized discount (Note E)
"* Special Funds Liabilities:
Construction payable Current maturities of bonds (Note E)
Accrued interest on bonds
"* Liability for Decommissioning Costs
"* Operating Liabilities:
Accounts payable Accrued taxes
"* Deferred Revenues (Note D)
"* Commitments and Contingencies (Note F)
"* Retained Earmngs 2001 Annual Report 1 21 2001 2000
$2,105,735
$2,051,926 3,100 59,508 57,858 120,466 117,553 59,448 62,273 121,721 103,600 11,660 13,382 25,042 1,952 14,480 16,432 335,833 361,446 7,400
$2,658,220 7,400
$2,716,334
Statements of And Changes in Retained Earnings (SO00s) 4:t7 An 1i1 )
- Operating Revenues Sales of electricity to participants Sales of electncity to utilities Other rexenues (Note G)
"* Operating Expenses Operation and maintenance Nuclear fuel Interconnection sen ices:
Purchased power Transmission and distribution Other AdministratiNe and general Gross receipts and excise taxes Property tax Depreciation
"* Net Operating Income
"* Interest Charges (Credits)
Interest expense Amortization of debt refunding costs Amortization of debt discount and issuance costs Gain on redemption of bonds Net increase in fair value of investments and derivative financial instruments Investment income
"* Net Cost to be Recovered From Future Billings to Participants (Note D)
"* Revenues (Under) Over Expenses Before Cumulative Effect of a Change in Accounting Principle
"* Cumulative Effect of a Change in Accounting Principle (Note B)
"* Excess of Revenues Over Expenses
"* Retained Earnings, Beginning of year
"* Retained Earnings, End of year See accomnp;anvng note v to financial statements 22 2001 Anqual Report 2001 Year Ended December 31, 2000
$261,921 55,759 7,266 324,946 83,348 27,286 45,730 14,109 134 59,973 30,851 10,968 12,920 51,233 276,579
$261,063 62,616 775 324,454 76,708 26,505 49,766 11,225 113 61,104 29,584 11,188 12,518 50,069 267,676 56,778 117,123 22,967 7,743 (6,823)
(42,463) 98,547 34,419 (7,350) 7,350 0
7,400 7,400 48,367 123,028 23,606 7,583 (43)
(35,406)
(48,612) 70,156 21,789 0
0 7,400 7,400
Statements of
($ooos)
Year Ended December 31,
" Cash Flows from Operating Activities Receipts from sales of electricity Receipts from other revenues Payments of operating expenses Net cash provided by operating activities
" Cash Flows from Capital and Related Financing Activities:
Interest paid Additions to electric utility plant and non-utility property and equipment Bonds retired Net cash used for capital and related financing activities
"* Cash Flows from Investing Activities.
Sales and maturities of investment securities Purchases of investment securities Investment earnings receipts from non-construction funds Net cash provided by investing activities
"* Net Increase (Decrease) in Operating Cash
- Operating Cash, Beginning of year
"* Operating Cash, End of year See accompanying notes to financial statements.
2001 Annual Report 123 2001 2000 327,907 775 (181,696) 146,986 (121,538)
(30,859)
(59,448)
(211,845) 9,490,720 (9,466,442) 40,585 64,863 315,463 7,266 (204,420) 118,309 (118,286)
(29,122)
(55,283)
(202,691) 7,412,283 (7,374,575) 46,645 84,353 4
(29) 1 5
30 1
NI I,
(>
10 3o t., i]r
}.
($OOOs)
Year Enided Deaember 31, 2001
- Reconciliation of Net Operating Income to Net Cash Provided by Operating Activities Net Operating Income Adjustments:
Depreciation Amortization of nuclear fuel Changes in assets and liabilities:
Decrease (increase) in participant accounts receivable Decrease (increase) in operating accounts receivable Decrease in prepaid expenses Increase (decrease) in accounts payable (Decrease) increase in accrued taxes Total Adjustments Net Cash Pro-ided by Operating Actix ities
$ 56,778 50,069 26,505 625 3,319 132 10,656 (1,098)
S 48,367 51,233 27,286 (617)
(1,908) 1,709 (8,239) 478 90,208
$146,986
$118,309 See accompanying notev tofinancial statements 24 2001 Annjal Reoort 2000 69,942
Rao+/- to Financial Statements Years Ended December 31, 2001 and 2000 A. GENERAL MATTERS North Carolina Municipal Power Agency Number 1 (Agency) is ajoint agency organized and existing pursuant to Chapter 159B of the General Statutes of North Carolina to enable municipalities owning electric distribution systems, through the organization of the Agency, to finance, construct, own, operate, and maintain electric generation and transrrUs sion facilities. The Agency has nineteen members (participants) with interests ranging from 0 0869% to 18.9600%, which receive power from the Agency The Project The Agency has entered into several agreements with Duke Energy Corporation (Duke) which govern the purchase, ownership, construction, operation, and maintenance of the project.
The Purchase, Construction, and Ownership Agreement provides, among other things,for the Agency to purchase a 75%
undivided ownership interest in Unit 2 of the Catmaba Nuclear Station (station) and a 37.5% undivided ownership interest in certain support factlities of the station (project)
However bY' virtue of various provisions in the Interconnection Agreement and the Operation and FuelAgreement, the Agency (1) bears the costs of acquisition, construction, operation, and maintenance of 37.5% of Unit I and 37.5% of Unit 2, and (2) has the same proportionate right to the output of and bears the risks associated with the lack of operation of such units.
The Interconnection Agreement provides for the interconnection between Duke's electric power system and the Agency's project andfor the exchange of power between Unit I and Unit 2 of the station and between the Catawba wuits and Duke's McGuire Nuclear Station. The agreement also provides for the purchase and sale of capacity and energy, and the transmis sion of energy to the Agency's participants As part of the Interconnection Agreement, the Agency agreed to sell back to Duke, on a take-or-pay basis, capacity from each Catawba unit in decreasing amounts In calendar years 2001 and 2000, the Agency retained 100 percent and approximately 98percent, respectivel, of the Agency's share of the station's aggregate available capadity On January 1, 2001, the sell back arrangement terminated The Operation and Fuel Agreement provides for Duke to operate, maintain, and fuel the station, to make renewals, replacements, and capital additions as approved by the Agency,; andfor the ultimate decommissioning of the station at the end of its usefid life.
The Agency's acquisition of its ownership interest is being financed by electnc revenue bonds pursuant to Resolution No. R-16-78, as amended, (resolution) of the Board of Commissioners of the Agency. The resolution established special funds to hold proceeds from debt issuance, such proceeds to be used for costs of acquisition and construction of the project, and to establish certain reserves. The resolution also established special funds in which project revenues are deposited and from which project operating costs, debt service, and other specified payments relating to the project are made.
The Agency has entered into a Project Power Sales Agreement and a Supplemental Power Sales Agreement with each participant These agreements provide for each participant to purchase from the Agency its all-require ments bulk power supply, in excess of power allotments from the Southeastern Power Administration (SEPA), which includes its total share of project output (as defined by the Project Power Sales Agreement) The Agency is obligated to provide all electrc power required by each participant at the respective delivery points. Each participant is obligated to pay its share of the operating and debt service costs of the project.
The Agency's participants receive their total electric power, exclusive of power allotments from SEPA, from the Agency Such power is provided by project output together with supplemental purchases of power. In accordance with an agreement between the Agency and Duke, beginning January 1, 2001, the Agency began making its supplemental purchases from another source To meet its supplemental power requirements, the Agency has entered a five year contract with Georgia Power Company for the purchase of 125 MW. In addition, the Agency purchased 100 MW from two suppliers for June through August.
Pursuant to two "Reliability Exchanges" contained in the Interconnection Agreement, project output is provided in essentially equal amounts from Catawba Unit 2 and three other nuclear units (Catawba Unit 1, McGuire Unit 1, and McGuire Unit 2) in operation on the Duke system, all of similar size and capacity. The reliability exchanges are intended to make more reliable the supply of capacity and energy to the Agency in the amount to which the Agency is entitled pursuant to its ownership interest in Catawba Unit 2, and to mitigate potential adverse economic effects on 2001 Annual Report 1 25
(conmtinm eci the Agency and the participants from unscheduled outages of Cata\\x ba Unit 2.
Correspondingly, the Agency bears nsls resulting from unscheduled outages of any Cata\\x ba or McGuire Unit ElectriCities of North Carolina, Inc.
ElectnCities of North Carolina, Inc (ElectriCities), organized as ajoint municipal assistance agency under the General Statutes of North Carolina, is a public body and body corporate and politic created for the puipose of proiding aid and assistance to municipalities in connection \\N ith their electnc systems and to joint agencies, such as the Agency The Agency has entered into a management agreement with ElectriCities Under the current management agreement, ElectriCities is required to provide all personnel and personnel sen ices necessary for the Agency to conduct its business in an economic and efficient manner Industry Restructuring Developments and Related Uncertainties Federal regulations have been passed which encourage N%
holesale competition among utility and non-utility power producers Similar regulations ar contemplated for retail competition at both the federal and state level However, because of other states' experiences with deregulation, momentum has slowed siggificantly m North Carolina.
In 1997, the North Carolina General Assembly created the "'Study Commission on the Future of Elector Service in North Carolina" (Study Commission) The Study Commission is compnsed of 30 members, representing lawmakers, the North Carolina municipal, coopemtix e, and private electnc utilities, electric consumers, the environmental community, and electric powA er marketers. The Study Commission is charged ýk ith examining the cost, adequacy, availability, and pricing of electric rates and service in North Carolina to detemiine whether legislation is necessary to assure an adequate and reliable source of electncity and economical, fair, and equitable rates for all consumers of electricity in North Carolina After much discussion and negotiations, the Study Commission presented a report to the General Assembly in May 2000 which included recommendations for full retail choice no later that January 1, 2006 with fifty percent of each power supplier's customer load ha ing the option of retail choice on January 1, 2005 The report indicated that the Study Cominus sion would then make recommendations on how to address other aspects of deregulation such as stranded costs recovery, the Agency's debt, consumer protection, environment and altemative energy, tax laws, transmission and distribution, and any other areas xx hIch need to be addressed In early 2001, the Study Commission determined that because of Califomia's circumstances, North Carolina would take a "go slow" attitude toward deregulation No recommendations were made to the General Assembly dunng 2001 and none are antici pated in 2002 Because the Study Commission does not intend to make any recommendation to the General Assembly dunng 2002, and because the General Assembly is not bound by the work of the Study Commission, and because other entities are able to propose legislation on this issue, the Agency cannot predict NN hether there NN ill be any legislative initiatiN es, xx hat the results of legislative initiatives will be, or hether any such legislation will become law The Board of Commissioners of the Agency, in conjunction %N ith the Board of Directors of ElectnCities of North Carolina, Inc, has developed a strategic plan to address deregulation In addition, the Agency periodically reviews its regulatory assets and the impact of recovenng such assets on Agency rates Also, the Agency's manage ment and Board are participating in the deregulation debate, both on the national and state levels For further discussion about deregulation and the possible effects on rates and deferred expenses, see Note D B. SIGNIFICANT ACCOUNTING POLICIES Basis of Accounting The accounts of the Agency are maintained on the accrual basis, in accordance xx ith the Unifomi System of Accounts of the Federal Energy Regulatory Commission, and are in conformity with accounting principles generally accepted in the United States of America (GAAP) The Agency has adopted the pnnciples promulgated by the Govern mental Accounting Standards Board (GASB) and Statement of Financial Accounting Standard (SFAS) No 71 "Accounting for the Effects of Certain T* pes of Regulation:' as amended. This standard allows utilities to capitalize or defer certain costs and/or revenues based upon the Agency's ongoing assessment that it is probable that such items will be recovered through future revenues.
In the future, issues of competitive market forces and restructuring in the electoc utility industry might require the reduction in the carrying value of the Agency's regulatory assets unless appropriate action is taken to 26 2001 Anrvjal Report 7-3
[k~Qe (continued) assure the recovery of these regulatory assets, even in a market environment.
Financial Reporting Under GASB Statement No. 20, "Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities that Use Proprietary Fund Accounting,"
the Agency has adopted the option to apply Financial Accounting Standards Board (FASB) statements and interpretations that do not conflict with or contradict GASB pronounce ments Electric Plant in Service All expenditures associated with the development and construction of the Agency's ownership interest in the Catawba station, including interest expense net of investment income on funds not yet expended, have been recorded at original cost and are being depreciated on a straight-line basis over the average composite life of each unit's assets. At December 31, 2001, the remaining composite average life for Catawba's assets was 18 years.
Original costs of major classes of the Agency's electric plant in service at December 31, 2001 and 2000 are shown in the chart at right.
Construction Work in Progress All expenditures related to capital additions are capitalized as construction work in progress until such time as they are completed and transferred to Electric Plant in Service. No interest is capitalized on capital additions.
