-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PCb+icdOdO3nBCWnrWSNm4Om+op/chzp1qqfHXOTCrSvkyzT9tdsI+m5FYMRHldw l3FgfsJYmsnhpBD7jBTQcg== 0000004904-00-000056.txt : 20000414 0000004904-00-000056.hdr.sgml : 20000414 ACCESSION NUMBER: 0000004904-00-000056 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000413 FILER: COMPANY DATA: COMPANY CONFORMED NAME: APPALACHIAN POWER CO CENTRAL INDEX KEY: 0000006879 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 540124790 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-03457 FILM NUMBER: 599885 BUSINESS ADDRESS: STREET 1: 40 FRANKLIN RD SW CITY: ROANOKE STATE: VA ZIP: 24011 BUSINESS PHONE: 7039852300 MAIL ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 10-K405/A 1 AMENDMENT TO APCO 10-K405 - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 ---------------------------- FORM 10-K/A Amendment No. 1 ---------------------------- (Mark One) |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____________ to ______________ COMMISSION REGISTRANT; STATE OF INCORPORATION; I.R.S. EMPLOYER FILE NUMBER ADDRESS AND TELEPHONE NUMBER IDENTIFICATION NO. - ----------- ----------------------------------- ------------------ 1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640 (A New York Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP GENERATING COMPANY 31-1033833 (An Ohio Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 APPALACHIAN POWER COMPANY 54-0124790 (A Virginia Corporation) 40 Franklin Road, S.W. Roanoke, Virginia 24011 Telephone (540) 985-2300 1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203 (An Ohio Corporation) 1 Riverside Plaza Columbus, Ohio 43215 Telephone (614) 223-1000 1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455 (An Indiana Corporation) One Summit Square P. O. Box 60 Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY 61-0247775 (A Kentucky Corporation) 1701 Central Avenue Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 OHIO POWER COMPANY 31-4271000 (An Ohio Corporation) 301 Cleveland Avenue, S.W. Canton, Ohio 44702 Telephone (330) 456-8173 AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K. SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE REGISTRANT TITLE OF EACH CLASS ON WHICH REGISTERED ---------- ------------------- --------------------- AEP Generating Company None American Electric Common Stock, Power Company, Inc. $6.50 par value.................................. New York Stock Exchange Appalachian Power Cumulative Preferred Stock, Company Voting, no par value: 4-1/2%.......................................... Philadelphia Stock Exchange 8-1/4% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026........................................ New York Stock Exchange 8% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027........................................ New York Stock Exchange 7.20% Senior Notes, Series A, Due 2038........................................ New York Stock Exchange 7.30% Senior Notes, Series B, Due 2038..........................................New York Stock Exchange Columbus Southern 8-3/8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2025........................................ New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027........................................ New York Stock Exchange Indiana Michigan 8% Junior Subordinated Deferrable Power Company Interest Debentures, Series A, Due 2026........................................ New York Stock Exchange 7.60% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2038..........................................New York Stock Exchange Kentucky Power 8.72% Junior Subordinated Deferrable Company Interest Debentures, Series A, Due 2025........................................ New York Stock Exchange Ohio Power Company 8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025........................................ New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027..........................................New York Stock Exchange 7 3/8% Senior Notes, Series A, Due 2038........................................ New York Stock Exchange
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X . No. --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF EACH CLASS ---------- ------------------- AEP Generating Company None American Electric Power Company, Inc None Appalachian Power Company None Columbus Southern Power Company None Indiana Michigan Power Company 4-1/8% Cumulative Preferred Stock, Non-Voting, $100 par value Kentucky Power Company None Ohio Power Company 4-1/2% Cumulative Preferred Stock, Voting, $100 par value
AGGREGATE MARKET VALUE OF VOTING AND NON-VOTING NUMBER OF SHARES COMMON EQUITY HELD OF COMMON STOCK BY NON-AFFILIATES OF OUTSTANDING OF THE REGISTRANTS AT THE REGISTRANTS AT FEBRUARY 1, 2000 FEBRUARY 1, 2000 ------------------------- --------------------- AEP Generating Company None 1,000 ($1,000 par value) American Electric Power Company, Inc $6,538,856,569 194,103,349 ($6.50 par value) Appalachian Power Company None 13,499,500 (no par value) Columbus Southern Power Company None 16,410,426 (no par value) Indiana Michigan Power Company None 1,400,000 (no par value) Kentucky Power Company None 1,009,000 ($50 par value) Ohio Power Company None 27,952,473 (no par value)
NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES All of the common stock of AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company is owned by American Electric Power Company, Inc. (see Item 12 herein). DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K INTO WHICH DOCUMENT DESCRIPTION IS INCORPORATED - ----------- ------------------- Portions of Annual Reports of the following companies for the fiscal year Part II ended December 31, 1999: AEP Generating Company American Electric Power Company, Inc. Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Portions of Proxy Statement of American Electric Power Company, Inc. for Part III 2000 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1999 Portions of Information Statements of the following companies for 2000 Part III Annual Meeting of Shareholders, to be filed within 120 days after December 31, 1999 Appalachian Power Company Ohio Power Company
------------------------------ THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY, AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY AND OHIO POWER COMPANY. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY, INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS. - -------------------------------------------------------------------------------- EXPLANATORY NOTE This Amendment No. 1 to Form 10-K for the fiscal year ended December 31, 1999, is filed in order to provide those portions of the APCo 1999 Annual Report for the fiscal year ended December 31, 1999 as Exhibit 13. The APCo 1998 Annual Report was inadvertently filed as Exhibit 13 in the original filing. SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to the report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. APPALACHIAN POWER COMPANY BY: /S/ A. A. PENA A. A. Pena, Vice President EX-13 2 AMENDED APCO 1999 ANNUAL REPORT
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data Year Ended December 31, 1999 1998 1997 1996 1995 (in thousands) INCOME STATEMENTS DATA: Operating Revenues $1,650,937 $1,672,244 $1,628,515 $1,624,869 $1,545,039 Operating Expenses 1,409,701 1,443,701 1,388,521 1,381,993 1,317,937 Operating Income 241,236 228,543 239,994 242,876 227,102 Nonoperating Income (Loss) 8,096 (8,301) (222) 128 (4,699) Income Before Interest Charges 249,332 220,242 239,772 243,004 222,403 Interest Charges 128,840 126,912 119,258 109,315 106,503 Net Income 120,492 93,330 120,514 133,689 115,900 Preferred Stock Dividend Requirements 2,706 2,497 7,006 15,938 16,405 Earnings Applicable to Common Stock $ 117,786 $ 90,833 $ 113,508 $ 117,751 $ 99,495 December 31, 1999 1998 1997 1996 1995 (in thousands) BALANCE SHEETS DATA: Electric Utility Plant $5,262,951 $5,087,359 $4,901,046 $4,717,132 $4,558,436 Accumulated Depreciation and Amortization 2,079,490 1,984,856 1,869,057 1,782,017 1,694,746 Net Electric Utility Plant $3,183,461 $3,102,503 $3,031,989 $2,935,115 $2,863,690 Total Assets $4,354,400 $4,047,038 $3,883,430 $3,800,737 $3,723,975 Common Stock and Paid-in Capital $ 974,717 $ 924,091 $ 873,506 $ 835,838 $ 785,509 Retained Earnings 175,854 179,461 207,544 208,472 199,021 Total Common Shareholder's Equity $1,150,571 $1,103,552 $1,081,050 $1,044,310 $ 984,530 Cumulative Preferred Stock: Not Subject to Mandatory Redemption $ 18,491 $ 19,359 $ 19,747 $ 29,815 $ 55,000 Subject to Mandatory Redemption (a) 20,310 22,310 22,310 190,000 190,235 Total Cumulative Preferred Stock $ 38,801 $ 41,669 $ 42,057 $ 219,815 $ 245,235 Long-term Debt (a) $1,665,307 $1,552,455 $1,494,535 $1,365,842 $1,285,684 Obligations Under Capital Leases (a) $ 64,645 $ 65,175 $ 60,110 $ 51,969 $ 48,937 Total Capitalization and Liabilities $4,354,400 $4,047,038 $3,883,430 $3,800,737 $3,723,975
(a) Including portion due within one year. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors that could cause actual results to differ materially from forward looking statements are: electric load and customer growth; abnormal weather conditions; available sources and costs of fuels; availability of generating capacity; the ability to recover generation-related regulatory assets and other transition costs including stranded costs under the Virginia and West Virginia restructuring plans; new legislation and government regulations; the ability of the Company to successfully control its costs; the economic climate and growth in our service territory; the outcome of litigation with the Internal Revenue Service (IRS) related to certain interest deductions for a corporate owned life insurance (COLI) program; the ability of the Company to successfully challenge new environmental regulations and to successfully litigate claims that the Company violated the Clean Air Act; inflationary trends; changes in electricity market prices; interest rates; and other risks and unforeseen events. Appalachian Power Company (the Company) is a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public utility holding company. The Company is engaged in the generation, purchase, sale, transmission and distribution of electric power to 896,000 retail customers in southwestern Virginia and southern West Virginia and does business as American Electric Power (AEP). The Company as a member of the AEP System Power Pool (AEP Power Pool) shares the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers. The Company also sells wholesale power to municipalities. The cost of the AEP System's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment or receipt of capacity charges and credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each Company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each Company's percentage share of revenues or costs. Since the Company's MLR decreased in 1999 and 1998, the AEP Power Pool is allocating a smaller share of Power Pool revenues and expenses to the Company. Results of Operations Net Income Net income increased $27.2 million or 29% in 1999 primarily due to a nonoperating gain in 1999 on the sale of real estate and mining assets by the Company's inactive mining subsidiaries and a decline in operating expenses. Although operating revenues increased in 1998, net income declined $27.2 million or 23% due primarily to increased fuel and maintenance expenses, losses on non-regulated electricity trading outside of the AEP Power Pool's traditional marketing area, increased interest charges and provisions for revenue refunds. Operating Revenues Operating revenues decreased 1% in 1999 primarily due to a decrease in wholesale sales and a decline in net revenues reflecting lower margins on wholesale trading transactions. An increase of 3% in operating revenues in 1998 was primarily due to increased revenues from regulated electricity trading and transmission services. The changes in the