Depreciation expense is recognized on these items after they are transferred Nuclear Fuel All expenditures related to the purchase and construction of nuclear fuel cores are capitalized until such time as the cores are placed in the reactor. No interest is capitalized on fuel cores When placed in the reactor, they are amortized and charged to fuel expense on the units of production method. Amounts are removed from the books upon disposal of the spent nuclear fuel. Nuclear fuel expense includes a provision for estimated spent nuclear fuel disposal costs which is being collected currently from members. Amortization of nuclear fuel costs includes estimated disposal costs of $6,544,000 and $6,357,000 for the years ended December 31, 2001 and 2000, respectively.
The Energy Policy Act of 1992 established a fund for the decontamination and decommis sioning of the Department of Energy's (DOE) uranium ennchment plants. Nuclear plant licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services Duke makes the annual Electric Plant In Service ($O00s)
S Land Structures and improvements Reactor plant equipment Turbo generator units Accessory electric equipment Miscellaneous plant equipment Station equipment Unclassified
- Accumulated depreciation payment to DOE for the Catawba station and bills the co-owners monthly for their proportion ate share. The Agency's payments to Duke were approximately $870,000 and $843,000 in 2001 and 2000, respectively, and were recorded as fuel expense.
Under provisions of the Nuclear Waste Policy Act of 1982, Duke, on behalf of all co owners of the Catawba station, has entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent nuclear fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and Duke's contract with the DOE. In 1998, Duke, on behalf of all co-owners, filed a claim with the United States Court of Federal Claims against the DOE for damages arising out of the DOE's failure to begin accepting the spent nuclear fuel Claimed damages are intended to recover costs incurred and to be incurred as a result of the DOE's partial material breach of its December 31, 2001 19,768 384,096 593,955 165,145 123,497 48,690 10,959 100,212 1,446,322 (601,818)
$ 844,504 2000 19,768 389,198 594,893 165,145 123,576 48,731 10,959 97,862 1,450,132 (562,787)
$ 887,345 Unclassified assets are in service but not yet classified to specific plant accounts.
2001 Annual Report 1 27
N contract, including costs associated with securing additional spent fuel storage capacity Non-Utility Property and Equipment Expenditures related to purchasing and installing an in-house computer, jointly owned with North Carolina Eastern Municipal Power Agency (NCEMPA), haxe been capitalized and are fully depreciated In addition, the Agency has purchased vanous computer equipment for its load management and telemetry programs,
", hich are being depreciated oxer the estimated useful life of the equipment Also included are the land and administratixe office building jointly owned with NCEMPA and used by both agencies and ElectnCities. The administrative office building is being depreciated over 37 1/2 years on a straight-line basis Non-Utility Property and Equipment onginal costs at December 31, 2001 and 2000 are shom% n in the chart beloxx.
Investments The Agency implemented the provisions of GASB Statement No 3 1, "Accounting and Non-Utility Property and Equipment ($O00s)
"* Land
"* Structures and improvements
"* Computer equipment
"* Telemetry equipment
"* Accumulated depreciation Financial Reporting for Certain Investments and for External Investment Pools," xx hich requires investments in marketable debt secunties to be reported at fair value.
Derivative Financial Instruments In June 1998, the FASB issued SEAS No 133, "Accounting for Denvative Instruments and Certain Hedging Activities" (SFAS No 133). In June 2000, the FASB issued SFAS No 138, "Accounting for Certain Denvauie Instruments and Certain Hedging Activities, an Amendment of SEAS 133" (SFAS No 138)
SFAS No. 133 and SEAS No 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values.
SEAS No 133 and SFAS No 138 are effective for all fiscal years beginning after June 30, 2000 The Agency adopted SEAS No. 133 and SEAS No 138 on January 1, 2001 In accordance with the transition provisions of SFAS No 133, the Agency recorded a cumulative-effect-adjustment of $7,350,000 in the statement of revenues and expenses to recognize at fair value all denvatives outstanding at that date December31, 2001
$ 710 1,499 1,000 745 3,954 (1,846)
$ 2,108 2000 710 1,499 998 645 3,852 (1,672)
$ 2,180 All derivatives are recognized on the balance sheet at their fair value estimated based on current market pricing models The Agency has not designated any of its denvatives as hedges Changes in the fair value of derivative instruments are reported in current-penod revenues and expenses For the year ended December 31, 2000, prior to the adoption of SFAS No. 133, the Agency entered into interest rate swap agreements For interest rate swaps, fair value
\\Nhich would be paid or received if the swap were terminated is accrued and recognized in
'Net increase in fair valuc of investments and denvative financial instruments" and may change as market interest rates change. If a swap contract is terminated pnor to its matunty, the gain or loss is recognized immediately.
The Agency has only limited involve ment xx ith den\\ati\\ e financial instruments In December 1999, the Agency entered into an interest rate swap agreement wvith a temlnation date of December 2009 The Agency's objective for entenng into the interest rate swap 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 rate of 4.984% through December 2009, \\Nhile paying a variable rate based on the BMA Municipal Swap Index Interest paid and receix ed under the swap agreement increases and decreases, respectively, interest expense The net effect was to reduce interest expense by $4,674,000 and $1,706,000 in 2001 and 2000. respectiely The notional anmount of this agreement is $200,600,000 The fair value of the interest rate swap 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 models were used to estimate the fair value of the interest rate swap agreement. The fluctuation in the fair value of the interest rate swaps was an increase of $4,799,000 in 2001 and is included in "Increase in fair value of investments and derivative financial instruments" in the statement 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 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 nsk associated with interest-rate contracts is managed by establishing and monitonng parameters that limit the types and degree of market risk that may be undertaken.
Decommissioning Costs U S. Nuclear Regulatory Commission (NRC) regulations require that each licensee of a commercial nuclear power reactor furmish to the NRC certification of its financial capability to meet the costs of nuclear decommissioning at the end of the useful life of the licensee's facility.
As a co-licensee of Catawba Unit 2, the Agency is subject to these requirements and therefore has furmshed certification of its financial capability to fund its share of the costs of nuclear decommissioning of the Catawba Station.
To satisfy the NRC's financial capability regulations, the Agency established an external trust fund (the Decommissioning Trust) pursuant to a trust agreement with a bank. The Agency's certification of financial capability requires that the Agency make annual deposits to the Decommissioning Trust which, together with the investment earnings and amounts previously on deposit in the trust, are anticipated to result in sufficient funds being held in the Decommissioning Trust at the expiration of the current operating licenses for the Catawba Units (currently 2024 for Unit I and 2026 for Unit 2) to meet the Agency's share of decommissioning.
Estimates of the future costs of decommis sioning the units are based on the most recent site specific study which was conducted in 1999. The Agency's portion of decommission ing costs, including the cost of decommission ing plant components not subject to radioactive contamination, is $355,690,000, stated in 1999 dollars.
The Decommissioning Trust is irrevocable and funds may be withdrawn from the trust solely for the purpose of paying the Agency's share of the costs of nuclear decommissioning Under the NRC regulations, the Decommission ing Trust is required to be segregated from Agency assets and outside the Agency's administrative control. The Agency is deemed to have incurred and paid decommissionig costs as deposits are made to the Decommissioning Trust. In addition to the Decommissioning Trust certain reserve assets are anticipated to be available to satisfy the Agency's total decom missioning liability 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 value of an asset retirement 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 adjust ments for changes in the estimated future cash flows will also be capitalized and amortized over the remaining life of the asset. Manage ment is currently evaluating what impact, if any, SFAS No 143 will have on the Agency's financial statements.
In August 2001, the FASB issued SFAS No 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No.
144) Effective for fiscal year 2002, SFAS No 144 addresses financial accounting and reporting for the impairment or disposal of long lived assets and supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of'. SFAS No. 144 states the required accounting for disposing of long-lived assets whether previously held and used or newly acquired, and broadens the presentation of discontinued operations to include more disposal transactions. The implementation of SFAS No. 144 is expected to have no material impact on the Agency's financial position or results of operations.
2001 Annual Report 1 29
Nuclear Relicensing In June 2001, Duke filed an applicafion with the NRC to renew the operating license for the Cataxsba units.
Deferred Costs Unamortized debt issuance costs, shown net of accumulated amortization of
$13,205,000 and $11,161,000 at December 3 1, 2001 and 2000, respectiely, are being amortized on the interest method over the term of the related debt. Costs of advance refundings of debt, shown net of accumulated amortization of $178,597,000 and
$155,630,000 at December 31, 2001 and 2000, respectively, are deferred and amortized over the term of the debt issued on refunding.
Deferred revenues and costs to be recovered from future billings to participants aam not amortized but A ill be either refunded to or recoN ered from participants through future rates (See Note D)
Discounts on Bonds Discounts (net of premiums) on bonds, shown net of accumulated amortization of
$46,888,000 and $41,189,000, at December 31, 2001 and 2000 respectively, are amortized over the tenns of the related bonds in a manner which yields a constant rate of interest Taxes Income of the Agency is excludable from federal income tax under Section 115 of the Internal Rex enue Code. Chapter 159B of the General Statutes of North Carolina exempts the Agency from property and franchise or other pnvilege taxes In lieu of North Carolina property taxes, the Agency pays an amount
%x hich would otherx ise be assessed on the non utility property and equipment of the Agency In lieu of a franchise or prix ilege tax, the Agency pays to North Carolina an amount equal to 3 22% of the gross receipts fmm sales of eleetnctty to participants Electric utility property is located in South Carolina and subject to South Carolina property tax An electric power excise tax equal to 05% (5/10 mill) for each kilowatt-hour of electrc power sold for resale within South Carolina is also paid Statements of Cash Flows For purposes of the statements of cash flows, operating cash consists of unrestricted cash included in the line item on the balance sheets "operating assets funds invested" Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses dunng the reporting period-Actual results could differ from those estimates Reclassifications Certain 2000 amounts hax e been reclassified to conform with 2001 classifications The reclassifications had no effect on excess of revenues over expenses or retained earnings as previously reported C. INVESTMENTS The resolution authonzes the Agency to invest in 1) direct obligations of, or obligations of m hich the principal and interest are unconditionally guaranteed by the United States (U S ), 2) obligations of any agency of the U S or corporation wholly owned by the U S, 3) direct and general obligations of the State of North Carolina or any political subdivision thereof %N hose secunties are rated
"-A' or better, 4) repurchase agreements %%
ith the Bond Fund Trustee, Construction Fund Trustee, or any govemment bond dealer reporting to the Federal Reserve Bank of New York xs hIch mature Nx ithin nine months from the date they were entered into and are collateralized by preN iously descnbed obligations, and 5) bank time deposits evidenced by certificates of deposit and bankers' acceptances.
Bank time deposits may only be in banks N%
ith capital stock, surplus, and undix ided profits of $20 000,000 or
$50,000,000 for North Carolina banks and out-of-state banks, respectively, and the Agency's investments deposited in such banks cannot exceed 50% and 25%,
respectively, of such banks' capital stock, surplus, and undivided profits The resolution permits the Agency to establish official depositones x ith any bank or trust company qualified under the laws of North Carolina to receive deposits of public moneys and ha\\ ing capital stock, surplus, and undivided profits in excess of $20,000,000 All depositories must collateralize public deposits in excess of federal depository insurance coverage The Agency's deposito nes use the pooling method, a single financial institution collateral pool. Under the pooling method, a depository establishes a single escrow account on behalf of all governmental agencies. Collateral is maintained with an eligible escrow agent in the name of the State Treasurer of North Carolina based on an approx ed averaging method for demand 30 2001 Annual Repod
->1(conf' ed)
RaJQ (continued) deposits and the actual current balance for time deposits less the applicable federal depository insurance for each depositor. Responsibility for sufficient collateralization of these excess deposits rests with the financial institutions that have chosen the pooling method. Because of the mabihty to measure the exact amount of collateral pledged for the Agency under the pooling method, the potential exists for under collateralization. However, the State Treasurer enforces strict standards for each pooling method depository, which minimizes any risk Investments ($O00s) of under-collateralization At December 31, 2001 and 2000 the Agency had $6,000 and
$100,000, respectively, covered by federal depository insurance.
The Agency's investments are categorized to give an indication of the level of nsk assumed by the Agency at year-end Category 1 includes investments that are insured or registered or for which the securities are held by the Agency or its agent in the Agency's name. Category 2 includes uninsured and unregistered investments for which the December 31, 2001 Cost Basis Market Value securities are held by the broker or dealer, or by its trust department or agent in the Agency's name. Category 3 includes uninsured and unregistered investments for which the securities are held by the broker or dealer, or by its safekeeping department or agent, but not in the Agency's name. All investments, except repurchase agreements, are considered Category 1. Repurchase agreements are considered Category 3. The Agency's investments are detailed in the chart below.
December 31, 2000 Cost Basis 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 accordance with the provisions of the resolution, the collateral under the repurchase agreements is segregated and held by the trustee for theAgency 2001 Annual Report 1 31
-5
.1 Costs to be Recovered from Future Billings to Participants ($O00s)
"* Net deferred interest
"* Amortization of debt discount and issuance costs
"* Depreciation
"* Amortization of debt refunding costs
"* Participant billing offsets
"* Increase in fair value of investments and denvative financial instruments
"* Training costs Deferred Revenues ($O00s)
"* Net special funds (withdrawals)/deposits
"* Restricted investment income
"* Rate stabilization funds used for other than operations
"* Special funds excess valuations Net Costs to be Recovered from Future Billings to Participants ($O00s)
D. COSTS TO BE RECOVERED FROM FUTURE BILLINGS TO PARTICIPANTS AND DEFERRED REVENUES Rates for power billings to participants are designed to cover the Agency's debt requirements, operating funds, and reserves as specified by the resolution and power sales agreements Straight-line depreciation and amortization are not considered in the cost of service calculation used to design rates In addition, certain earnings on bond resolution funds are restrcted to those funds and not Year Ended December 31, 2001 (161) 7,743 50,069 22,967 (57,639)
(14,173)
$ 8,806
$(44,977) 19,364
$(25,613)
$34,419 2000 (741) 7,583 51,233 23,606 (56,213)
(35,406)
$ (9,938)
$(53,044) 21,317
$(31,727)
$21,789 available for operations The differences between debt principal maturities (adjusted for the effects of premiums, discounts, and amortization of deferred gains and losses) and straght-line depreciation and amortization and interest income recognition are recogmzed as costs to be recovered from future billings to participants. Funds collected through rates for reserve accounts and restricted investment income are recognized as deferred revenues.
The Agency's present charges to the participants, together with planned withdrawals from the Rate Stabilization Fund and Inception to December 31, 2001 2000
$153,689 88,782 727,129 243,627 (748,187)
(32,336) 6,696
$439,400
$103,431 357,188 (121,840)
(2,946)
$355,833
$153,850 81,039 677,060 220,660 (690,548)
(18,163) 6,696
$ 430,594
$148,408 337,824 (121,840)
(2,946)
$ 361,446 Supplemental Reserve Account, are sufficient to recover all of the Agency's current annual costs of the participants' bulk poNser needs.
Each participant is required under the power sales agreements to set its rates for its customers at le% els sufficient to pay all its costs of its electric utility system, including the Agency's charges for bulk power supply. All participants have done so In a deregulated electric utility industry, the participants can expect to have as their major competition the investor-owned utilities (IOUs) and rural electnc cooperatives presently 32 2001 AnnuA ReIoo
R5@Qa (continued) operating in North Carolina and power marketers and others that begin serving North Carolina retail customers after deregulation The participants' retail electric rates are higher, on average, than the retail electric rates of the IOUs currently serving North Carolina.
Agency studies indicate that in a market environment, the participants may not be able to charge rates sufficient to meet their obligations to the Agency as well as cover the costs of their distribution systems This would give rise to stranded investments of the Agency and the need for stranded investment recovery in a deregulated environment The Agency expects that the methods by which it will recover some or all of its stranded investments will come from the legislative initiatives discussed in Note A.
However, no assurances can be given that the Agency will be able to recover, in pail or m whole, these stranded investments.
All rates must be approved by the Board of Commissioners Rates are designed on an
- Bonds Outstanding at December 31,2000
- Principal payments January 1, 2001
- Bonds Outstanding at December 31, 2001 annual basis and are reviewed quarterly. If they are determined to be inadequate to cover the Agency's current annual costs, rates may be revised.
The recovery of outstanding amounts associated with costs to be recovered from future billings to participants will coincide with the retirement of the outstanding long-term debt of the Agency barring a change in regulation. A change in regulation could directly affect the recoverabihty of these costs, resulting in impairment of these assets and reexamination of these assets in accordance with SFAS No 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of' (SPAS No 121). The Agency follows the accounting requirements of SFAS No. 121. This statement requires the long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable This statement also imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. Upon adoption, and to date, SIAS No. 121 has had no effect on the Agency's financial position See discussions of SFAS No. 144 at Note B, Recently Issued Pronounce ments.
E. BONDS The Agency has been authorized to issue Catawba Electric Revenue Bonds (bonds) in accordance with the terms, conditions, and limitations of the resolution. The total to be issued is to be sufficient to pay the costs of acquisition and construction of the project, as defined, and/or for other purposes set forth in the resolution. Future reftindlngs may result in the issuance of additional bonds The following shows bond activity during 2001.
$ 2,271,884,000 (59,448,000)
$ 2,212,436,000 The various issues comprising the outstanding debt are as follows (in thousands of dollars)"
"* Series 1985B 6% matunng in 2020 with annual sinking fund requirements beginning in 2018
"* Series 1988 Zero coupon priced to yield 7.5% to 7.6% maturing annually from 2002 to 2003
"* Series 1990 6.8% to 6.9% maturing annually from 2002 to 2003 Zero coupon priced to yield 6 75% maturing in 2004 7% maturing in 2014 December 31, 2001
$80,575 5,526 4,515 3,670 10,225 18,410 2000
$80,575 8,289 5,680 3,670 10,225 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 "Series 1993 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)
December 31,
- Series 1999A 5.75% to 6% maturing annually from 2007 to 2010
- Series 1999B 6.125% to 6 625% maturing annually from 2006 to 2010 6.375% maturing in 2013 with annual sinking fund requirements beginning in 2011 6.5% maturing in 2020 with annual sinking fund requirements beginning in 2014 Less:
Current matunties of bonds Unamortized discount The table on page 36 is a sunimary of debt service requirements for bonds outstanding at December 31, 2001 and reflects principal debt service included in the designated year's rates. In accordance with the resolution, these moneys are deposited into the Bond Fund for payment of the following year's current maturities. Current maturities of $59,508,000 at December 31, 2001 were collected through rates dunng 2001 and deposited monthly into the Bond Fund to make the January 1,2002 principal payment.
The fair market value of the Agency's long-tenm debt was estimated using a yield curve derived from December 31, 2001 and 2000 market prices for similar securities Using these yield curves, market pnces were estimated to call date, to par call date, and to maturity. The lowest of the three prices was used as the estimated market price for each individual maturity and the individual maturities were summed to arrive at a fair market value of
$2,249,935,000 and $2,288,589,000 at December 31, 2001 and 2000, respectively.
Certain proceeds of the Series 1984 (subsequently paid at maturity or refunded),
1985B, 1988,1990, 1992, 1993, 1995A, 1997A, 1998A, and 1999A bonds were used to establish trusts for advance refunding of
$3,417,280,000 of previously issued bonds At December 31, 2001, $3,137,470,000 of these bonds have been redeemed. Under these Refunding Trust Agreements, obligations of, or guaranteed by, the United States have been placed in irrevocable Refunding Trust Funds maintained by the Bond Fund Trustee. The government obligations in the respective Refunding Trust Funds along with the interest earnings on such obligations, will be sufficient to pay all interest on the refunded bonds when due and to redeem all refunded bonds at various dates prior to their original maturities, in amounts ranging from par to a maximum redemption price of 102%. The monies on deposit in each Refunding Trust Fund, including the interest earnings thereon, are pledged solely for the benefit of the holders of the refunded bonds Since the establishment of each Refunding Trust Fund, the refunded bonds are no longer considered outstanding obligations of the Agency.
Interest on the bonds is payable semi annually. Certain of the following bonds are subject to redemption pnor to maturity at the option of the Agency, on or after the following dates at a maximum of 102% of the respective principal amounts:
Series 1985B Series 1990 Series 1992 and 1993 Series 1995A Series 1997A Series 1998A Series 1999B January 1, 1996 January 1, 2000 January 1, 2003 January 1, 2006 January 1, 2007 January 1, 2008 January 1, 2010 The bonds are special obligations of the Agency, payable solely from and secured solely by (1) project revenues (as defined by the resolution) after payment of project operating expenses (as defined by the resolution) and (2) other monies and securities pledged for payment thereof by the resolution 2001 Annual Report 1 35 2001 2000 83,340 54,035 33,585 112,980 200,600 2,212,436 59,508 101,002
$2,051,926 83,340 54,035 33,585 112,980 200,600 2,271,884 59,448 106,701
$2,105,735
I
)! I i Debt Service Deposit Requirements for Bonds (SO00s)
Year
- 2002
- 2003
- 2004
- 2005
- 2006
- 2007
- 2008
- 2009
- 2010
- 2011
- 2012
- 2013
- 2014
- 2015
- 2016
- 2017
- 2018
- 2019 Total Principal 64,323 68,280 70,665 87,135 93,075 98,205 102,565 107,195 112,500 118,520 125,165 132,460 139,775 148,210 156,655 165,880 176,010 186,310
$2,152,928 Interest*
$ 115,419 111,917 108,211 104,285 98,483 92,648 88,509 86,664 81,834 76,051 69,795 62,762 55,208 47,466 39,039 30,569 20,598 10,302
$1,299,760 Total
$ 179,742 180,197 178,876 191,420 191,558 190,853 191,074 193,859 194,334 194,571 194,960 195,222 194,983 195,676 195,694 196,449 196,608 196,612
$3,452,688
- Assumes a 4 97% interest rate for the 1999B SWAP The resolution requires the Agency to deposit into special funds all proceeds of bonds issued and all project revenues (as defined by the resolution) generated as a result of the Project Power Sales Agreements and Interconnection Agreement The purpose of the individual funds is specifically defined in the resolution F. COMMITMENTS AND CONTINGENCIES ElectriCities The Agency has a contractual agreement with ElectnCities %x hereby ElectnCities provides, at cost, general management sen ices to the Agency This agreement continues through December 31 2004, and is automati cally renewed for successive three-year penods unless temuinated by one year's notice by either party pnor to the end of the contract temi For the years ended December 31, 2001 and 2000, the Agency paid ElectnCities
$4,867,000 and $4,801,000, respectively Insurance The Price-Anderson Act limits the public liability for a nuclear incident at a nuclear genera unit to S9540,000,000, xx hich anlount is to be covered by private insurance and agreements of indemnity with the NRC.
Such pnvate insurance and agreements of indemnity are carried by Duke on behalf of all co-oNN nets of the station The temis of this coverage require the ow ners of all licensed facilities to prox ide up to $88,100,000 per year per unit owned (adjusted annually for inflation) in the ex ent of any nuclear incident invok ing any licensed facility in the nation, x iLth an 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 in light of uncertainty regarding the potential effect of electnc industry restructuring legislation which might be enacted Thus, the Agency disapproved the capital project in accordance 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 in 2001 and 2000, respectively, which were received from Duke in settlement of arbitration issues.