components of revenues were as follows: Increase (Decrease) From Previous Year (dollars in millions) 1999 1998 Amount % Amount % Retail: Residential $ 19.4 $(5.1) Commercial 17.1 2.3 Industrial (4.4) (0.3) Other 0.9 2.2 33.0 2.6 (0.9) (0.1) Wholesale (80.6)(23.0) 30.7 9.6 Transmission (3.4) (7.3) 19.3 69.9 Miscellaneous 29.7 186.9 (5.4) (25.5) Total $(21.3) (1.3) $43.7 2.7 Revenue from retail customers increased in 1999 primarily due to a 2% increase in retail sales reflecting higher residential and commercial sales. The increase in retail sales is primarily due to colder winter weather and customer growth. The decline in wholesale revenues in 1999 reflects the termination of a contract with several municipal customers in July 1998 and a decline in margins on regulated power trading transactions. The decline in margins reflects the moderation in 1999 of extreme weather in 1998 and capacity shortage experienced in the summer of 1998. The volume of power trading grew substantially during 1998 and accounted for the increase in wholesale revenues in 1998. Trading revenues are recorded net of purchases. Transmission service revenues increased in 1998 due to a substantial rise in the volume of energy transmitted for other entities over the AEP System's transmission lines. The issuance of open access transmission rules by the Federal Energy Regulatory Commission (FERC) facilitated the growth in transmission services. The Company receives its MLR share of AEP System transmission revenues. The increase in miscellaneous revenues in 1999 reflects a favorable adjustment to a provision for revenue refunds recorded in connection with the execution of a final rate refund and an increase in rental revenues from billings to telecommunications companies for pole attachments. In 1998 miscellaneous revenues declined due to the recordation of provisions for revenue refunds under final rate orders. Operating Expenses Operating expenses decreased by 2% in 1999 and increased 4% in 1998. The decline in purchased power expense is the primary reason for the decrease in operating expenses in 1999. Operating expenses increased in 1998 mainly due to increased fuel and maintenance costs. Changes in the components of operating expenses were as follows: Increase (Decrease) From Previous Year (dollars in millions) 1999 1998 Amount % Amount % Fuel $ 7.2 1.6 $33.7 8.4 Purchased Power (49.0) (16.2) (8.4) (2.7) Other Operation (5.1) (2.0) 7.9 3.2 Maintenance (11.0) (8.2) 22.0 19.5 Depreciation and Amortization 5.1 3.5 6.1 4.5 Taxes Other Than Federal Income Taxes 1.5 1.4 (0.5) (0.4) Federal Income Taxes 17.3 32.2 (5.6) (9.6) Total $(34.0) (2.4) $55.2 4.0 The increases in fuel expense in 1999 and 1998 are primarily due to increases in generation reflecting greater utilization of internally generated power. The reductions in purchased power expense in 1999 and 1998 were primarily due to reduced capacity charges from the AEP Power Pool as a result of declines in the Company's MLR and decreased purchases from the AEP Power Pool. The decline in purchases from the AEP Power Pool can be attributed to increased internal generation and the termination of the contract with several municipal customers. Maintenance expense decreased in 1999 and increased in 1998 primarily as a result of expenditures during 1998 to restore service and make repairs following two severe snowstorms. Also contributing to the increase in maintenance expense in 1998 were expenditures to clear and maintain right-of-ways. The increase in federal income taxes attributable to operations in 1999 is primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes. Federal income taxes attributable to operations decreased in 1998 primarily due to a decline in pre-tax operating income. Nonoperating Income The increase in nonoperating income in 1999 is primarily due to the effect of non-regulated electricity trading and a gain on the sale of coal lands and mining assets by the Company's inactive coal mining subsidiaries. In 1999 nonoperating income included a gain from non-regulated electricity trading transactions, which are outside the AEP Power Pool's traditional marketing area, whereas 1998 included a net loss. In November 1999 the subsidiaries sold coal lands and mining assets which had been leased by an unaffiliated company. Nonoperating income declined in 1998 primarily due to net losses from non-regulated electricity trading transactions outside of the AEP Power Pool's traditional marketing area which are marked-to-market. Interest Charges The increase in interest charges in 1998 is primarily due to increased long-term borrowings and the accrual of interest to be paid to customers under rate refund orders. Business Outlook The most significant factors affecting the Company's future earnings are its ability to recover regulatory assets, transition and other stranded costs under the Virginia and West Virginia restructuring plans; weather in the service territories served by the Company and its wholesale customers; generating unit availability; the outcome of litigation with the IRS related to certain interest deductions for COLI; and the outcome of ongoing environmental litigation and challenges to proposed air quality standards. In 1999 significant progress was made related to many of these major challenges. Virginia Restructuring In March 1999 a law was enacted in Virginia to restructure the electric utility industry. Under the restructuring law, a transition to choice of electricity supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on or before January 1, 2004. The law also provides an opportunity to recover just and reasonable net stranded generation costs. The mechanisms in the Virginia law for net stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001 and the establishment of a wires charge by the fourth quarter of 2001. West Virginia Restructuring On January 28, 2000, after over three years of workshops, hearings and negotiations, the Public Service Commission of West Virginia (WVPSC) issued an order approving an electricity restructuring plan for West Virginia. The restructuring plan has been submitted to the West Virginia Legislature for approval or rejection. The provisions of the proposed restructuring plan provide for customer choice to begin on January 1, 2001, or at a later date set by the WVPSC after all necessary rules are in place (the "starting date"); deregulation of generating assets occurring on the starting date; functional separation of the generation, transmission and distribution businesses on the start date and their legal corporate separation no later than January 1, 2005; a transition period of up to 13 years, during which the incumbent utility must provide default service for customers who do not change suppliers unless an alternative default supplier is selected through a WVPSC-sponsored bidding process; capped and fixed rates for the 13 year transition period as discussed below; deregulation of metering and billing; a 0.5 mills per kwh wires charge applicable to all retail customers for the period January 1, 2001 through December 31, 2010 intended to provide for recovery of stranded cost including net regulatory assets; and establishment of a rate stabilization deferred balance by the Company of $76 million by the end of year ten of the transition period to be used as determined by the WVPSC to offset prices paid in the eleventh, twelfth, and thirteenth year of the transition period by residential and small commercial customers that do not choose a supplier. Default rates for residential and small commercial customers are capped for four years after the starting date and then increased as specified in the plan for the next six years. In years eleven, twelve and thirteen of the transition period, the power supply rate shall equal the market price of comparable power. Default rates for industrial and large commercial customers are discounted by 1% for four and a half years, beginning July 1, 2000, and then increased at pre-defined levels for the next three years. After seven years the power supply rate for industrial and large commercial customers will be market based. Regulatory/Restructuring Accounting Under the provisions of Statement of Financial Accounting Standards (SFAS) 71 "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (deferred revenues) are included in the consolidated balance sheets of cost-based regulated utilities in accordance with regulatory actions to match expenses and revenues. In order to maintain net regulatory assets on the balance sheet, SFAS 71 requires that rates charged to customers be cost-based and provide for the probable recovery of regulatory assets over future accounting periods. Management has concluded that as of December 31, 1999 the requirements to apply SFAS 71 continue to be met for all jurisdictions. However, the recent legislation in Virginia will result in the discontinuance of SFAS 71 regulatory accounting for the generation portion of the Virginia jurisdiction. When the restructuring plan is enacted into law it will result in the discontinuance of SFAS 71 regulatory accounting for the generation portion of the West Virginia jurisdiction. In the event a portion of the Company's business no longer meets the requirements of SFAS 71, SFAS 101 "Accounting for the Discontinuance of Application of Statement 71" requires that net regulatory assets be written off for that portion of the business. The provisions of SFAS 71 and SFAS 101 did not anticipate or provide accounting guidance for an extended transition period and for recovery of stranded costs during and after a transition period through a wires charge or regulated distribution rates. In July 1997 the Financial Accounting Standards Board's (FASB) Emerging Issues Task Force (EITF) addressed such a situation with the consensus reached on issue 97-4 that requires that the application of SFAS 71 to a segment of a regulated electric utility cease when that segment is subject to a legislatively approved plan for transition to competitive market pricing from cost-based regulated rates and/or a rate order is issued containing sufficient detail for the utility to reasonably determine what the restructuring plan would entail and how it will affect the utility's financial statements. The EITF indicated that the cessation of application of SFAS 71 regulatory accounting would require that regulatory assets and impaired stranded plant cost applicable to the portion of the business that was no longer cost-based regulated, be written off unless they are recoverable in the future through transition rates and/or post-transition cost-based regulated rates. Potential For Write Offs In Virginia And West Virginia Jurisdictions The Company's accounting for generation will continue to be in accordance with SFAS 71 in the Virginia jurisdiction and will continue to be considered to be cost-based regulated for accounting purposes until the amount of transition rates and stranded cost wires charges are determined and known. The establishment of transition rates and wire charges should enable management to determine the Company's ability to recover stranded costs including regulatory assets and transition costs, a requirement under EITF 97-4 to discontinue application of SFAS 71. The application of SFAS 71 will be discontinued for the Virginia retail jurisdictional portion of the Company's generation business when the capped rates and the wires charge are known in Virginia which is expected to occur by the fourth quarter of 2000. In the West Virginia jurisdiction accounting for generation will continue to be in accordance with SFAS 71 and the generation business will continue to be considered to be cost-based regulated for accounting purposes until the proposed restructuring plan is enacted into law. The application of SFAS 71 for the generation portion of the West Virginia jurisdiction will be discontinued when the restructuring plan is enacted into law and when the WVPSC approves the rate stipulation