2001 Annual Report 1 37
(I> NI K9K 'j In Assets of Funds Invested (SO00s)
Bond Fund Interest account Reserve account Pnncipal account Resewne & Contingency Fund Special Reserve Fund Revenue Fund:
Revenue account Rate stabilization account Operating Fund Working capital account Fuel account Supplemental Fund:
Supplemental account Supplemental reserxe account 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 December 31, 2001 and 2000, revpectvelv See a compan ing independent Audttorv' Report 38 2001 Anqial Report
\\(
\\
f 1y
Funds Ini ested Jan 1, 2000
$ 55,537 194,896 55,417 305,850 Po*i er Billing Receipts 0
0 Inve*izent Income
$1,894 12,450 1,845 16,189 D sbu sements
$(119,925)
(55,138)
(175,063) 2,154 68 20,390 1,082 26,830 268,974 295,804 19,876 89,576 109,452 38,280 113,781 152,061
$884,639 220,533 220,533 0
40,518 40,518
$261,051 417 14,351 14,768 5,972 5,972 2,496 6,965 9,461
$48,612 3,081 3,081 (165.639)
(165,639)
(11,955)
(11,955)
$(349,576)
Schedules of @farng In Assets of Funds Invested (S000s)
Funds Power Invested Billing Investment Dec. 31, Receipts Income Disbursements Transfers 2001 0
$ 968
$(123,043)
$120,349
$ 60,870 12,227 (11,195) 197,058 911 (59,448) 58,369 59,615 0
14,106 (182,491) 167523 317,543 1,906 895 19,760 57 1,100 230,849 559 28,921 (226,638) 31,211 12,741 (46,680) 217,576 230,849 13,300 28,921 (273,318) 248,787 4,991 (158,690) 147,257 31,956 (12,442) 58,144 0
4,991 (158,690) 134,815 90,100 31,085 1,478 (18,754)
(21,618) 26,863 6,622 (8,297) 113,953 31,085 8,100 (18,754)
(29,915) 140,816
$261,934
$42,460
$(331,014) 0
$818,106 Note: The schedule above has been prepared in accordance with the underlying Bond Resolution, and accordingly, does not reflect the change in the fair value of investments as of December 31, 2001 and 2000, respectively See accompanying Independent Auditors' Report 2001 Annual Report 1 39 Funds Invested Dec. 31, 2000
$ 62596 196,026 59,783 318,405 16,959 1,043 Transfers
$125,090 (11,320) 57,659 171,429 (5,585)
(107)
(253,341)
(31,810)
(285,151) 178,189 (18,990 159,199 (34,667)
(5,118)
(39,785) 0 (2,480) 251515 249,035 38,398 70586 108,984 34,672 115,628 150,300
$844,726
0 _ý r
__A
¶ I 1'_'JiF2 7,)
'1
'
I.,
3/4, j
Per Bond Resolution and Other Agreements (SOOOs)
Year Ended December 31, 2001 Project Sipplemental Total Year Ended December 31, 2000 Ptvje t Supplemental Total Revenues:
Sales of electncity to participants
$ 228,752 Sales of electricity to utilities 62,616 Other revenues 661 Rate stabilization fund withdrawal 36,679 Fund valuations 14,210 Supplemental Reserve Fund withdrawal Investment revenue available for operations 21,562 364,480 Expenses:
Operation and maintenance Nuclear fuel Interconnection services Purchased pomer Transmission and distribution Other Administrati e and general - Duke Administrative and general -Agency Miscellaneous Agency expense Gross receipts and excise taxes Property tax Debt service 76,708 16,505 24,577 24,577 21,676 3,341 10,183 12,518 176,631
$ 32,311
$ 261,063 62,616 114 775 36,679 14,210 8,298 8,298 1.536 42,259 25,189 11,225 113 36,527 23,098 406,739 76,708 16,505 49,766 11,225 113 61,104 21,676 3,644 6,985 923 923 1,004 11,187 12,518 161 176,792
$ 230,130 55,759 7,210 45,850 14,681 24,732 378,362 83,348 17,286 24,271 24,271 22,367 3,762 9,937 12,920 183,025
$ 31,791
$ 261,921 55,759 56 7,266 45,850 14,681 7,194 7,194 2,563 41.604 21,459 14,109 134 35,702 27,295 419,966 83,348 17,286 45,730 14,109 134 59,973 22,367 3,907 7,669 815 815 1,031 10,968 12,920 149 183,174 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 prepared in accomdamue wtth the undelhying Bond Re sohmon, and a(i ordingl; doe s not meflet tIhe Uhange in the fair ahtme of mnvesuneti* as of De ember 31, 2001 and2000, respettively See ticc omnipa ing Independent Anmhtors 'Report 40 20C1 Annual Repcri
Statistical en Ytnce Nte Ten Years at a Glance (Unaudited)
"* Megawatt-hour Sales (MWh)
"* Peak Billing Demand (kW)
"* Operating Revenues
"* Excess of Revenues over Expenditures
"* Sales to Utilities (Revenues)
"* Average Monthly Power Purchases by Cities (MWh)
- Average Monthly Billings to Cities
"* Megawatt-hour Sales (MWh)
"* Peak Billing Demand (kW)
- Operating Revenues
"* Excess (Deficiency) of Revenues over Expenditures
"* Sales to Utihties (Revenues)
"* Average Monthly Power Purchases by Cities (MWh)
- Average Monthly Billings to Cities
- Includes $91,005,000 received in settlement of arbitration issues.
2001 Annual Report 1 41 2001 4,638,350 856,577
$324,454,000
$o
$62,616,000 386,529
$21,755,000 1996 4,221,890 829,245
$375,577,000
$0
$134,453,000 351,824
$19,942,000 2000 4,749,523 894,324
$324,946,000
$0
$55,759,000 395,794
$21,827,000 1995 4,125,029 803,615
$413,852,000
$0
$183,554,000 343,752
$19,077,000 1999 4,567,636 882,083
$347,476,000
$0
$85,097,000 380,636
$21,734,000 1994 3,950,370 752,717
$540,695,000*
$0
$237,153,000 329,198
$17,711,000 1998 4,496,603 842,892
$361,131,000
$0
$102,551,000 374,717
$21,439,000 1993 3,976,104 788,060
$443,511,000
$3,121,000
$238,954,000 331,342
$17,046,000 1997 4,223,699 853,384
$367,130,000
$0
$119,698,000 351,975
$20,514,000 1992 3,757,172 740,847
$418,234,000
$(5,799,000)
$234,625,000 313,098
$15,301,000 I
k'i I I I I I U
le I I ro I
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 cities continued the business of providing electricity and, as always, we made our scheduled debt payment on time and in full NCEMPA was also hard at %Nork securing a contract for our supplemental power supply After going over more than 20 proposals xxith a fine-tooth comb, A e determined CP&L provided the best opportunity and arrangements for our cities. This was a significant accomplishment as this contract represents nearly 30 percent of our total energy needs through 2006 Our cities Nsere also keeping a close eye on proposed clean air legislation Any such plan N%
ould likely require capital improvements to our coal generating plants.
We shepherded through privacy legislation that Awould ensure our customers' sensitive billing information would not get in the wrong hands We worked to see that our customers' needs were met and that our distrnbution systems were running well and efficiently So as you can see, deregulation may have been put on hold in 2001, but our business was not Now we face more challenges We must continue our efforts to reduce costs and be more efficient to lessen the impact of any possible future rate increases We must continually improve and upgrade our systems and keep them in top running order. Past hurricanes hae proven how important that is 2001 marked 20 years since our power agency officially became knoxs n as North Carolina Eastern Municipal Power Agency (NCEMPA) It also marks 20 years that NCEMPA has supplied all requirements power to all 32 participant cities. Initially, the eastern cities "ere split into two separate power agencies Our coming together back in 1981 made us stronger Today we remain united in our efforts to provide electricity to the citizens that call our communities home and to the businesses that help fuel our economy Local control and local operation 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 Frederick E. Turnage Mayor, Rocky Mount Chairman, NCEMPA
NCEMPA LsadaNOTEo 2001 Board of Commissioners 2001 Officers Frederick E.
Tumage Chairman Mayor, Rocky Mount Commissioners and Mark S. Williams Vice-Chairman Town Manager, Wake Forest Anne-Marie Knighton Secretary-Treasurer Town Manager, Edenton Alternate Commissioners Alternate commissioner's names appear in itafics
- Apex Mr. Bruce A Radford Air J Michael Wilson
- Ayden Mr Edwin L Booth Mayor Michael House
- Belhaven Mr Timothy M. Johnson Air H Dewitt Hardison
-Benson Mr Keith R. Langdon Mayor Don H. Johnson
- Clayton Mr. Robert J Ahlert AMr Ronald E Gurganus
- Edenton Ms Anne-Mane Knighton First Alternate Vacant Ar William A Crunmney
- Elizabeth City Mr Steven L Harrell Air Brett VanNteuvvenhutse
- Farnmille Mr Richard N Hicks Mr J Don Riddle
- Fremont Commiassioner Vacant First Alternate Vacant Mr Billy Harvey
- Greenville Mr Charles E, Davis Ms Nancy M. Jenkins Mr MalcolmA Green
- Hamilton Mr Herbert L. Everett Mayor Donald G Matthews, III
- Hertford Mr John Christensen Mayor James Sidney (Sid) Eley
- Hobgood Ms Stella Daugherty Mayor Thmothy D Purvis
- Hookerton Mr R. Scott Spence First Alternate Vacant
- Kinston Mr Ralph A. Clark Mlr. Carey B Washburn Air Ronald D WMcker
- La Grange Mr Mike Taylor Mr Andy Hughes
- Laurinburg Mr Joseph R. Huffrnan MayorAnn B Slaughter
- Louisburg Mr. C. L Gobble AMs Lots Brown Wheless Air Ray Patterson
- Lumberton Mr Harry L Ivey Mr W. Todd Powell Mr J Franklin Price
- New Bern Mr Ralph E Puckett Mr Walter B Hartman, JrA
- Pikeville Mr Lyman Galloway First Alternate Vacant
- Red Springs Mr John McNeil Mr T Wa7ye Home
- Robersonville Mr John H Pritchard, Jr Mr John David Jenkins
- Rocky Mount Mayor Fredenck E. Tumage Mr Stephen W Raper
- Scotland Neck Mayor Robert B Partim First Alternate Vacant
- Selma Commissioner Vacant First Alternate Vacant
- Smithfield Mr PeterT Connet Mr Robert E Tripp, III
- Southport Mr. Paul D Fisher Mr. Donald James "Jim" Henry
- Tarboro Mr Samuel W Noble, Jr.
Mr Ricky C. Page Mr James L Afford
- Wake Forest Mr Mark S Williams Mr Boyce C. Medhn
- Washington Mr. R. L. Willoughby Mr Keith Hardt
- "*ilson Mr Edward A. Wyatt Mr Charles W Whitley Jr Mr Charles W Pittman, IIl 2001 Annual Report 1 43
El st System City/Town
- Apex
- A)den
- Belhaven
- Benson
- Clayton
- Edenton SElizabeth City
- Fanm tile
- Fremont
- Green ille
- Hamilton
- Hertford
- ltobgood
- Hookerton SKinston
- La Grange
- Launnburg
- Louisburg
- Lumberton
- New Bern
- Pjkeudlle
- Red Springs
- Robersonville
- Rocky Mount
- Scotland Neck
- Selma
- Smithfield
- Southport
- Tarboro
- Wake Forest
- Washington SWilson Established 1917 1916 1920 1913 1913 1908 1926 1904 1918 1905 1922 1915 1922 1907 1897 1917 1925 1906 1915 1901 1918 1910 1919 1902 1903 1913 1912 1916 1897 1909 1903 1892 Revenues 2001-
$13,330,439 2000-
$13,108,892 2001-
$9,223,985 2000-
$8,571,413 2001-
$2,315,095 2000-
$2,376,863 2001-
$3,578,574 2000-
$3,467,178 2001-
$7,786,644 2000-
$7,119,224 2001 -Not Available 2000 -Not Available 2001-
$24,393,759 2000-
$23,946,844 2001-
$5,090,104 2000-
$5,184,798 2001-
$1,266695 2000-
$1 296,724 2001 -$118,998,891 2000-
$114,647,018 2001 -
$394,580 2000-
$396,043 2001-
$2,394,564 2000-
$2,051028 2001 -
$437,477 2000-
$413,611 2001-
$659,808 2000-
$642,728 2001-
$36,469,351 2000-
$34,345,917 2001-
$2,442,179 2000-
$2,310,552 2001-
$12,807,234 2000-
$12,513,202 2001-
$5,571,964 2000-
$5,378,600 2001-
$23,295,394 2000-
$24,519,476 2001-
$39,062,539 2000-
$38,403,674 2001-
$766,162 2000-
$807,931 2001-
$3,322,061 2000-
$3,145,760 2001-
$2,040,817 2000-
$2,142,427 2001-
$62,597,012 2000-
$61,493,313 2001-
$2,907,077 2000-
$3,241,434 2001-
$5,425,610 2000-
$5,547,412 2001-
$13,629,585 2000-
$12,015,061 2001-
$4,241,594 2000-
$3,906,268 2001-
$22,327,554 2000-
$21,736,954 2001-
$9,386,534 2000-
$8,649,414 2001-
$23,867,256 2000-
$23,329,724 2001-
$93,548,632 2000-
$91,038,001 46 2001 An it,al Reocrt Customers 9,154 3,695 1,139 1,800 4,082 3,899 10,717 2,888 869 51 662 254 1 271 320 422 16,528 1,524 5,932 1,940 1(1,066 16,821 527 1 916 I 220 29,097 1,630 2,705 4,568 2,086 5,797 4,900 12,384 30990
% Ownership 0706%
1 134%
0 409%
0577%
0 745%
I 596%
4 251%
1 290%
0 306%
16134%
078%
0412%
0091 0155%
8668%
0501%
2 267%
0858%
5 157%
6 368%
0 205%
0 580%
0 507%
16026%
0 576%
0810%
2 006%
0714%
4 743%
0726%
5892%
15512%
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 Louisburg and the development of new delivery points for Clayton, Greenville, and Wake Forest.
Agency and participant staff continued to develop communication alternatives for load management operations. The participants and their customers utilize more than 10 different paging companies Agency staff makes over 175,000 pages and e-mail communications through these different companies each year providing load management recommendations and information, in addition to over 3,000 direct telephone calls Energy and Demand The year's energy consumption was 6,787,351 MWh (including SEPA) and was below last years total of 6,944,631 MWh.
Neighbors serving neighbors. One of the many advantages of living in a public power community is knowing the people who run your electric system. It means local control and fnendly service.
The highest monthly energy consumption for 2001 was 720,766 MWh, which was above the old record set in August 1999 of 717,270 MWh.
The highest Coincident Peak demand for 2001 (including SEPA) was 1,313 MW during August. This broke the old Coincident Peak record of 1,292 MW set in August 2000.
The average Coincident Peak load factor (net of SEPA) for the year was 83 percent, a slight change from the 2000 average of 84 percent The 2001 maximum Non-Coincident Peak demand (including SEPA) was 1,412 MW set in August This was up from the previous all time peak of 1,394 MW set in August 1999.
Environmental Regulations Early in 2001 a coalition of environ mental groups called upon the North Carolina General Assembly to take action to reduce air pollution from power plants. In April the bill approved by the Senate, the so called "Clean Smokestacks" bill, mandated pollution cuts of about 70 percent to be implemented in two stages by 2013. The bill calls for a 72 percent statewide reduction from 1998 levels of year-round nitrogen oxide (NO.) emissions, a 73 percent statewide reduction of sulfur dioxide (SO2) emissions, and a 60 percent incidental reduction of mercury. If the new Clean Smokestacks Act wins approval in the 2001 Annual Report 1 47
6 'i I
AT-,
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 and replace older equipment to ensure citizens and businesses have a reliable source of power 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 The Eastern North Carolina cities continue their successful industrial recruit ment and expansion of existing businesses NCENIPA members added 1.881 new jobs in 48 200' Annjal Repao
( )
2 t
1
Operational K 2001 to their communities with investments totaling $169,980,000. New load added to 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 expires December 31, 2003 This new contract will expire December 31, 2006 The Agency put out a Request for Proposals TOP' NCEMPA has 16 17% ownership in the Shearon Harris Nuclear Plant in Wake County. BOTTOM. NCEMPA has 18.33% ownership of the Brunswick Nuclear Plant in Southport.
2001 Annual Report 1 49 0
110ý 4_
(r/Ka Nr,,--Ilonal VlrQ
/I C
rews in Clayton make repairs to an ele Clayton's electric system was established in the Johnston County town has more than 4 in late 2000 looking for a new supplemental power contract They receixed 22 bids from 15 suppliers. The Agency worked through a short list of bidders in a lengthy process CP&L provided the best opportunity and best arrangement for the eastern cities This contract means CP&L will pro% ide additional power kkhen needs exceed the capacity NCEMPA ass ns The contract represents 25 to 30 percent of NCEMPA's total energy needs or roughly 1,000 MW "Retail Billing The Retail Billing program continued its steady groxh in 2001
~ ~
Tarboro addedl13 customers and Kinston increased its pamcipa tion by six At year end, the program was serving 139 customers in 21 municipalities, and anticipating the addition of II new customers in Wake Forest Customer accounts are monitored and billing data dispatched on a timely basis so that the cities can process and prepare their retail bills.
Cities who want to receive their billing infom~ation Nia email ctric line can do so, alloy ing 1913 Today them even faster access
,000 customers to theirdata To maintain data integrity, equipment failures are quickly detected and reported to the cities.
Plant Status
- Mayo Unit 1 and Roxboro Unit 4 completed annual boiler inspection outages in the spnng of 2001
- Brnswick Unit 2 completed a 3 1 day refueling outage and generator rewind on March 27, xx hich set a record for the shortest refuel outage for Unit 2 The uiit operated continuously from March 27, prox iding 279 days of continuous service as of December 31, 2001 SBrunswick Unit I passed the mark of providing 500 days of continuous service on August 6 and went on to set a new world record on October 27 for the longest continu ous operating run for a GE boiling water reactor, breaking Unit 2's record of 581 days set in 1996. As of December 31, 2001, the unit had provided 647 days of continuous service.
- Harris Unit I completed its refueling and steam generator replacement outage on January 3, 2002 that began on September 22 A planned power uprate was also completed during this outage, A hIch increased the generating capacity of the plant by 60 MW, for a total generating capacity of approximately 900 MW Security Following the terrorist attacks on the World Trade Center and the Pentagon on September HI, 2001, the focus shifted to another potential target The nation's nuclear power plants came under scrutiny about
%N hether they could withstand a terrorist strike As a result of the exents on 9/11, nuclear pmo er plants across the United States have upgraded secunty measures.
Under the contractual arrangement with NCEMPA, all issues of security are handled by CP&L CP&L is closely coordinating with federal, state and local authorities and has taken and continues taking appropriate steps to ensure safety and security at all the nuclear facilities in which NCEMPA has oxx nership 50
- 1) An~dl Re,-I
Operational Highlights NCEMPA Participant Energy Usage Forenst for 2002 is from Sept 2001 Losad Forecast m
Jan Feb Mar Apr.
May June July m
Attual 2090 m
Actual 2001 Aug Sept Oct.
Nov 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 Jan Feb.
Ma.
Apr.
Actual 2000 May June July SActual 2001 Aug Sept Oct.
Forecasr 2002 NCEMPA Economic Development 2,000 1,760 2000 2W1 Number of New Jobs
- less,
$17 million 200) 2001 Investments in Milions 2000 2001 Megawaft Growth c(~Z 2001 Arqual~t r.po 1
C 1
l0 C"
9e00,*
Nov Deci
Investment Portfolio Statistics Earnings*
Jrif Onte
- 2001
$29,575,000
- 2000
$33,538,000 Rate of Retini 5 80%
629%
Market Value as of 12/31 '
Vliue Ai erag'e Alatunnt
- 2001
$593,487,000 5 5 years
- 2000
$646,174,000 5 2 years Transactions Numntber Amount
- 2001 633
$8,222,276,000
- 2000 752
$6,948,522,000 For EanwngA al Mar'tke %thlue tnttit,inchude int ontefarm andl nurkr' wtlue tif wr' urrtes held i the demnrrunrtstrrnr Intr Debt Outstanding Debt Outstanding 12/31 e tihtled -t erige Balanh e 11th resl CoVI Fixed Rate Bonds
- 2001
$3,204,444,000**
607%
- 2000
$3,271,245,000**
6 12%
NCEMPA Bond Reconciliation
"* Bonds Outstanding 12/31/00
"* Matured 1/1/01
"* Bonds Outstanding 12/31/01
$3271.245,000**
66,801.000**
$31204,444.000**
NCEMPA Bonds Outstanding
"* Senes 1985G
"* Seies 1986A
" Senes 1988A
" Senes 1989A
" Senes 1991A
"* Senes 1993B
"* Senes 1993C
"* Senes 1993D
"* Senes 1995A
" Senes 1996A
"* Senes 1996B
"* Senes 1997A
"* Senes 1999A
"* Senes 1999B
"* Senes 1999C
" Senes 1999D
$95,565,000
$4,495,000 S28,056,026*"
S83,501,778"
$323.751,432
$1,470-520,000
$274,370,000
$78,300,000 S 14,090,000
$252,495.000
$136.875,000
$29,185,000
$155,000,000
$116,725,000
$6,045,000
$135,470,000
- Does not inchde $979,000 an $856,000 for 2001and 2000, teVte ti ely accr ted on the baltau e sheet for u t rent matutrities of tie Senes 1988A Capital Appir, 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 1-773 Tfl-ý-Til
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 with auditing standards generally accepted in the United States of America. 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 beheve 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 Eastern Municipal Power Agency as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
As discussed in note B to the financial statements, the Agency changed its method of accounting for derivative financial instruments in 2001.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplementary information included in the Schedules of Revenues and Expenses per Bond Resolution and Other Agreements and Schedules of Changes in Assets of Funds Invested is presented for purposes of additional analysis and is not a required part of the basic financial statements Such information has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial 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 note Y tofinanc tal statements.
54 2u5 Annrar Repcrt
BoEallasc Sheets (SOOOs)
December 31, Liabilities and Retained Earnings
- Long-Term Debt.
Bonds, net of unamortized discount (Note H)
"* Special Funds Liabilities:
Construction payables Current maturities of bonds (Note H)
Accrued interest on bonds
"* Liability for Decommissioning Costs
"* Operating Liabilities:
Accounts payable Accrued taxes
"* Deferred Revenues (Note G)
- Commitments and Contingencies (Notes J and K)
"* Retained Earnings 2001 Annual Report 1 55 2001 2000
$3,061,984 1,838 64,290 92,961 159,089
$3,119,976 1,821 68,805 99,922 170,548 90,589 79,350 17,040 4,912 21,952 24,232 6,242 30,474 60,639 94,469 23,324
$3,417,577 23,324
$3,518,141
t~~'-ets ci 1
And Changes in Retained Earnings ($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
"* Cash Flows from Operating Activities:
Receipts from sales of electricity Payments of operating expenses Net cash provided by operating activities
" Cash Flows from Capital and Related Financing Activities Interest paid Debt discount and issuance costs paid Additions to electric utility plant and non-utility property and equipment Bonds retired or redeemed Investment earnings receipts from construction fund Net cash used for capital and related financing activities
"* Cash Flows from Investing Activities:
Sales and matunties of investment securities Purchases of investment securities Investment earnings receipts from non-construction funds Net cash provided by investing activities
"* Net (Decrease) Increase in Operating Cash
"* Operating Cash, Beginning of year
"* Operating Cash, End of year See accompanying notes to financial statements 2001 Annual Report 1 57 Statements of
~alseh IF@1Os)
($000s)
Year Ended December 31, 2001 455,042 (236,392) 218,650 (188,704)
(69)
(44,151)
(68,805) 161 (310,568) 8,136,174 (8,076,798) 23,396 82,772 (146) 148 2
2000 454,166 (228,120) 226,046 (197,663)
(82)
(24,383)
(164,242) 565 (385,805) 6,892,469 (6,758,335) 25,770 159,904 145 3
148
St-atem-eni~s of (SOOOs)
Reconciliation of Net Operating Income to Net Cash Provided by Operating Actix ities:
Net Operating Income Adjustments:
Depreciation and amortization Amortization of nuclear fuel Changes in assets and liabilities Increase in participant accounts receivable (Increase) decrease in fossil fuel stock Increase in prepaid expenses Decrease in deferred costs (Decrease) increase In accounts payable (Decrease) increase in accrued taxes Total Adjustments Net Cash Pros ided by Operating Activities See accomJ)anvtIg notev lofinan tal tatementv.
(C I' 58 2C01 An tll H[eport I\\
If _ ;_
2001 Year Ended December 31, 2000
$163,047 55 091 14,979 (3,422)
(2,178)
(622) 659 (7,574)
(1,330) 55,603
$218,650 S154,277 54,590 13,030 (2,645) 1,238 (1,237) 659 4,980 1,154 71,769
$226,046 1-1
ý r-1 I t I [
R©t(Be to Financial Statements Years Ended December 31, 2001 and 2000 A. GENERAL MATTERS North Carolina Eastern Municipal Power Agency (Agency) is a joint agency organized and existing pursuant to Chapter 159B of the General Statutes of North Carolina to enable municipal electric systems, through the organization of the Agency, to finance, build, own, and operate generation and transmission projects The Agency is comprised of 32 municipal electric systems (participants) with interests ranging from 0.0783% to 16.1343%, which receive power from the Agency.
Initial Project The initial project is comprised of the Agency's undivided ownership interests in three nuclear-fueled and two coal-fired generating units presently m commercial operation by Carolina Power & Light Company (CP&L). The initial project is financed under Power System Revenue Bond Resolution No R-2-82 (resolution) adopted by the Board of Commissioners (board) of the Agency. The resolution established special funds to hold proceeds from debt issuance, such proceeds to be used for costs of acquisition and construc tion of the initial project and to establish and maintain certain reserves. The resolution also established special funds into which initial project revenues from participants are to be deposited and from which initial project operating costs, debt service, and other specified payments are to be made.
The Agency entered into several agreements with CP&L which govern the purchase, ownership, construction, operation, and maintenance of the generating units in the initial project. Under these agreements, CP&L manages the construction and operation of the generating units in which the Agency has undivided ownership interests. Both CP&L and the Agency have the right to challenge the allocation of charges for a period extending to April 1 of the second year after which the challenged payment or adjustment was made.
During 2001, the Agency and CP&L finalized a new contract for supplemental power purchases by the Agency from CP&L from 2004 to 2006 Purchases under the new contract will replace purchases under the current contract and the Peaking Project Delay Agreement discussed later.
The Agency also entered into agree ments with CP&L and Virginia Electric and Power Company (VEPCO) for the transmis sion of power to the Agency's participants.
The Power Coordination Agreement (1981 PCA) obligates CP&L to purchase power from the Agency in specified percentages of the Agency's entitlement to such power from Harris Unit 1 (1987-2007).
The Agency entered into two power sales agreements with each of its participants for supplying the total electric power requirements of the participants in excess of Southeastern Power Administration (SEPA) allocations With the power generated from the initial project, together with supplemental purchases of power from CP&L, the Agency provides the total electric power require ments of its participants, exclusive of power allotments from SEPA. Under the Initial Project Power Sales Agreements, the Agency sells to the participants their respective shares of initial project output. The revenues received relative to the initial project are pledged as security for bonds issued under the resolution, after payment of initial project operating expenses. Each participant is obligated to pay its share of operating costs and debt service for the initial project. Under the Supplemental Power Sales Agreements, the Agency supplies each participant the additional power it requires in excess of that provided by output from the initial project and from SEPA.