filed with the Commission. Together these two documents provide sufficient information for management to determine the impact of restructuring on the Company's financial statements. Upon the discontinuance of SFAS 71 the Company will have to write off its Virginia and West Virginia jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the frozen transition rates and stranded costs distribution wires charges and record any asset accounting impairments. An impairment loss would be recorded to the extent that the cost of generation assets cannot be recovered through non-discounted generation-related revenues during the transition period and future market prices. Absent the determination in the legislative or regulatory process of transition rates, any wires charge and other pertinent information, it is not possible at this time for management to determine if any of the Company's generating assets are impaired for accounting purposes on an undiscounted cash flow basis. The amount of regulatory assets recorded on the books at December 31, 1999 applicable to the Virginia and West Virginia retail jurisdictional generation business before related tax effects is estimated to be $64 million and $131 million, respectively. Based on current projections of future market prices, the Company does not anticipate that it will experience material tangible asset accounting impairment write-offs. Whether the Company will experience material regulatory asset write-offs will depend on whether the capped transition rates and allowed wires charges in Virginia and West Virginia will permit their recovery. An estimated determination of whether the Company will experience any asset impairment loss regarding its Virginia and West Virginia retail jurisdictional generating assets and any loss from the possible inability to recover Virginia and West Virginia generation related regulatory assets and other transition costs cannot be made until such time as the transition rates and the wires charges are determined through the regulatory or legislative process. Should the Virginia SCC fail to approve transition rates and wires charges that are sufficient to provide for recovery or the West Virginia Legislature approves a restructuring plan that does not provide for recovery of the Company's generation-related regulatory assets, any other stranded costs and transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. The Company's firm wholesale sales are a relatively small part of its business and are still under cost-of-service contracts. Customer choice and competition for these sales could also ultimately result in adverse impacts on results of operations and cash flows depending on the future market prices of electricity. Environmental Concerns and Issues We take great pride in our efforts to economically produce and deliver electricity while minimizing the impact on the environment. Over the years the Company has spent hundreds of millions of dollars to equip its facilities with the latest cost effective clean air and water technologies and to research new technologies. We intend to continue in a leadership role fostering economically prudent efforts to protect and preserve the environment while providing a vital commodity, electricity, to our customers at a fair price. Air Quality In 1998 United States (U.S.) Environmental Protection Agency (Federal EPA) issued a final rule which requires substantial reductions in nitrogen oxide (NOx) emissions in 22 eastern states, including the states in which the Company's generating plants are located. A number of utilities, including the Company, filed petitions seeking a review of the final rule in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). On March 3, 2000, the Appeals Court issued a decision generally upholding Federal EPA's final rule on NOx emission reductions. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to the Clean Air Act (Section 126 Rule). The Rule approved portions of the states' petitions and imposed NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rule. The AEP System companies with coal-fired generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of the Section 126 Rule. In 1999, three additional northeastern states and the District of Columbia filed petitions with Federal EPA similar to those originally filed by the eight northeastern states. Since the petitions relied in part on compliance with an 8-hour ozone standard remanded by the Appeals Court, Federal EPA indicated its intent to decouple compliance with the 8-hour standard and issue a revised rule. On December 17, 1999, Federal EPA issued a revised Section 126 Rule requiring 392 industrial plants, including certain generating plants owned by the Company, to reduce their NOx emissions by May 1, 2003. This rule approves petitions of four northeastern states which contend that their failure to meet Federal EPA smog standards is due to coal-fired generating plants in upwind states, including many of the Company's plants, and not their automobiles and other local sources. Preliminary estimates indicate that compliance with the Federal EPA's final rule on NOx emission reductions that was upheld by the Appeals Court could result in required capital expenditures of approximately $365 million for the Company. It should be noted, however, that compliance costs cannot be estimated with certainty since actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless compliance costs are recovered from customers through regulated rates, unbundled generation transition rates, wires charges and the future market price of electricity, such compliance costs will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation Under the Clean Air Act, if a plant undergoes a major modification that results in a significant emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. On November 3, 1999, the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company and its affiliates in the AEP System made modifications to certain of their coal-fired generating plants over the course of the past 25 years that extend their operating lives or increase their generating capacity in violation of the Clean Air Act. Federal EPA also issued Notices of Violation to the Company and its affiliates in the AEP System alleging violations of certain provisions of the Clean Air Act at certain plants. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. The states of New Jersey, New York and Connecticut were subsequently allowed to join Federal EPA's action against the Company under the Clean Air Act. On November 18, 1999, a number of environmental groups filed a lawsuit against power plants owned by the Company and its affiliates in the AEP System alleging similar violations to those in the Federal EPA complaint and Notices of Violation. This action has been consolidated with the Federal EPA action. The complaints and Notices of Violation named four of the Company's six coal-fired generating plants. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act provisions and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, approved unbundled transition generation rates, wires charges and future market prices for electricity. Financial Condition The Company issued $230 million principal amount of long-term obligations in 1999 at interest rates ranging from 6.05% to 7.45% and received from its parent a $50 million capital contribution. The principal amount of long-term debt retirements, including maturities, totaled $117 million with interest rates ranging from 7% to 8.43%. The Company's senior secured debt/first mortgage bond ratings are: Moody's, A3; Standard and Poor's (S&P), A; Fitch, A; and Duff & Phelps, LLC (D & P), A. Gross plant and property additions were $225 million in 1999 and $226 million in 1998. Management estimates construction expenditures for the next three years to be $839 million. The funds for construction of new facilities and improvement of existing facilities can come from a combination of internally generated funds, short-term and long-term borrowings and investments in common equity by AEP Co., Inc. Approximately 70% of the construction expenditures for the next three years are expected to be financed with internally generated funds. When necessary the Company generally issues short-term debt to provide for interim financing of capital expenditures that exceed internally generated funds. At December 31, 1999, $1,056 million of unused short-term lines of credit shared with other AEP System companies were available. Short-term debt borrowings are limited by provisions of the 1935 Act to $325 million. Generally periodic reductions of outstanding short-term debt are made through issuances of long-term debt and through additional capital contributions by the parent company. The Company's earnings coverage presently exceeds all minimum coverage requirements for the issuance of mortgage bonds and preferred stock. The minimum coverage ratio is 2.0 for mortgage bonds and 1.5 for preferred stock. At December 31, 1999, the mortgage bonds and preferred stock coverage ratios were 5.29 and 1.89, respectively. Market Risks The Company has certain market risks inherent in its business activities from changes in electricity commodity prices and interest rates. The allocation of trading of electricity and related financial derivative instruments through the AEP Power Pool exposes the Company to market risk. Market risk represents the risk of loss that may impact the Company due to adverse changes in electricity commodity market prices and rates. Policies and procedures have been established to identify, access and manage market risk exposures including the use of a risk measurement model which calculates Value at Risk (VaR). The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a three-day holding period. Throughout 1999 and 1998, the Company's share of the highest, lowest and average quarterly VaR in the wholesale trading portfolio was less than $4 million and $3 million, respectively. Based on this VaR analysis, at December 31, 1999 a near term change in electricity commodity prices is not expected to have a material effect on the Company's results of operations, cash flows or financial condition. The Company is exposed to changes in interest rates primarily due to short-term and long-term borrowings to fund its business operations. The debt portfolio has fixed and variable interest rates with terms from one day to 39 years and an average duration of eight years at December 31, 1999. The Company measures interest rate market risk exposure utilizing a VaR model. The model is based on a Monte Carlo method of simulated price movements with a 95% confidence level and a one year holding period. The volatilities and correlations are based on three years of weekly prices. The risk of potential loss in fair value attributable to the Company's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $218 million at December 31, 1999 and $135 million at December 31, 1998. The Company would not expect to liquidate its entire debt portfolio in a one year holding period. Therefore, a near term change in interest rates should not materially affect results of operations or the consolidated financial position of the Company. Inflation affects the Company's cost of replacing utility plant and the cost of operating and maintaining its plant. The rate-making process limits recovery to the historical cost of assets resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis. However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses. Litigation Corporate Owned Life Insurance The IRS agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions claimed by the Company relating to a COLI program should not be allowed. As a result of a suit filed by the Company in U.S. District Court (discussed below) this request for ruling was withdrawn by the IRS agents. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through December 31, 1999 would reduce earnings by approximately $79 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. The payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refund through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the U.S. in the U.S. District Court for the Southern District of Ohio in March 1998. In 1999 a U.S. Tax Court judge decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI deductions should be disallowed. Notwithstanding the Tax Court's decision in Winn-Dixie, management has made no provision for any possible adverse earnings impact from this matter because it believes, and has been advised by outside counsel, that it has a meritorious position and will vigorously pursue its lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. The Company is involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on the results of operations, cash flows and/or financial condition. Other Matters Superfund By-products from the generation of electricity include materials such as ash, slag and sludge. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials. The Company is currently incurring costs to safely dispose of such substances. Additional costs could be incurred to comply with new laws and regulations if enacted. The Comprehensive Environmental Response, Compensation and Liability Act (Superfund) addresses clean-up of hazardous substances at disposal sites and authorized Federal EPA to administer the clean-up programs. As of year-end 1999, there are two sites for which the Company has received information requests which could lead to potentially responsible party (PRP) designations. The Company's liability has been resolved for a number of sites with no significant effect on results of operations and present estimates do not anticipate material cleanup costs for identified sites. However, if for reasons not currently identified significant costs are incurred for cleanup, future results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be recovered from customers. The Clean Air Act Amendments (CAAA) required Federal EPA to issue rules to implement the law. In 1996 Federal EPA issued final rules governing NOx emissions that must be met after January 1, 2000 (Phase II of the CAAA). The final rules required substantial reductions in NOx emissions from certain types of boilers including those in the power plants of the Company and its affiliates in the AEP System. To comply with Phase II of CAAA, the Company installed NOx emission control equipment on certain units and switched fuel at other units. The Company is operating under the Phase II rules which require reporting at the end of each year. The Company does not anticipate any material problems complying with the rules. At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many scientists believe are contributing to global climate change. The treaty, which requires the advice and consent of the U.S. Senate for ratification, would require the U.S. to reduce greenhouse gas emissions seven percent below 1990 levels in the years 2008-2012. Although the U.S. has agreed to the treaty and signed it on November 12, 1998, President Clinton has indicated that he will not submit the treaty to the Senate for consideration until it contains requirements for "meaningful participation by key developing countries" and the rules, procedures, methodologies and guidelines of the treaty's emissions trading and joint implementation programs and compliance enforcement provisions have been negotiated. At the Fourth Conference of the Parties, held in Buenos Aires, Argentina, in November 1998, the parties agreed to a work plan to complete negotiations on outstanding issues with a view toward approving them at the Sixth Conference of the Parties to be held in November 2000. We will continue to work with the Administration and Congress to develop responsible public policy on this issue. If the Kyoto treaty is approved by Congress, the costs to comply with the emission reductions required by the treaty are expected to be substantial and would have a material adverse impact on results of operations, cash flows and possibly financial condition if not recovered from customers. It is management's belief, that the Kyoto protocol is unlikely to be ratified or implemented in the U.S. in its current form. Year 2000 Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems could have produced erroneous results or failed, unless these systems had been modified or replaced, because such systems have been programmed incorrectly and interpreted the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year or otherwise incorrectly interpret a year 2000 date. The Company has not experienced any material failures of generation or delivery of electric energy due to Year 2000 because of the AEP System's preparations. Such preparations included the modification or replacement of certain computer hardware and software to minimize Year 2000-related failures and repair. This included both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem was addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company sought written assurances from third parties regarding their state of Year 2000 readiness. Another issue addressed was the impact of electric power grid problems that may have occurred outside of our transmission system. Through December 31, 1999, the Company's share of the AEP System's expenditures on the Year 2000 project was $14 million. Most Year 2000 costs were for IT contractors and consultants and for salaries of internal IT professionals and were expensed; however, in certain cases the Company acquired hardware and new software that was capitalized. New Accounting Standards The FASB issued SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" in June 1998. SFAS 133 establishes accounting and reporting standards for derivative instruments. It requires that all derivatives be recognized as either an asset or a liability and measured at fair value in the financial statements. If certain conditions are met, a derivative may be designated as a hedge of possible changes in fair value of an asset, liability or firm commitment; variable cash flows of forecasted transactions; or foreign currency exposure. The accounting/reporting for changes in a derivative's fair value (gains and losses) depend on the intended use and resulting designation of the derivative. Management is currently studying the provisions of SFAS 133 and reviewing the Company's contracts and transactions to determine the impact on the Company's results of operations, cash flows and financial condition when SFAS 133 is adopted on January 1, 2001.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 1999 1998 1997 (in thousands) OPERATING REVENUES $1,650,937 $1,672,244 $1,628,515 OPERATING EXPENSES: Fuel 444,711 437,500 403,777 Purchased Power 254,100 303,116 311,514 Other Operation 249,616 254,718 246,785 Maintenance 123,834 134,856 112,873 Depreciation and Amortization 148,874 143,809 137,670 Taxes Other Than Federal Income Taxes 117,641 116,070 116,590 Federal Income Taxes 70,925 53,632 59,312 Total Operating Expenses 1,409,701 1,443,701 1,388,521 OPERATING INCOME 241,236 228,543 239,994 NONOPERATING INCOME (LOSS) 8,096 (8,301) (222) INCOME BEFORE INTEREST CHARGES 249,332 220,242 239,772 INTEREST CHARGES 128,840 126,912 119,258 NET INCOME 120,492 93,330 120,514 PREFERRED STOCK DIVIDEND REQUIREMENTS 2,706 2,497 7,006 EARNINGS APPLICABLE TO COMMON STOCK $ 117,786 $ 90,833 $ 113,508
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,014,968 $1,979,180 Transmission 1,151,377 1,118,726 Distribution 1,741,685 1,641,523 General 247,798 228,464 Construction Work in Progress 107,123 119,466 Total Electric Utility Plant 5,262,951 5,087,359 Accumulated Depreciation and Amortization 2,079,490 1,984,856 NET ELECTRIC UTILITY PLANT 3,183,461 3,102,503 OTHER PROPERTY AND INVESTMENTS 160,546 111,020 CURRENT ASSETS: Cash and Cash Equivalents 64,828 7,755 Accounts Receivable: Customers 109,525 122,746 Affiliated Companies 37,827 35,802 Miscellaneous 9,154 8,572 Allowance for Uncollectible Accounts (2,609) (2,234) Fuel - at average cost 58,161 49,826 Materials and Supplies - at average cost 56,917 60,440 Accrued Utility Revenues 53,418 45,985 Energy Marketing and Trading Contracts 143,777 22,436 Prepayments 7,713 8,151 TOTAL CURRENT ASSETS 538,711 359,479 REGULATORY ASSETS 436,894 433,516 DEFERRED CHARGES 34,788 40,520 TOTAL $4,354,400 $4,047,038
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 30,000,000 Shares Outstanding - 13,499,500 Shares $ 260,458 $ 260,458 Paid-in Capital 714,259 663,633 Retained Earnings 175,854 179,461 Total Common Shareholder's Equity 1,150,571 1,103,552 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 18,491 19,359 Subject to Mandatory Redemption 20,310 22,310 Long-term Debt 1,539,302 1,472,451 TOTAL CAPITALIZATION 2,728,674 2,617,672 OTHER NONCURRENT LIABILITIES 132,130 120,281 CURRENT LIABILITIES: Long-term Debt Due Within One Year 126,005 80,004 Short-term Debt 123,480 76,400 Accounts Payable - General 59,150 60,569 Accounts Payable - Affiliated Companies 42,459 50,313 Taxes Accrued 49,038 35,719 Customer Deposits 12,898 14,123 Interest Accrued 19,079 19,990 Revenue Refunds Accrued - 95,267 Energy Marketing and Trading Contracts 140,279 24,076 Other 71,044 78,808 TOTAL CURRENT LIABILITIES 643,432 535,269 DEFERRED INCOME TAXES 671,917 643,711 DEFERRED INVESTMENT TAX CREDITS 57,259 62,231 DEFERRED CREDITS 120,988 67,874 COMMITMENTS AND CONTINGENCIES (Notes 5 and 6) TOTAL $4,354,400 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 1999 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income $ 120,492 $ 93,330 $ 120,514 Adjustments for Noncash Items: Depreciation and Amortization 149,791 144,967 138,975 Deferred Federal Income Taxes 13,033 (2,338) (5,117) Deferred Investment Tax Credits (4,972) (5,265) (5,181) Deferred Power Supply Costs (net) 35,955 30,081 12,310 Provision for Rate Refunds 4,818 (31,019) 7,601 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 10,989 (1,562) (3,990) Fuel, Materials and Supplies (4,812) (5,006) 3,950 Accrued Utility Revenues (7,433) 5,223 635 Accounts Payable (9,273) 14,066 10,924 Taxes Accrued 13,319 (5,830) 614 Revenue Refunds Accrued (95,267) 91,956 (2,272) Payment of Disputed Tax and Interest Related to COLI (4,124) (68,316) - Net Book Value of Assets Sold (24,373) (9,286) (14,036) Change in Operating Reserves 7,451 10,052 8,872 Net Change in Unrealized (Gain) Loss on Forward Commitments (14,531) 3,529 (194) Other (net) (23,174) 9,582 6,908 Net Cash Flows From Operating Activities 167,889 274,164 280,513 INVESTING ACTIVITIES: Construction Expenditures (211,416) (204,869) (218,074) Proceeds from Sales of Property and Other 19,296 2,930 4,971 Net Cash Flows Used For Investing Activities (192,120) (201,939) (213,103) FINANCING ACTIVITIES: Capital Contributions from Parent Company 50,000 50,000 40,000 Issuance of Long-term Debt 227,236 211,944 183,257 Retirement of Cumulative Preferred Stock (2,675) (294) (183,875) Retirement of Long-term Debt (116,688) (157,973) (56,379) Change in Short-term Debt (net) 47,080 (53,900) 69,600 Dividends Paid on Common Stock (121,392) (118,916) (114,436) Dividends Paid on Cumulative Preferred Stock (2,257) (2,278) (5,890) Net Cash Flows From (Used For) Financing Activities 81,304 (71,417) (67,723) Net Increase (Decrease) in Cash and Cash Equivalents 57,073 808 (313) Cash and Cash Equivalents January 1 7,755 6,947 7,260 Cash and Cash Equivalents December 31 $ 64,828 $ 7,755 $ 6,947
See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, 1999 1998 1997 (in thousands) Retained Earnings January 1 $179,461 $207,544 $208,472 Net Income 120,492 93,330 120,514 299,953 300,874 328,986 Deductions: Cash Dividends Declared: Common Stock 121,392 118,916 114,436 Cumulative Preferred Stock: 4-1/2% Series 850 875 892 5.90% Series 425 455 455 5.92% Series 364 364 364 6.85% Series 579 579 579 7.80% Series - - 931 Total Cash Dividends Declared 123,610 121,189 117,657 Capital Stock Expense 489 224 3,785 Total Deductions 124,099 121,413 121,442 Retained Earnings December 31 $175,854 $179,461 $207,544