Peaking Project Delay Agreement In 1996, the Agency entered into an agreement with CP&L to delay the commer cial operation of the Agency's peaking project (subsequently cancelled) until January 1, 2004. In return, CP&L will provide capacity and energy equal to the peaking project at a price comparable to what it would have cost to operate the peaking project during the delay period (June 1, 1998 to December 31, 2003). As mentioned previously, the Agency and CP&L entered into an agreement in 2001 for the replacement of the power provided under the Peaking Project Delay Agreement for 2004 to 2006 ElectriCities of North Carolina, Inc.
ElectriCities of North Carolina, Inc (ElectriCities), organized as a joint municipal assistance Agency under the General Statutes of North Carolina, is a public body and body corporate and politic created for the purpose of providing aid and assistance to municipali ties in connection with their electric systems and to joint agencies, such as the Agency. The Agency entered into a management agree-2001 Annual Report 1 59
17 onmtimue" ment with ElectriCities Under the current management agreement u ith the Agency, ElectriCities is required to prox ide all personnel and personnel services necessary for the Agency to conduct its business in an economic and efficient manner Industry Restructuring Developments and Related Uncertainties Federal regulations have been passed
%%hich encourage ulholesale competition among utility and non-utility power producers Similar regulations are contemplated for retail competition at both the federal and state level. HoNeer, because of other states' experiences with deregulation, momentum has slowned significantly in North Carolina.
In 1997, the North Carolina General Assembly created the "'Study Commission on the Future of Electric Service in North Carolina" (Study Commission) The Study Commission is comprised of 30 members, representing la%% makers, the North Carolina municipal, cooperative, and private electnc utilities, electric consumers, the environ mental community, and electric power marketers The Study Commission is charged with examining the cost, adequacy.
availability, and pricing of electric rates and service in North Carolina to determine whether legislation is necessary to assure an adequate and reliable source of electricity and economical, fair, and equitable rates for all consumers of electricity in North Carolina.
After much discussion and negotia tions, the Study Commission presented a report to the General Assembly in 2000.
wshich included recommendations for full retail choice no later that January 1, 2006, with fifty percent of each power supplier's customers load ha; ing the option of retail choice on January 1, 2005 The report indicated that the Study Commission wsould then make recommendations dealing \\, ith how to address other aspects of deregulation such as stranded costs recovery, the Agency's debt, consumer protection, environment and alternatie energy, tax laws, transmission and distribution, and any other areas ss hich need to be addressed.
In early 2001. the Study Commission determined that because of California's circumstances, North Carolina would take a "go slow" attitude toNs ard deregulation. No recommendations were made to the General Assembly during 2001 and none are anticipated in 2002 Because the Study Commission does not intend to make any recommendations to the General Assembly during 2002, and because the General Assembly is not bound by the w, ork ol the Study Commission, and because other entities are able to piopose legislation on this issue, the Agency cannot predict whether there %x ill be any legislative initiatives, wx hat the results of legislative initiatines wx ill be, or whether any such legislation N%
ill become law The Board of Commissioners of the Agency, in conjunction With the Board ot Directors of ElectriCities of North Carolina, Inc, has developed a strategic plan to address deregulation In addition, the Agency periodically reviews its regulatory assets and the impact of reco\\ enng such assets on Agency rates. In addition, the Agency's management and Board are parutcipating in the deregulation debate.
both on the national and state level For further discussion about deregula tion and the possible effects on rates and deferred expenses,. see Note G.
B. SIGNIFICANT ACCOUNTING POLICIES Basis of Accounting The accounts of the Agency are naintained on the accrual basis, in accor dance with the Uniform System of Accounts of the Federal Energy Regulatory Commis sion, and are in conformity with accounting principles generally accepted in the United States of America (GAAP) The Agency has adopted the principles pronmulgated by the Governmental Accounting Standards Board (GAS B) and Statement of Financial Account ing Standard (SFAS) No. 71, "Accounting for the Elfects of Certain Types of Regulation,"
as amended This,,tandard allows utilities to capitalize or deter certain costs and/or revenues based upon the Agency's ongoing assessment that it is probable that such items
%N ill be recovered through future rex enues In the future, issues of competitive market forces and retnicturng in the electric utility industry might require the reduction in the carrying value of the Agency's regulatory assets unless appropriate action is taken to assure the recoN ery of these regulatory assets, ex en in a market en% ironment Financial Reporting Under GASB Statement No 20, "Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities that Use Proprietary Fund Account ing", the Agency has adopted the option to apply Financial Accounting Standards Board (FASB) statements and interpretations that do 60 2001 Annual Heport
E%!JtR (continued) not conflict with or contradict GASB pronouncements Electric Plant in Service All direct and indirect expenditures associated with the development and construction of the Agency's undivided ownership interests in five of CP&L's generating units now in commercial operation, including interest expense net of investment earnings on funds not yet expended, have been recorded at original cost (plus acquisition adjustment) and are being depreciated (or amortized) on a straight-line basis over the composite average life of each unit's assets At December 31, 2001, the remaining composite average life for Brunswick Units 1 and 2 was 7 years, Harris Unit 1 was 22 years, Roxboro Unit 4 was 12 years, and Mayo Unit 1 was 14 years Construction Work in Progress All expenditures associated with capital additions related to the Agency's undivided ownership interests in CP&L's generating units are capitalized as construction work in progress until such time as they are complete, at which time they are transferred to Electric Plant in Service. No interest is capitalized on capital additions. Depreciation expense is recognized on these items after they are transferred Nuclear Fuel All expenditures related to the purchase and construction of the Agency's undivided ownership interests in nuclear fuel cores at the nuclear units are capitalized until such time as the cores are placed in the reactor. No interest is capitalized on fuel cores. When placed in the reactor, they are amortized to fuel expense on the units of production method Nuclear fuel expense includes a provision for estimated disposal costs, which is being collected currently from participants Amortization of nuclear fuel costs in 2001 and 2000 includes a provision of $3,434,000 and $3,453,000, respectively, for estimated disposal costs.
The Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the Department of Energy's (DOE) uranium enrichment plants.
Nuclear plant licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services.
CP&L makes the annual payment to DOE for the Brunswick and Harris units and bills the Agency for their proportionate share. The Agency's payments to CP&L were approxi mately $756,000 and $742,000 in 2001 and 2000, respectively, and were recorded as fuel expense.
Under provisions of the Nuclear Waste Pohcy Act of 1982, CP&L, on behalf of CP&L and the Agency, has entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent nuclear fuel in 1998, the year provided by the Nuclear Waste Policy Act and CP&L's contract with the DOE.
CP&L, on behalf of all co-owners, along with other utilities, have taken steps to force the DOE to take spent nuclear fuel. To date, the courts have rejected these attempts While some utilities have filed actions for damages in the United States Court of Federal Claims, CP&L has not yet taken such action.
The Agency stores all spent fuel within its facilities. With certain modifications and additional Nuclear Regulatory Commission (NRC) approval, the Agency's spent fuel storage facilities are sufficient to handle all spent fuel generated by all of the Agency's nuclear generating units through the expiration of their current operating licenses In 1998, CP&L submitted a license amendment application to the NRC requesting NRC approval to activate and begin using the additional spent fuel storage at the Harris Plant. In December 2000, CP&L received such permission from the NRC.
Non-Utility Property and Equipment All expenditures related to purchasing and installing an in-house computer, jointly owned with North Carolina Municipal Power Agency Number 1 (NCMPA 1), have been capitalized and are fully depreciated Also included are the land and administra tive office building jointly owned with NCMPAI and used by both agencies and ElectriCities. The administrative office building is being depreciated over 37 1/2 years on a straight-line basis Investments The Agency has implemented the provisions of GASB Statement No. 31, "Accounting and Financial Reporting for Certain Investments and for External Investment Pools," which requires investments to be reported at fair value.
Derivative Financial Instruments In June 1998, the Financial Accounting Standards Board (FASB) issued SIAS No.
133, "Accounting for Derivative Instru ments and Certain Hedging Activities" (SFAS No 133). In June 2000, the FASB issued SFAS No. 138, 'Accounting for Certain Denvative Instruments and Certain 2001 Annual Report 161
Hedging Actie ities, 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 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 $11.902,000 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 estimated based on current market pricing models The Agency has not designated any of its derivatives as hedges Changes in the fair value of denvati se instruments are reported in current-penod revenues and expenses For the year ended December 3 1. 2000, prior to the adoption of SFAS No 133, the Agency entered into interest rate swap agreements For interest rate swaps, fair value which would be paid or received if the SWAP were temiinated is accrued and recognized in "net increase in fair value of im estnents and denvati e financial instruments" and may change as market interest rates change If a swap contract is terminated prior to its maturity, the gain or loss is recognized immediately.
The Agency has only limited involve ment N%
ith derivative financial instruments In June of 1999 and January of 2000, the Agency entered into two identical interest rate swap agreements NN ith termination dates of June 14. 2009 and December 31, 2009, respectively. The Agency's objective for entering into these interest rate s%%ap agreements is to synthetically corn ert a portion of its fixed rate debt to variable rate debt os er the life of the swaps Under these fixed to variable interest rate swaps, NCEMPA receives a fixed rate of 4 67%
and 5 03%, respectively, through the termination dates, Nshile paying a variable rate based on the BMA Municipal Ssap Index Interest paid and receised Linder the swap agreements increases and decreases, respectively, interest expense The net effect was to reduce interest expense S6,409,000 and $2,067,000 in 2001 and 2000, respec tively The notional amount of each of these agreements is S 155,000,000 and S136.970,000, respectively The fair value of the two interest rate swap agreement was approxinately
$15,681,000 and $11,902,000 at December 31, 2001 and 2000, respectiely Current market pricing models were used to estimate the fair -, alue of the interest rate swap agreements The fluctuation in the fair value of the interest rate swaps was an increase of $3,779,000 in 2001 and is included in "Increase in fair value of investments and derivative financial instruments" in the statement of resenues and expenses.
By using densvati'e instruments, the Agency exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perfonn under the terms of the densvatise contract When the fair value of the derivati, e contract is positive, the counterparty os es the Agency. x%
hIch creates repayment risk for the Agency When the fair s alue of a derivative contract is negatise, the Agency m% es the counterparty and, therefore, does not possess repayment risk. The Agency minimizes the credit or repayment risk by entering into transactions %%
ith high-quality counterpariies Market risk is the adverse effect on the salue of financial instruments that results from a change i interest rates. The market iisk associated v, ith interest-rate contracts is managed by establishing and monitoring parameters that limit the types and degree of maiket risk that may be undertaken Decommissioning Costs NRC regulations require that each licensee ot a commercial nuclear power reactor furnish to the NRC certification of its financial capability to meet the costs of nuclear decommissioning at the end of the useful life of the licensee's facility As a co licensee of Brunsssick Units 1 and 2 and Harris Unit 1, the Agency is subject to the NRC's financial capability regulations, and therefore has furnished certification of its financial capability to fund its share of the costs of decommissioning those units To satisfy the NRC's financial capability regulations, the Agency established an external trust fund (Decommissioning Trust) pursuant to a trust agreement with a bank The Agency's certification of financial capability requires that the Agency make annual deposits to the Decommissioning Trust xN hich, together skith the investment earnings and amounts previously on deposit in the trust, are anticipated to result in sufficient funds being held in the Decommis sioning Trust at the expiration of the current opei ating licenses for the units (currently 2014 for Bruns%%ick Unit 2, 2016 for BrunsN ck Unit 1, and 2026 for Harris Unit I) to meet the Agency's share of 62 20C1 A nual Repol A
to (cont ýJec,
bKtQ (continued) decommissioning Estimates of the future costs of decommissioning the units are based on the most recent site specific study which was conducted in 1998 The Agency's portion of decommissioning costs, including the cost of decommissioning plant compo nents not subject to radioactive contamina tion, is $67,242,000 for Brunswick Unit 1,
$67,040,000 for Brunswick Unit 2, and
$63,287,000 for Harris, all stated in 1998 dollars The Decommissioning Trust is irrevocable, and funds may be withdrawn from the trust solely for the purpose of paying the Agency's share of the costs of nuclear decommissioning. Under the NRC regulations, the Decommissioning Trust is required to be segregated from Agency assets and outside the Agency's administrative control. The Agency is deemed to have incurred and paid decommissioning costs as amounts are deposited to the Decommissioning Trust In addition to the Decommissioning Trust, certain reserve assets are anticipated to be available to satisfy the Agency's total decommissioning liability The Agency determined that it was necessary to fund decommissioning costs associated with the non-nuclear portion of the Brunswick plant which fell outside the NRC requirements Therefore, it also deposits to the Decommissioning Fund, separate from deposits required to the Decommissioning Trust.
Recently Issued Pronouncements In June 2001, the FASB issued SFAS No 143, 'Accounting for Asset Retirement Obligations" (SFAS No. 143). SPAS No. 143 requires the Agency to record the fair value of an asset retirement 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 assets The Agency is required to adopt SFAS No 143 on January 1, 2003 The Agency will record a corre sponding 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. Management is currently evaluating what impact, if any, SFAS No. 143 will have on the Agency's financial statements.
In August 2001, the FASB issued SEAS No 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SIAS No 144). Effective for fiscal year 2002, SEAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No 121, 'Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of'. SFAS No. 144 states the required accounting for disposing of long-lived assets whether previously held and used or newly acquired, and broadens the presenta tion of discontinued operations to include more disposal transactions The implemen tation of SFAS No 144 is expected to have no material impact on the Agency's financial position or results of operations Fossil Fuel Inventory Fossil fuel inventory includes fossil fuel stock and EPA Clean Air Act Allowances.
Fossil fuel stock and EPA Clean Air Act Allowances are each stated at average cost.
Deferred Costs Deferred costs are shown net of accumulated amortization Unamortized debt issuance costs at December 31, 2001 and 2000, shown net of accumulated amortiza tion of $12,961,000 and $11,067,000, respectively, are being amortized on the interest method over the term of the related debt. Development costs, shown net of accumulated amortization of $5,825,000 and
$5,555,000 at December 31, 2001 and 2000, respectively, are being amortized on a straight-line basis over the forty-year life of the initial project. Costs of advance refundings of debt at December 31, 2001 and 2000, shown net of accumulated amortiza tion of $286,036,000 and $251,414,000, respectively, are deferred and are amortized over the term of the debt issued on refund ing Costs to be recovered from future billings to participants and deferred revenues are not amortized but will be either recovered from or refunded to participants through future rates (see Note G)
Discounts on Bonds Discounts on bonds (net of premiums) at December 31, 2001 and 2000 shown net of accumulated amortization of $14,026,000 and $12,342,000, respectively, are amortized over the terms of the related bonds in a manner which yields a constant rate of interest.
2001 Annual Report 1 63
©tta (continued)
Taxes Income of the Agency is excludable from income subject to federal income tax under Section 115 ot the Internal Rexenue Code Chapter 159B of the General Statutes of North Carolina exempts the Agency from property and franchise or other pfivilege taxes In lieu of property taxes, the Agency pays an amount % hich w ould otherwise be assessed on the real and personal property of the Agency. In lieu of a franchise or privilege tax, the Agency pays an amount equal to 3 22% of the gross receipts from sales of electrcity to participants Statements of Cash Flows For purposes of the statements of cash flow s, operating cash consists of unrestncted ca,,h included in the line item on the balance sheets "operating assets funds mwested" Use of Estimates The preparation of financial statements in confonnity x ith GAAP requires manage-nment to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses dunng the reporting period. Actual results could differ from those estimates Reclassifications Certain 2000 amounts hax e been reclassified to confomi wNi th 2001 classifica tions. The reclassifications had no effect on excess of revenues over expenses or retained earnings as prex iously reported C. ELECTRIC PLANT IN SERVICE, NON-UTILITY PROPERTY AND EQUIPMENT, AND ACQUISITION AND CONSTRUCTION PROGRAM Initial Project The Agency has commitments to CP&L in connection %%
ith capital additions for the initial project Current estimates indicate the Agency's portion of these costs for 2(X)2 and 2003 will be appmximately S34,(00.000 There %%ere no interest costs capitalized as part of the cost of initial project capital additions under construction duiing 2001 and 2000 The Agency's agreements "x ith CP&L specify the purchase of undivided ownership interests in nuclear-fuieled and coal-fired generating units, wh Inch comprise the initial project, presently in commercial operation as detailed in the table below.
On July 1, 2001, CP&L uprated Brunsx\\ ick Unit I to 820 MW from 790 MW as a result of plant improvements The Agency's ownership entitlement increased from 144 8 MW to 150.3 MW On January I. 2002, CP&L upmted Hams Unit I to 900 MW from 860 MW as a result of plant unproxements. The Agency's ownership entitlement increased from 139 I MW to 145 5 MW Maximum Net Commercial Dependable Operation Capability Agency Ultimate On nershlp Megawatts
- Coal-Fired Units Roxboro Unit 4 Mayo Unit I Total Coal-Fired Capability
- Nuclear-Fueled Units Brunswick Unit 2 Brunswick Unit 1 Harris Unit 1 Total Nuclear-Fueled Capability Total of All Units 64 2001 Annual Report 1980 1983 1975 1977 1987 700 MW 745 790 820 900 12.94%
16 17 1833 1833 1617 90 6 MW 1205 211 1 1448 1503 1455 4406 651.7 MW
[Mateo~ (continued)
The table at the right (top) shows planned uprates at the Brunswick umts and the Agency's increase in entitlement as a result of the uprates Peaking Project 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 $2,147,000 No interest was capitalized in 2001.
Electric Plant in Service Original costs of major classes of the Agency's electric plant in service at December 31, 2001 and 2000 are shown in the table at the nght (middle).
Non-Utility Property and Equipment Non-Utility Property and Equipment original costs at December 31, 2001 and 2000 are shown in the table at the right (bottom).
Unit Brunswick Unit 1 Brunswick Unit 2 Brunswick Unit 1 Brunswick Unit 2 Electric Plant In Service ($O00s)
"* Land
"* Structures and improvements
"* Reactor plant equipment
"* Turbo generator units
"* Accessory electric equipment
"* Miscellaneous plant equipment
"* Other
"* Unclassified
"* Accumulated depreciation D. INVESTMENTS The resolution authorizes the Agency to invest in 1) direct obligations of, or 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 wholly owned by the U.S, 3) direct and general obligations of the State of North Carolina or any political subdivision thereof whose securities are rated "A" or better, 4) repurchase agreements with a member of the Federal Reserve System which are collateralized by previously described obhgations, and 5) bank time deposits evidenced by certificates of deposit and bankers' acceptances Unclassified assets are in service but not yet classified to specific plant accounts Non-Utility Property and Equipment ($O00s)
"* Land
"* Structures and improvements
"* Computer equipment
"* Accumulated depreciation 2001 Annual Report 1 65 Projected Date 2003 2004 2005 2006 Design MNDC Increase 41 MW 62MW 107 MW 105 MW Agency Share 7.5 MW 11.3MW 19.6 MW 19.3 MW December 31, 2001 2000 14,180 482,006 410,283 123,396 174,213 50,720 28,026 171,315 1,454,139 (679,007)
$ 775,132
$ 14,180 481,762 378,417 121,345 173,869 50,304 27,792 169,977 1,417,646 (629,605)
$ 788,041 December 31, 2001
$ 710 1,491 605 2,806 (1,065)
$1,741 2000
$ 710 1,491 551 2,752 (950)
$1,802
Bank time deposits may only be in banks ýxith capital stock, surplus, and undivided profits of $20,000.000 or
$50.000,000 for North Carolina banks and out-of-state banks, respectively, and the Agency's ins estments deposited in such banks cannot exceed 50% and 25%,
respectiely, of such banks' capital stock.
surplus, and undivided profits The resolution permits the Agency to establish official depositories with any bank or trust company qualified under the laws of North Carolina to receive deposits of public moneys and has ing capital stock, surplus, and undivided profits aggregating in excess of $20,000,000 All depositories must collateralize public deposits in excess of federal depository insurance coserage The Agency's depositories use the pooling method, a single financial institution collateral pool Under the pooling method, a depository establishes a single escrow account on behalf of all govemmental agencies Collateral is maintained with an eligible escrow agent in the name of the State Treasurer of North Carolina based on an approsed averaging method for demand deposits and the actual current balance for time deposits less the applicable federal depository insurance for each depositor Responsibility for sufficient collateralization of these excess deposits rests with the financial institutions that have chosen the pooling method. Because of the inability to measure the exact amount of collateral pledged for the Agency under the pooling method, the potential exists for under collateralization Hosseser. the State Investments ($O00s)
"* Repurchase agreements
"* U S government securities
"* U S government agencies
"* Municipal bonds
"* Strips
- Collateralized mortgage obligations
"* Decommissioning Trust securities
- Operating cash
"* Restricted cash
"* Accrued interest
"* Total funds invested
"* Consisting of:
Special funds invested Decommissioning Trust Operating assets 2001 December 31, Cost Basis
$107,148 7,987 313,771 39,096 9,232 17,366 494,600 88,311 2
5 3,047
$585,965 Cost Basis
$259,353 19,967 168,068 18,332 15,304 76,476 557,500 77,080 148 301 3,715
$638,744 Marike Vahle
$107,148 8,280 317,511 39,930 9,064 18,239 500,172 93,315 2
5 3,047
$596,541
$400,610 93,315 102,616
$596,541 2000 Maiket Value
$259,353 20,114 169,739 19,052 15,280 76,602 560,140 86,034 148 301 3,715
$650,338
$412,240 86,034 152,064
$650,338 56 2X(J1 Annual Heport
R,Qt (continued)
Treasurer enforces strict standards for each pooling method depository, which mnni mizes any risk of under-collateralization At December 31, 2001 and 2000, the Agency had $7,000 and $435,000, respectively, covered by federal depository insurance.
The Agency's investments are categorized to give an indication of the level of risk assumed by the Agency at year-end.
Category I includes investments that are insured or registered or for which the securities are held by the Agency or its agent in the Agency's name. Category 2 includes uninsured and unregistered investments for which the securities are held by the broker or dealer, or by its trust department or agent in the Agency's name.
Category 3 includes uninsured and unregistered investments for which the securties are held by the broker or dealer, or by its safekeeping department or agent, but not in the Agency's name. All invest ments except repurchase agreements are considered Category 1 Repurchase agreements are considered Category 3.
The Agency's investments are detailed in the table at the left.
In accordance with the provisions of the resolution, the collateral under the repurchase agreements is segregated and held by the trustee for the Agency.
E. PARTICIPANT ACCOUNTS RECEIVABLE At December 31,2001, there were
$8,532,000 of unbilled receivables associated with the peaking project benefits versus peaking project participant credits.
This receivable will be recovered from the peaking project participants in 2002 and 2003.
F. VEPCO COMPENSATION PAYMENT The VEPCO compensation payment represents compensation to VEPCO for early termination of service for those participants previously served by VEPCO This payment of $15,515,000 and the related capitahzed interest of $33,000 were deferred and are being amortized on a straight-line basis over 40 years, the expected life of the initial project. The balance at December 31, 2001 and 2000 is net of accumulated amortization of $7,775,000 and $7,386,000, respectively.
G. COSTS TO BE RECOVERED FROM FUTURE BILLINGS TO PARTICIPANTS AND DEFERRED REVENUES Rates for power billings to participants are designed to cover the Agency's debt requirements, operating funds, and reserves as specified by the resolution and power sales agreements. Straight-line depreciation and amortization are not considered in the cost of service calculation used to design rates. In addition, certain earnings on bond resolution funds are restricted to those funds and not available for operations The differences between debt principal maturi ties (adjusted for the effects of premiums, discounts, and amortization of deferred gains and losses) and straight-line deprecia tion and amortization and interest income recognition are recognized as costs to be recovered from future billings to partici pants Funds collected through rates for reserve accounts and restricted investment income are recognized as deferred revenues.
The Agency's present charges to the participants, together with planned withdraw als from the Rate Stabilization Fund and Special Supplemental Reserve Account, are sufficient to recover all of the Agency's current annual costs of the participants' bulk power needs Each participant is required under the power sales agreements to set its rates for its customers at levels sufficient to pay all its costs of its electric utility system, including the Agency's charges for bulk power supply. All participants have done so.
In a deregulated electric utility industry, the participants can expect to have as their major competition the investor-owned utilities (IOUs) and rural electric coopera tives presently operating in North Carolina and power marketers and others that begin serving North Carolina retail customers after deregulation The participants present retail electric rates are higher, on average, than the present retail electric rates of the IOUs currently serving North Carolina Agency studies indicate that in a market environment, the participants may not be able to charge rates sufficient to meet their obligations to the Agency as well as cover the costs of their distribution systems. This would give rise to stranded investments of the Agency and the need for stranded investment recovery in a deregulated environment The Agency expects that the methods by which it will recover some or all of its stranded investments will come from the legislative initiatives discussed in Note A However, no assurances can be given that the Agency will be able to recover, in part or in whole, these stranded investments All rates must be approved by the Board of Commissioners. Rates are designed on an annual basis and are reviewed quarterly. If 2001 Annual Report 1 67
V a
-f they are deternmned to be inadequate to cover the Agency's current annual costs, rates may be rexised The reco ery of outstanding amounts associated %%
ith costs to be recoxered from future billings to participants will coincide with the retirement of the outstanding long term debt of the Agency barring a change in regulation. A change in regulation could directly affect the recoverability of these costs, resulting in impairment of these assets and reexamination of these assets in accordance %Nith SFAS No 121, "Accounting for the Impairment of Long-Lix ed Assets and for Long-Lived Assets to Be Disposed Of" This statement requires the long-ived assets be re% iewed for impairment N%
henever events or changes in circumstances indicate that the carrying amount of an asset may not be recoxerable.