See Notes to Consolidated Financial Statements. APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SIGNIFICANT ACCOUNTING POLICIES: Organization Appalachian Power Company (the Company or APCo) is a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public utility holding company. The Company is engaged in the generation, purchase, sale, transmission and distribution of electric power to 896,000 retail customers in southwestern Virginia and southern West Virginia and does business as American Electric Power (AEP). Under the terms of the AEP System Power Pool (AEP Power Pool) and the AEP System Transmission Equalization Agreement, the Company's generation and transmission facilities are operated in conjunction with the facilities of certain other AEP affiliated utilities as an integrated utility system. The Company as a member of the AEP Power Pool shares in the revenues and costs of Power Pool wholesale sales to neighboring utility systems and power marketers. The Company also sells wholesale power to municipalities. The Company has four wholly-owned subsidiaries which are consolidated in these financial statements: Cedar Coal Co., Central Appalachian Coal Company and Southern Appalachian Coal Company (which were formerly engaged in coal mining and now lease their coal reserves to unaffiliated companies) and West Virginia Power Company (which is inactive). Regulation As a subsidiary of AEP Co., Inc., the Company is subject to the regulation of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). Retail rates are regulated by the State Corporation Commission of Virginia (Virginia SCC) and the Public Service Commission of West Virginia (WVPSC). The Federal Energy Regulatory Commission (FERC) regulates the Company's wholesale and transmission rates. Principles of Consolidation The consolidated financial statements include the revenues, expenses, cash flows, assets, liabilities and equity of APCo and its wholly-owned subsidiaries. Significant intercompany items are eliminated in consolidation. Basis of Accounting As a cost-based rate-regulated entity, APCo's financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets (deferred expenses) and regulatory liabilities (deferred income) are recorded to reflect the economic effects of regulation and to match expenses with regulated revenues. Use of Estimates The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of estimates. Actual results could differ from those estimates. Utility Plant Electric utility plant is stated at original cost and is generally subject to first mortgage liens. Additions, major replacements and betterments are added to the plant accounts. Retirements of plant are deducted from the electric utility plant in service account and deducted from accumulated depreciation together with associated removal costs, net of salvage. The costs of labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses. Allowance for Funds Used During Construction (AFUDC) AFUDC is a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of utility plant. It represents the estimated cost of borrowed and equity funds used to finance construction projects. In the Virginia jurisdiction, construction work in progress is included in rate base and earns a return in regulated rates in lieu of recording AFUDC. The amounts of AFUDC in 1999, 1998 and 1997 were not significant. Depreciation and Amortization Depreciation of electric utility plant is provided on a straight-line basis over the estimated useful lives of utility plant and is calculated largely through the use of composite rates by functional class. The annual composite depreciation rates for 1999, 1998 and 1997 are as follows: Annual Composite Functional Class Depreciation of Property Rates 1999 1998 1997 Production: Steam 3.4% 3.4% 3.4% Hydro 2.9% 2.8% 2.8% Transmission 2.2% 2.2% 2.2% Distribution 3.3% 3.3% 3.3% General 3.1% 3.1% 3.1% Expenditures for the demolition and removal of plant are charged to the accumulated provision for depreciation and recovered through depreciation charges included in rates. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with original maturities of three months or less. Operating Revenues Revenues include the accrual of electricity consumed but unbilled at month-end as well as billed revenues. Power Supply Costs and Fuel Costs The Company practices deferred accounting with respect to over or under collection of certain fuel and power supply costs pursuant to the Virginia SCC's fuel cost recovery mechanism. In the Virginia jurisdiction, changes in fuel costs and the fuel portion of purchased power costs are deferred and reviewed for recovery or refund annually by the Virginia SCC. In the West Virginia jurisdiction, under the terms of a 1996 settlement agreement, a modified version of deferral accounting was practiced for the over and under collection of fuel, AEP Power Pool capacity charges and certain transmission revenue for the period November 1996 through December 1999. Although a cumulative over and under recovery balance has been maintained, ratepayers will not be responsible for any cumulative underrecovery balance at December 31, 1999. Overrecoveries during the annual periods through December 31, 1999 in excess of $10 million per period would be accumulated and shared equally between the Company and its ratepayers. Overrecoveries under $10 million are not shared with ratepayers and are included in operating income annually. Under a pending rate settlement agreement, beginning January 1, 2000 deferral accounting for over or under recovery of fuel would be discontinued and the current cumulative overrecovery balance of $65.9 million shall remain on the Company's books as a regulatory liability. (see Note 4 "Rate Matters".) In addition, the cumulative overrecovery balance would be used to reduce unrecoverable generation-related regulatory assets and, to the extent possible, any additional cost or obligations that deregulation may impose (see Note 3 for discussion of West Virginia Restructuring Plan). Wholesale jurisdictional fuel cost changes are expensed and billed as incurred through a FERC fuel clause. Energy Marketing and Trading Transactions The AEP Power Pool administers and implements power marketing and trading transactions (trading activities) in which the Company shares. Trading activities involve the sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity contracts including exchange traded futures and options, over-the-counter options and swaps. The majority of these transactions represents physical forward electricity contracts in the AEP Power Pool's traditional marketing area and are typically settled by entering into offsetting contracts. The net revenues from these transactions in the AEP System's traditional marketing area are included in operating revenues for ratemaking, accounting and financial and regulatory reporting purposes. In addition the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area. The Company's share of the non-regulated trading activities are included in nonoperating income. In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions within the AEP Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes in the Company's non-Virginia jurisdictions. A Virginia jurisdiction net mark-to-market after-tax gain of $3 million as of December 31, 1999 is included in net income as a result of an agreed prohibition against establishing new regulatory assets in a February 1999 Virginia SCC approved settlement agreement. The Company's share of non-regulated open trading contracts are accounted for on a mark-to-market basis in nonoperating income. Unrealized mark-to-market gains and losses from trading activities are reported as assets and liabilities, respectively. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. The Company enters into contracts to manage the exposure to unfavorable changes in the cost of debt to be issued. These anticipatory debt instruments are entered into in order to manage the change in interest rates between the time a debt offering is initiated and the issuance of the debt (usually a period of 60 days). Gains or losses are deferred and amortized over the life of the debt issuance with the amortization included in interest charges. There were no such forward contracts outstanding at December 31, 1999 or 1998. See Note 9 - Financial Instruments, Credit and Risk Management for further discussion. Reclassification Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income. Income Taxes The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax consequence. Where the flow-through method of accounting for temporary differences is reflected in rates (that is, deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established in accordance with SFAS 71. Investment Tax Credits Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of regulated plant investment. Debt and Preferred Stock Gains and losses from the reacquisition of debt are deferred as regulatory assets and amortized over the remaining term of the reacquired debt in accordance with rate-making treatment. If debt is refinanced, reacquisition costs are deferred except in the Virginia jurisdiction and amortized over the term of the replacement debt commensurate with their recovery in rates. Debt discount or premium and debt issuance expenses are deferred and amortized over the term of the related debt, with the amortization included in interest charges. Redemption premiums paid to reacquire preferred stock are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over the cost of preferred stock reacquired is credited to paid-in capital and amortized to retained earnings. Other Property and Investments Other property and investments are stated at cost. Comprehensive Income There were no material differences between net income and comprehensive income. 2. EFFECTS OF REGULATION: In accordance with SFAS 71 the consolidated financial statements include regulatory assets (deferred expenses) and regulatory liabilities (deferred income) recorded in accordance with regulatory actions in order to match expenses and revenues from cost-based rates in the same accounting period. Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries. Among other things, application of SFAS 71 requires that the Company's regulated rates be cost-based and the recovery of regulatory assets must be probable. Management has reviewed all the evidence currently available and concluded that the Company continues to meet the requirements to apply SFAS 71. In the event a portion of the Company's business were to no longer meet those requirements, net regulatory assets would have to be written off for that portion of the business and assets attributable to that portion of the business would have to be tested for possible impairment and if required an impairment loss recorded unless the net regulatory assets and impairment losses are recoverable as a stranded cost. (See Note 3 "Restructuring Legislation".) Recognized regulatory assets and liabilities are comprised of the following: December 31, 1999 1998 (in thousands) Regulatory Assets: Amounts Due From Customers For Future Income Taxes $389,922 $374,750 Unamortized Loss On Reacquired Debt 20,828 22,827 Deferred Storm Damage 6,619 13,424 Other 19,525 22,515 Total Regulatory Assets $436,894 $433,516 Regulatory Liabilities: Deferred Investment Tax Credits $ 57,259 $ 62,231 Other* 80,312 53,955 Total Regulatory Liabilities $137,571 $116,186 * Included in Deferred Credits on Consolidated Balance Sheets. 3. RESTRUCTURING LEGISLATION: Virginia In March 1999 a law was enacted in Virginia to restructure the electric utility industry. Under the restructuring law a transition to choice of electricity supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia SCC that an effective competitive market exists, on January 1, 2004. The law also provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for net stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001 and the establishment of a wires charge by the fourth quarter of 2001. Management has concluded that as of December 31, 1999 the requirements to apply SFAS 71 continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates and the wires charge as provided in the law. The establishment of capped rates and the wires charge should enable management to determine its ability to recover stranded costs, a requirement to discontinue application of SFAS 71. When the capped rates and the wires charge are established in Virginia, the application of SFAS 71 will be discontinued for the Virginia retail jurisdictional portion of the Company's generating business. At that time the Company will have to write-off its generation-related regulatory assets to the extent that they cannot be recovered under the capped rates and wires charges approved by the Virginia SCC under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of impaired assets cannot be recovered through generation-related revenues during the transition period and future market prices. Absent the determination through the regulatory process, wires charges and other pertinent information of capped rates as required by the restructuring law, it is not possible at this time for management to determine if any generation-related assets are impaired in accordance with SFAS 121 and if generation-related regulatory assets will be recovered. The amount of regulatory assets recorded on the books applicable to the Company's Virginia retail generating business at December 31, 1999 is estimated to be $64.1 million before related tax effects. Should it not be possible under the Virginia law to recover all or a portion of the generation-related regulatory assets and/or tangible generating assets, it could have a material adverse impact on results of operations and cash flows. An estimated determination of whether the Company will experience any asset impairment loss regarding its Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation-related regulatory assets and other transition costs cannot be made until such time as the Company completes economic studies to estimate an asset impairment and until the transition period capped rates and the wires charge are determined under the law, which is expected to occur by the fourth quarter of 2000. West Virginia On January 28, 2000, the WVPSC issued an order approving an electricity restructuring plan for West Virginia. The restructuring plan has been submitted to the West Virginia Legislature for approval or rejection. The provisions of the proposed restructuring plan provide for customer choice to begin on January 1, 2001, or at a later date set by the WVPSC after all necessary rules are in place (the "starting date"); deregulation of generation assets occurring on the starting date; functional separation of the generation, transmission and distribution businesses on the start date and their legal corporate separation no later than January 1, 2005; a transition period of up to 13 years, during which the incumbent utility must provide default service for customers who do not change suppliers unless an alternative default supplier is selected through a WVPSC-sponsored bidding process; capped and fixed rates for the 13 year transition period as discussed below; deregulation of metering and billing; a 0.5 mills per kwh wires charge applicable to all retail customers for the period January 1, 2001 through December 31, 2010 intended to provide for recovery of any stranded cost including net regulatory assets; and establishment of a rate stabilization deferred balance of $75.6 million by the end of year ten of the transition period to be used as determined by the WVPSC to offset prices paid in the eleventh, twelfth, and thirteenth year of the transition period by residential and small commercial customers that do not choose a supplier. Default rates for residential and small commercial customers are capped for four years after the starting date and then increased as specified in the plan for the next six years. In years eleven, twelve and thirteen of the transition period, the power supply rate shall equal the market price of comparable power. Default rates for industrial and large commercial customers are discounted by 1% for four and a half years, beginning July 1, 2000, and then increased at pre-defined levels for the next three years. After seven years the power supply rate for industrial and large commercial customers will be market based. Management has concluded that as of December 31, 1999 the requirements to apply SFAS 71 continue to be met. The Company's West Virginia rates for generation will continue to be cost-based regulated until the restructuring plan is enacted into law. At that time, management should be able to determine its ability to recover stranded costs, a requirement to discontinue application of SFAS 71. When the restructuring plan is enacted into law, the application of SFAS 71 will be discontinued for the West Virginia retail jurisdictional portion of the Company's generating business. At that time the Company will have to write-off its generation-related regulatory assets to the extent that they cannot be recovered under the provisions of the approved restructuring plan and record any asset impairments in accordance with SFAS 121. An impairment loss would be recorded to the extent that the cost of impaired assets cannot be recovered through generation-related revenues during the transition period and future market prices. Absent the approval through the regulatory and legislative processes of rates and other pertinent information, it is not possible at this time for management to determine if any generation-related assets are impaired in accordance with SFAS 121 and if generation-related regulatory assets will be recovered. The amount of regulatory assets recorded on the books applicable to the Company's West Virginia retail generating business at December 31, 1999 is estimated to be $131.1 million before related tax effects. Should it not be possible under the West Virginia restructuring plan to recover all or a portion of the generation-related regulatory assets and/or tangible generating assets, it could have a material adverse impact on results of operations and cash flows. An estimated determination of whether the Company will experience any asset impairment loss regarding its West Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation-related regulatory assets and other transition costs cannot be made until such time as the Company completes economic studies to estimate an asset impairment and until the restructuring plan is enacted into law and the WVPSC approves the Joint Stipulation (See Note 4). 4. RATE MATTERS: West Virginia On May 12, 1999, the Company filed with the WVPSC for a base rate increase of $50 million annually and a reduction in expanded net energy cost (ENEC) rates of $38 million annually. On February 7, 2000, APCo and other parties to the proceeding filed a Joint Stipulation and Agreement for Settlement (Joint Stipulation) with the WVPSC for approval. The Joint Stipulation's main provisions include no change in either base or ENEC rates effective January 1, 2000 from those base and ENEC rates in effect from November 1, 1996 until December 31, 1999 (these rates provide for recovery of regulatory assets including any generation related regulatory assets of approximately 0.5 mills per kwh); annual ENEC recovery proceedings are suspended and deferral accounting for over or under recovery is discontinued effective January 1, 2000; the net cumulative deferred ENEC recovery balance as established by a WVPSC order on December 27, 1996, which is $65.9 million at December 31, 1999, shall remain on the books as a regulatory liability. However, if deregulation of generation occurs in West Virginia (WV), APCo will use this regulatory liability to reduce unrecoverable generation-related regulatory assets and, to the extent possible, any additional costs or obligations that deregulation may impose. APCo's share of any net savings from the pending merger between AEP and Central and South West Corporation prior to December 31, 2004 shall be retained by APCo. All costs incurred in the merger that are allocated to APCo, whether the merger is consummated or not, shall be fully charged to expense as of December 31, 2004 and shall not be included in any WV rate proceeding after that date. After December 31, 2004 any savings related to the merger will be reflected in rates in any future rate proceeding before the WVPSC to establish distribution rates or to adjust rate caps during the transition to market based rates. If deregulation of generation occurs in WV the net retained generation related merger savings should be used to recover any generation related regulatory assets that are not recovered under the provisions of the Joint Stipulation and the mechanisms provided for in the deregulation legislation and, to the extent possible, to recover any additional costs or obligations that deregulation may impose on APCo. Regardless of whether the net cumulative deferred ENEC recovery balance and the net merger savings are sufficient to offset all of APCo's generation related regulatory assets, under the terms of the Joint Stipulation there will be no further explicit adjustment to APCo's rates to provide for recovery of generation-related regulatory assets beyond the above discussed specific adjustments provided in the Joint Stipulation and the 0.5 mills per kwh wires charge in the WV Restructuring Plan (see Note 3 for discussion of WV Restructuring Plan). FERC The FERC issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission service tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 30, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers sought rehearing of the Commission's Order. The Company made a provision in September 1999 for the refund including interest. On December 10, 1999, AEP filed a settlement agreement with the FERC resolving the issues on rehearing of the July 30, 1999 order. Under terms of the settlement, AEP will make refunds retroactive to September 7, 1993 to certain customers affected by the July 30, 1999 FERC order. The refunds will be made in two payments. The first payment was made February 2, 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder will be paid after the FERC issues a final order and approves a compliance filing that AEP will make pursuant to the final order. In addition, a new rate was made effective January 1, 2000, subject to FERC approval, for all transmission service customers and a future rate was established to take effect upon the consummation of the AEP and Central and South West Corporation merger unless a superseding rate is made effective prior to the merger. 5. COMMITMENTS AND CONTINGENCIES: Construction and Other Commitments Substantial construction commitments have been made to support the Company's utility operations and are estimated to be $839 million for 2000-2002. Long-term fuel supply contracts contain clauses that provide for periodic price adjustments. The contracts are for various terms, the longest of which extends to 2006, and contain various clauses that would release the Company from its obligation under certain force majeure conditions. Federal EPA Complaint and Notice of Violation - Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. On November 3, 1999 the Department of Justice, at the request of the United States (U.S.) Environmental Protection Agency (Federal EPA), filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company and its affiliates in the AEP System made modifications to generating units at certain of their coal-fired generating plants over the course of the past 25 years that extend unit operating lives or increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued Notices of Violation to the Company and its affiliates in the AEP System alleging similar violations at certain AEP plants. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. The states of New Jersey, New York and Connecticut were subsequently granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. On November 18, 1999 a number of environmental groups filed a lawsuit against power plants owned by the Company and its affiliates in the AEP System alleging similar violations to those in the Federal EPA complaint and Notices of Violation. This action has been consolidated with the Federal EPA action. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts Federal EPA's contentions, could be substantial. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense of this matter. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and as generation is deregulated through future market prices for energy. Litigation The Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions claimed by the Company relating to AEP's corporate owned life insurance (COLI) program should not be allowed. As a result of a suit filed in U.S. District Court (discussed below) this request for ruling was withdrawn by the IRS agents. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through December 31, 1999 would reduce earnings by approximately $79 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. The payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the U.S. District Court for the Southern District of Ohio in March 1998. In 1999 a U.S. tax court judge decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the Tax Court's decision in Winn-Dixie, management has made no provision for any possible earnings impact from this matter because it believes, and has been advised by outside counsel, that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. The Company is involved in a number of other legal proceedings and claims. While management is unable to predict the ultimate outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations, cash flows or financial condition. 6. SUBSEQUENT EVENT - NOx REDUCTIONS (March 3, 2000): On March 3, 2000, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision generally upholding Federal EPA's final rule (the NOx rule) that requires substantial reductions in nitrogen oxide (NOx) emissions in 22 eastern states, including the states in which the Company's generating plants are located. A number of utilities, including the Company, had filed petitions seeking a review of the final rule in the Appeals Court. On May 25, 1999, the Appeals Court had indefinitely stayed the requirement that states develop revised air quality programs to impose the NOx reductions but did not, however, stay the final compliance date of May 1, 2003. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to the Clean Air Act (Section 126 Rule). The rule approved portions of the states' petitions and imposed NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx Rule. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of the northeastern states' petitions. In 1999, three additional northeastern states and the District of Columbia filed petitions with Federal EPA similar to those originally filed by the eight northeastern states. Since the petitions relied in part on compliance with an 8-hour ozone standard remanded by the Appeals Court in May 1999, Federal EPA indicated its intent to decouple compliance with the 8-hour standard and issue a revised rule. On December 17, 1999, Federal EPA issued a revised Section 126 Rule not based on the 8-hour standard and ordered 392 industrial facilities, including certain coal-fired generating plants owned by the Company, to reduce their NOx emissions by May 1, 2003. This rule approves portions of the petitions filed by four northeastern states which contend that their failure to meet Federal EPA smog standards is due to emissions from upwind states' industrial and coal-fired generating facilities. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeal Court could result in required capital expenditures of approximately $365 million for the Company. Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the Company's preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through regulated rates, transition charges and/or reflected in the future market price of electricity, they will have an adverse effect on future results of operations and cash flows and possibly financial condition. 7. RELATED PARTY TRANSACTIONS: Benefits and costs of the AEP System's generating plants are shared by members of the AEP Power Pool of which the Company is a member. Under terms of the System Interconnection Agreement, capacity charges and credits are designed to allocate the cost of the System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. Operating revenues include $41.9 million in 1999, $36.9 million in 1998 and $40.1 million in 1997 for energy supplied to the AEP Power Pool. Since the Company's internal peak demand exceeds its generating capacity, charges for AEP Power Pool capacity reservation, which is a charge for the right to receive power even if the power is not taken, and charges for energy received from the AEP Power Pool were included in purchased power expense as follows: Year Ended December 31, 1999 1998 1997 (in thousands) Capacity Charges $ 67,894 $ 83,536 $128,680 Energy Charges 63,097 97,226 149,113 Total $130,991 $180,762 $277,793 The AEP Power Pool allocates operating revenues, purchased power expense and nonoperating income to the Company. Power marketing and trading operations, which are described in Note 1, are conducted by the AEP Power Pool and shared with the Company. Net trading transactions are included in operating revenues if the trading transactions are within the AEP Power Pool's traditional marketing area and are recorded in nonoperating income if the net trading transactions are outside of the AEP Power Pool's traditional marketing area. The total amounts allocated by the AEP Power Pool, which includes amounts for power marketing and trading transactions, are as follows: Year Ended December 31, 1999 1998 1997 (in thousands) Operating Revenues $148,803 $193,441 $128,041 Purchased Power Expense 101,345 111,909 27,330 Nonoperating Income (Loss) 3,088 (11,179) (81) Energy sold directly to Kingsport Power Company (KGPCo), an affiliated distribution utility that is not a member of the AEP Power Pool, was included in operating revenues in the amounts of $57.2 million in 1999, $56.8 million in 1998 and $57.9 million in 1997. Purchased power expense includes $21.7 million in 1999, $10.4 million in 1998 and $6.4 million in 1997 of energy bought from the Ohio Valley Electric Corporation, an affiliated company that is not a member of the AEP Power Pool. The Company participates in the AEP Transmission Equalization Agreement along with other AEP System electric operating utility companies. This agreement combines certain AEP System companies' investments in transmission facilities and shares the costs of ownership in proportion to the System companies' respective peak demands. Pursuant to the terms of the agreement since the Company's relative investment in transmission facilities is greater than its relative peak demands in 1999 and 1998 and less than its relative peak demands in 1997, other operation expense includes equalization charges (credits) of $(8.3) million, $(2.4) million and $8.4 million in 1999, 1998 and 1997, respectively. The Company and an affiliate, Ohio Power Company (OPCo), jointly own two power plants. The costs of operating these facilities are apportioned between the owners based on ownership interests. The Company's share of these costs is included in the appropriate expense accounts on the Consolidated Statements of Income. The Company's investment in these plants is included in electric utility plant on the Consolidated Balance Sheets. American Electric Power Service Corporation (AEPSC) provides certain managerial and professional services to AEP System companies including the Company. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. 8. SEGMENT INFORMATION: Effective December 31, 1998 the Company adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information". The Company has one reportable segment, a regulated vertically integrated electricity generation and energy delivery business. All other activities are insignificant. The Company's operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on business processes, cost structures and operating results. Included in the regulated electric utility business is the power marketing and trading activities that are discussed in Note 1. For the years ended December 31, 1999, 1998 and 1997, all of the Company's revenues are derived from the generation, sale and distribution of electricity in the United States. 9. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT The Company is subject to market risk as a result of changes in electricity commodity prices and interest rates. The Company through its membership in the AEP Power Pool participates in a power marketing and trading operation that manages the exposure to electricity commodity price movements using physical forward purchase and sale contracts at fixed and variable prices, and financial derivative instruments including exchange traded futures and options, over-the-counter options, swaps and other financial derivative contracts at both fixed and variable prices. Physical forward electricity contracts within the AEP System's traditional marketing area are recorded on a net basis as operating revenues in the month when the physical contract settles. The Company's share of the net realized gains from these regulated transactions for the years ended December 31, 1999 and 1998 are $7 million and $33 million, respectively. These activities were not material in 1997. Non-regulated physical forward electricity contracts outside AEP's traditional marketing area, and all financial electricity trading transactions where the underlying physical commodity is outside AEP's traditional market area are marked to market and recorded in nonoperating income. The Company's share of the net income (loss) from these non-regulated trading transactions for the years ended December 31, 1999 and 1998 are $3 million and $(11) million, respectively. These activities were not material in 1997. In the first quarter of 1999 the Company adopted EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open regulated trading contracts to market is deferred as regulatory assets or liabilities for the portion of those open trading transactions within the AEP Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes in the Company's non-Virginia jurisdictions. A Virginia jurisdiction net mark-to-market pre-tax gain of $5 million as of December 31, 1999 is included in operating revenues as a result of an agreed prohibition against establishing new regulatory assets in a February 1999 Virginia SCC approved settlement agreement. The unrealized mark-to-market gains and losses from trading of financial instruments including forward purchase contracts are reported as assets and liabilities, respectively. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. The Company is exposed to risk from changes in interest rates primarily due to short-term and long-term borrowings used to fund its business operations. The debt portfolio has both fixed and variable interest rates with terms from one day to 39 years and an average duration of eight years at December 31, 1999. A near term change in interest rates should not materially affect results of operations or financial position since the Company would not expect to liquidate its entire debt portfolio in a one year holding period. Market Valuation The book value of cash and cash equivalents, accounts receivable, short-term debt and accounts payable approximate fair value because of the short-term maturity of these instruments. The book value amounts and fair values of the Company's significant financial instruments at December 31, 1999 and 1998 are summarized in the following table. The fair values of long-term debt and preferred stock are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments of the same remaining maturities. The fair value of those financial instruments that are marked-to-market are based on management's best estimates using over-the-counter quotations, exchange prices, volatility factors and valuation methodology. The estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. 