This statement also imposes stricter cntena for regulatory assets by requiring that such assets be probable of future reco, cry at each balance sheet date. Upon adoption, and to date, SFAS No 121 has had no effect on the Agency's financial position. See discussions of SFAS No 144 at Note B, Recentl) Ahved Pronou(
emuent H. BONDS The Agency has been authorized to issue Po\\k er System ReN enue Bonds (bonds) in accordance with the terms, conditions, and limitations of the resolution The total to be issued is to be sufficient to pay the costs of acquisition and construction of the project, as defined, and/or for other purposes set forth in the resolution Future refundings may result in the issuance of additional bonds Costs to be Recovered from Future Billings to Participants ($O00s)
"* Deferred interest expense
"* Amortization of debt discount and issuance costs
"* Net increase in fair value of investments and derivative financial instruments
"* Depreciation and amortization
"* Amortization of debt refunding costs
"* Participant billing offsets
"* New project negotiation and Harris Plant litigation costs Deferred Revenues (SOOs)
"* Net special funds withdrawals
"* Restricted investment income
"* Rate stabilization funds used for other than operations
"* Special funds valuations Net Costs to be Recovered From Future Billings to Participants (SO00s)
Year Ended December 31, 2001
$ (3,465) 3,557 (14,657) 55,091 34,622 (85,439)
$ (10,291)
$ (35,503) 1,673
$ (33,830)
$ 23,539 300 3,514 (22,445) 54,589 35,821 (75,002)
$ (3,223)
$(37,062)
(129)
$(37,191)
$ 33,968 68 2001 Anwual Retort 2000 Inception to December 31, 2001
$ 656,319 55,827 (26,251) 827,251 411,049 (510,955) 45,086
$1,458,594
$ (135,284) 218,334 (21,839)
(572) 60,639 2000
$ 659,784 52,270 (11,594) 772,428 376,427 (425,516) 45,086
$1,468,885
$ (99,781) 216,661 (21,839)
(572) 94,469
H[
es! (continued)
The following chart shows 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 comprising the 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 I
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 N ith 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
$3,119,976 2001 Annual Report 1 71
A u, I
t>
N 7
N Debt Service Deposit Requirements for Bonds ($o00s)
Year
- 2002
- 2003
- 2004
- 2005
- 2006
- 2007
- 2008
- 2009
- 2010
- 2011
- 2012
- 2013
- 2014
- 2015
- 2016
- 2017
- 2018
- 2019
- 2020
- 2021
- 2022
- 2023
- 2024
- 2025 Total Principal 78,776 82,097 90,116 98,368 118,070 127,100 133,595 118,230 133,315 140,711 124,728 142,164 145,694 148,180 142,763 144,855 156,650 168,735 178,235 170,830 175,625 168,015 77,675 80,240
$3,144,767 Interest*
$ 187,602 180,312 175,969 170,910 164,053 156,327 147,468 141,072 135,296 127,329 118,659 111,295 102,916 94,610 86,045 77,664 68,849 59,806 50,169 40,188 29,869 19,153 9,506 4,842
$2,459,909 Total
$ 266,378 262,409 266,085 269,278 282,123 283,427 281,063 259,302 268,611 268,040 243,387 253,459 248,610 242,790 228,808 222,519 225,499 228,541 228,404 211,018 205,494 187,168 87,181 85,082
$5,604,676
- Assumes a 4 56% interest rate for the 1999A SWAP and a 517% interest rate for the 1999D SWAP At left is a summary of the debt service deposit requinements for bonds outstanding at December 31, 2001. This table reflects pnncipal debt service included in the designated year's rates In accordance with the resolution, these moneys are deposited into the Bond Fund for payment of the following year's current maturities Current maturities of $64,290,000 at December 3 1, 2001 sxere collected through rates during 2001 and deposited monthly into the Bond Fund to make the January 1, 2002 principal payment The lair market value of the Agency's long termn debt was estimated using the Dobbins Scale The individual maturities ssere priced and summed to arrive at a fair mai ket value of $3,244,498,000 and
$3,360,260,000 at December 31, 2001 and 2000, respecti ely.
Certain proceeds of the Series 1985 G, 1986A, 1988 A, 1989 A, 1991 A, 1993 B, 1993 C, 1995 A. 1996 A, 1997 A, 1999A, 1999 B, and 1999 C bonds, %%ere used to establish trusts for refunding
$4,297,580,000 of pre% rously issued bonds.
At December 3 1, 2001, $3,852,350,000 of these bonds have been redeemed Under these Refunding Trust Agreements, obligations of or guaranteed by, the United States have been placed in irreNocable Refunding Trust Funds maintained by the Bond Fund Trustee The govemment obligations in the Refunding Trust Funds, along with the interest earnings thereon, s ill be sufficient to pay all interest when due on the refunded bonds and to redeem all refunded bonds still outstanding at 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
?+T
1 K)
N j
[kt~Q (continued)
Funds, including the interest earnings thereon, are pledged solely for the benefit of the holders of the refunded bonds Since the establishment of each Refunding Trust Fund, the refunded bonds are no longer considered outstanding obligations of the Agency.
Interest on the bonds is payable semi annually. Certain of the bonds are subject to redemption prior to maturity at the option of the Agency, on or after the following dates, at a maximum of 102 1/2% of the respective principal amounts
"* Series 1986A January 1, 1996
"* Series 1988 A January 1, 1998
"* Series 1989 A January 1, 1999
"* Series 1991 A January 1, 2002
"* Series 1993 B, C, and D and Series 1985 G January 1, 2003
"* Series 1995 A January 1, 2006
"* Series 1996AandB January 1, 2007
"* Series 1997 A January 1, 2008
"* Series 1999 A and B January 1, 2009
"* Series 1999 D January 1, 2010 The bonds are special obligations of the Agency, payable solely from and secured solely by (1) revenues (as defined by the resolution) after payment of operating expenses (as defined by the resolution) and (2) other monies and securities pledged for payment thereof by the resolution.
The resolution requires the Agency to deposit into special funds all proceeds of bonds issued and all revenues (as defined by the resolution) generated as a result of the Initial Project Power Sales Agreements and the 1981 PCA. The purpose of the individual funds is specifically defined in the resolution I. SURETY BOND At December 31, 2001, the Agency had a $10,000,000 surety bond from an insurance company for the period June 13, 2001 to June 13, 2002 The term of the surety bond shall continue for consecutive one year terms unless written notice of termination is provided by the Agency or CP&L at least 60 days prior to the expira tion of the then current term. In accordance with a 2001 agreement between the Agency and CP&L, the surety bond replaces a
$12,900,000 letter of credit which expired on April 20, 2001, previously maintained by the Agency in accordance with the initial project agreements. The surety bond is for CP&L to call upon should the Agency fail to make full payment of its monthly obliga tions under the Operating and Fuel Agreement On each anniversary date of the surety bond, with 60 days prior notification to the Agency, CP&L may require an increase in the amount of the surety bond, not to exceed
$12,900,000 The Agency paid $112,000 for the surety bond in 2001 and paid quarterly commitment fees of $43,000 and $131,000 for 2001 and 2000, respectively, for the letter of credit.
J. COMMITMENTS The Agency has a contractual agreement with ElectriCities whereby ElectriCities provides, at cost, general management services to the Agency. This agreement continues through December 31, 2004, and is automatically renewed for successive three-year periods unless terminated by one year's notice by either party prior to the end of any contract term.
For the years ended December 31, 2001 and 2000, the Agency paid ElectnCities
$2,962,000 and $3,047,000, respectively K. CONTINGENCIES The Price-Anderson Act limits the public liability for a nuclear incident at a nuclear generating unit to $9,540,000,000, which amount is to be covered by private insurance and agreements of indemnity with the NRC. Such private insurance and agreements of indemnity are carried by CP&L on behalf of all co-owners of the initial project. The terms of this coverage require the owners of all licensed facilities to provide up to $88,100,000 per year per unit (adjusted annually for inflation) in the event of any nuclear incident involving any operating facility in the nation, with a maximum of $10,000,000 per year per unit owned in the event of more than one incident. The joint owners of a unit would be hable for the amount of any such assessment in proportion to their respective ownership interests.
The Price Anderson Act expires August 1, 2002. Although several renewal programs are before Congress, the final outcome cannot be predicted.
CP&L carries, for the benefit of the owners, property insurance on the various plants of the initial project. All risk coverage for the operating units ranges from
$100,000,000 to $500,000,000 with a deductible of $1,000,000. In addition, nuclear liability insurance exists in the form and amount necessary to meet the financial 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
- 9)
(3) 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
$(587-368)
Note. The schedule above hav beei prepaiedin a(tortdtn( e iut it the undetlvying Bond Re soltuomn, and
- mordinglx, doe% not mtejie I ttie lhamige uit tle fair value of tm estments mI of December 31, 2001 and 2000. repei tn eh/
See tcomnp*n rug hidependent Aduhtoi 5'Report 74 2001 Annual Report
Schedules of ©U'fav9ga In Assets of Funds Invested ($O00s)
Funds Invested Dec. 31, 2000
$ 6,319 0
6,319 Power Billing Receipts 0
0 95,264 212,573 69,193 0
0 0
377,030 21232 0
21,232 0
Investment Income 162 162 1,510 12,994 984 15,488 1,937 Transfers (193)
(1)
(194) 193,066 (11,129) 66,994 (3)
(91) 248,837 1,961 1,961 (118)
(304,082)
(16,900)
(23,793)
(4,023)
(348,798) 108,162 (8,844) 99,318 22,920 (6,436)
(17,490)
(1,006) 0 1,937 Disbursements
$ (6,479)
(6,479)
(192,450)
(68,805)
(261,255)
(19,612)
(19,612)
Transfers 0
0 188,925 (15,620) 63,033 236,338 19,128 19,128 238 4,196 1,043 26,650 0
11,042 4,468 42,160 24507 25,241 49,748 33,532 24,873 1,531 59,936
$561,664 327,716 327,716 0
54,050 40,294 94,344
$422,060 57 815 28 72 915 1,829 1,829 1,162 1,058 354 2,574
$23200 247 247 (110,983)
(110,983)
(111,189)
(111,189)
$(509271)
(71)
(344,551)
(4,077)
(3,935)
(352,563) 106,703 (935) 105,768 58,217 (25,485)
(41,33 (8,60 0
Funds Invested Dec. 31,2001 2
0 2
93249 209,947 64,405 0
0 0
367,601 22,685 0
22,685 4,434 1,029 10,877 0
6,993 605 18,475 22,056 24,306 46,362 35,772 446 847 37,065
$497,653 Note: The schedule above has been prepared in accordance with the underlying Bond Resolution, and accordingly, does not reflect the change in the fair value of wm'estments as of December 31, 2001 and 2000, respectively See accompanying Independent Auditors' Report 2001 Annual Report 1 75 0
A I
1 j"
Per Bond Resolution and Other Agreements (SO00s)
Year Ended December 31, 2001 1',ar Ended Decembe, 31. 2000 Initial Project Revenues:
Sales of electricity to participants Sales of electricity to utilities Rate stabilization fund xu ithdrawal Special funds N aluations Special supplemental resen e fund withdraxx I Other operating re% enues Investment reN enue available for operations Expenses:
Operation and maintenance Fuel Po\\, er coordination sen ices:
Purchased power Tran*sission and distribution Other Adminmstram e and general - CP&L Adniinistrati\\ e and general -Agency Amounts in lieu of taxes Gross receipts tax Letters of credit commnitent fees and administrat*xe costs Debt sen ice Special funds deposits Supplemental Total 3332,419
$ 92,462
$424.881 33,279 33,279 8,012 25,485 33.497 4,084 4,084 2.000 2,000 93 93 20,303 398,190 38,639 36,148 1,579 121,526 Initial Projei t S310,514 33,910 27,816 19,496 164 21,882 24.237 519,716 416,137 5
38,644 36,148 7,624 99.647 14.210 439 7624 114.296 19,188 2,848 3,857 10,704 673 248.633 4,086 2,627 107,271 14,210 439 121,920 19,188 6,934 3,857 13,331 673 162 248 825 Squplemental Fatal
$112,421 S422,935 33.910 6,435 34,251 19,496 0
39 203 1,620 120.515 38,930 34,179 25,857 536,652 4
38,934 34,179 7,090 95,972 16,103 240 7.090 112,315 25.671 3,299 3,991 9,998 128 263,025 3,959 3.542 103.062 16,103 240 119,405 25,671 7,258 3,991 13,540 128 1,04-4 264,069 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 in aroidtan e uitih the undcmlenh Bond Rewhcion, and arroidugh; doer not re/let tii theange in the fair /ahte of tmiienctis or of Dec ember 3/, 2001 rind 2000, terpettn elv See iti ronipoiiang
- ndependent Anthtor "Repoi t 76 2001 Ann al Report
2
7'
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
The Harris sellback increased from 331/3% in 1992 to 50% in 1993 and 1994 as part of the Hams litigation settlement, then reduced to 33 1/3%
until the sellback ends in 2007.
2001 Annual Report 177
-HIIIHIIIIIHI