1999 1998 Book Value Fair Value Book Value Fair Value (in thousands) (in thousands) Non-Derivatives Long-term Debt $1,665,307 $1,580,600 $1,552,455 $1,638,700 Preferred Stock 20,310 19,700 22,310 23,400 Derivatives 1999 1998 Notional Fair Average Notional Fair Average Amount Value Fair Value Amount Value Fair Value (Dollars in thousands) Trading Assets Electric GWH GWH NYMEX Futures and Options 64 $ 535 $ 254 - $ - $ - Physicals 19,953 165,624 150,377 17,556 13,700 12,200 Options 1,781 11,766 18,461 1,161 10,100 24,300 Swaps 51 112 90 83 1,000 300 Trading Liabilities Electric GWH GWH NYMEX Futures and Options - - - 212 (2,100) (500) Physicals 21,461 (154,364) (144,876) 17,295 (14,800) (13,900) Options 2,557 (12,375) (16,811) 881 (8,900) (23,700) Swaps 52 (103) (85) 147 (2,300) (600) Credit and Risk Management In addition to market risk associated with electricity price movements, the Company through the AEP Power Pool is also subject to the credit risk inherent in the risk management activities. Credit risk refers to the financial risk arising from commercial transactions and/or the intrinsic financial value of contractual agreements with trading counter parties, by which there exists a potential risk of nonperformance. The AEP Power Pool has established and enforced credit policies that minimize this risk. The AEP Power Pool accepts as counter parties to forwards, futures, and other derivative contracts primarily those entities that are classified as Investment Grade, or those that can be considered as such due to the effective placement of credit enhancements and/or collateral agreements. Investment grade is the designation given to the four highest debt rating categories (i.e., AAA, AA, A, BBB) of the major rating services e.g., ratings BBB- and above at Standards & Poor's and Baa3 and above at Moody's. When adverse market conditions have the potential to negatively affect a counter party's credit position, the AEP Power Pool requires further credit enhancements to mitigate risk. Since the formation of the power marketing and trading business in July of 1997, the Company has experienced no significant losses due to the credit risk associated with risk management activities; furthermore, the Company does not anticipate any future material effect on its results of operations, cash flow or financial condition as a result of counter party nonperformance. 10. STAFF REDUCTIONS: During 1998 an internal evaluation of the power generation organization was conducted with a goal of developing a better organizational structure for a competitive generation market. The study was completed in October 1998. In addition, a review of energy delivery staffing levels was conducted in 1998. As a result approximately 180 power generation and energy delivery positions were identified for elimination. Severance accruals totaling $7.6 million were recorded by the Company in December 1998 for reductions in power generation and energy delivery staffs and were charged to other operation expense in the Consolidated Statements of Income. In the first quarter of 1999 the power generation and energy delivery staff reductions were made. The amount of severance benefits paid was not significantly different from the amount accrued. 11. BENEFIT PLANS: The Company and its subsidiaries participate in the AEP System qualified pension plan, a defined benefit plan which covers all employees. Net pension costs (credits) for the years ended December 31, 1999, 1998 and 1997 were $(3.9) million, $0.8 million and $1.9 million, respectively. Postretirement benefits other than pensions are provided for retired employees for medical and death benefits under an AEP System plan. The annual accrued costs were $19.5 million in 1999, $16.6 million in 1998 and $17.3 million in 1997. A defined contribution employee savings plan required that the Company make contributions to the plan totaling $4.1 million in 1999, $4.3 million in 1998, and $4 million in 1997. 12. FEDERAL INCOME TAXES: The details of federal income taxes as reported are as follows:
Year Ended December 31, 1999 1998 1997 (in thousands) Charged (Credited) to Operating Expenses (net): Current $64,603 $56,446 $66,810 Deferred 8,981 (143) (4,801) Deferred Investment Tax Credits (2,659) (2,671) (2,697) Total 70,925 53,632 59,312 Charged (Credited) to Nonoperating Income (net): Current (1,714) (4,902) (1,677) Deferred 4,052 (2,195) (316) Deferred Investment Tax Credits (2,313) (2,594) (2,484) Total 25 (9,691) (4,477) Total Federal Income Taxes as Reported $70,950 $43,941 $54,835 The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of federal income taxes reported. Year Ended December 31, 1999 1998 1997 (in thousands) Net Income $120,492 $ 93,330 $120,514 Federal Income Taxes 70,950 43,941 54,835 Pre-tax Book Income $191,442 $137,271 $175,349 Federal Income Taxes on Pre-tax Book Income at Statutory Rate (35%) $67,005 $48,045 $61,372 Increase (Decrease) in Federal Income Taxes Resulting From the Following Items: Depreciation 12,593 11,667 10,945 Corporate Owned Life Insurance - (4,212) (3,974) Removal Costs (3,220) (4,200) (4,200) Investment Tax Credits (net) (4,972) (5,265) (5,181) Other (456) (2,094) (4,127) Total Federal Income Taxes as Reported $70,950 $43,941 $54,835 Effective Federal Income Tax Rate 37.1% 32.0% 31.3%
The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals: December 31, 1999 1998 (in thousands) Deferred Tax Assets $ 173,038 $ 168,898 Deferred Tax Liabilities (844,955) (812,609) Net Deferred Tax Liabilities $(671,917) $(643,711) Property Related Temporary Differences $(510,143) $(496,464) Amounts Due From Customers For Future Federal Income Taxes (109,846) (106,436) Deferred State Income Taxes (76,073) (70,644) All Other (net) 24,145 29,833 Net Deferred Tax Liabilities $(671,917) $(643,711) The Company and its subsidiaries join in the filing of a consolidated federal income tax return with their affiliated companies in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group. The AEP System has settled with the IRS all issues from the audits of the consolidated federal income tax returns for the years prior to 1991. Returns for the years 1991 through 1996 are presently being audited by the IRS. With the exception of the deductibility of interest deductions related to AEP's corporate owned life insurance program, which is discussed under the heading "Litigation" in Note 5, management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations. 13. COMMON SHAREHOLDER'S EQUITY: The Company received from AEP Co., Inc. cash capital contributions of $50 million in 1999 and 1998, and $40 million in 1997 which were credited to paid-in capital. In 1999, 1998 and 1997 net changes in paid-in capital of $626,000, $585,000 and $(2,332,000), respectively, resulted from gains and (expenses) associated with cumulative preferred stock transactions. There were no other material transactions affecting common stock and paid-in capital accounts in 1999, 1998 and 1997. At December 31, 1999 there were no dividend restrictions on retained earnings. To pay dividends out of paid-in capital, the Company needs regulatory approval. 14. CUMULATIVE PREFERRED STOCK:
The authorized number of shares of no par value cumulative preferred stock is 8,000,000. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The Company redeemed and canceled 500,000 shares of the 7.80% series subject to mandatory redemption in 1997. Cumulative Preferred Stock Not Subject to Mandatory Redemption: Call Price Shares Amount December 31, Number of Shares Redeemed Outstanding December 31, Series 1999 Year Ended December 31, December 31, 1999 1999 1998 1999 1998 1997 (in thousands) 4-1/2% $110.00 8,671 3,878 100,685 184,916 $18,491 $19,359 Cumulative Preferred Stock Subject to Mandatory Redemption: Call Price December 31, Number of Shares Redeemed Outstanding December 31, Series(a) 1999 Year Ended December 31, December 31, 1999 1999 1998 1999 1998 1997 (in thousands) 5.90% (b) $ (d) 20,000 - 422,900 57,100 $ 5,710 $ 7,710 5.92% (b) (d) - - 538,500 61,500 6,150 6,150 6.85% (c) (e) - - 215,500 84,500 8,450 8,450 $20,310 $22,310 (a) The sinking fund provisions of each series have been met by purchase of shares in advance of the due date. (b) Commencing in 2003 and continuing through 2007 the Company may redeem at $100 per share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92% series outstanding under sinking fund provisions at its option and all outstanding shares must be reacquired in 2008. Shares redeemed in 1999 and 1997 may be applied to meet the sinking fund requirement. (c) Commencing in 2000 and continuing through date of redemption, a sinking fund for the 6.85% cumulative preferred stock will require the redemption of 60,000 shares each year, in each case at $100 per share. The Company has the non-cumulative option to redeem up to 60,000 additional shares on any sinking fund date at a redemption price of $100 per share. Shares redeemed in 1997 may be applied to meet the sinking fund requirement. (d) Not callable until after 2002. (e) Not callable until after 1999.
15. LONG-TERM DEBT AND LINES OF CREDIT: Long-term debt by major category was outstanding as follows: December 31, 1999 1998 (in thousands) First Mortgage Bonds $ 844,472 $ 960,597 Installment Purchase Contracts 264,217 234,262 Senior Unsecured Notes 392,844 193,959 Junior Debentures 161,228 161,087 Other Long-term Debt 2,546 2,550 1,665,307 1,552,455 Less Portion Due Within One Year 126,005 80,004 Total $1,539,302 $1,472,451 First mortgage bonds outstanding were as follows: December 31, 1999 1998 (in thousands) % Rate Due 7.00 1999 - December 1 $ - $ 30,000 6.35 2000 - March 1 48,000 48,000 6.71 2000 - June 1 48,000 48,000 6-3/8 2001 - March 1 100,000 100,000 7.38 2002 - August 15 50,000 50,000 7.40 2002 - December 1 30,000 30,000 6.65 2003 - May 1 40,000 40,000 6.85 2003 - June 1 30,000 30,000 6.00 2003 - November 1 30,000 30,000 7.70 2004 - September 1 21,000 21,000 7.85 2004 - November 1 50,000 50,000 8.00 2005 - May 1 50,000 50,000 6.89 2005 - June 22 30,000 30,000 6.80 2006 - March 1 100,000 100,000 8.43 2022 - June 1 - 37,471 8.50 2022 - December 1 70,000 70,000 7.80 2023 - May 1 30,237 40,000 7.90 2023 - June 1 - 30,000 7.15 2023 - November 1 20,000 30,000 7.125 2024 - May 1 50,000 50,000 8.00 2025 - June 1 50,000 50,000 Unamortized Discount (2,765) (3,874) 844,472 960,597 Less Portion Due Within One Year 96,000 80,000 Total $ 748,472 $ 880,597 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Installment purchase contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: December 31, 1999 1998 (in thousands) % Rate Due Industrial Development Authority of Russell County, Virginia: 7.70 2007 - November 1 $ 17,500 17,500 5.00 2021 - November 1 19,500 19,500 Putnam County, West Virginia: 5.45 2019 - June 1 40,000 40,000 6.60 2019 - July 1 30,000 30,000 Mason County, West Virginia: 7-7/8 2013 - November 1 10,000 10,000 7.40 2014 - January 1 30,000 30,000 6.85 2022 - June 1 40,000 40,000 6.60 2022 - October 1 50,000 50,000 6.05 2024 - December 1 30,000 - Unamortized Discount (2,783) (2,738) 264,217 234,262 Less Portion Due Within One Year 30,000 - Total $234,217 $234,262 Under the terms of the installment purchase contracts, the Company is required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Senior unsecured notes outstanding were as follows: December 31, 1999 1998 (in thousands) % Rate Due 7.45 2004 - November 1 $ 50,000 $ - 6.60 2009 - May 1 150,000 - 7.20 2038 - March 31 100,000 100,000 7.30 2038 - June 30 100,000 100,000 Unamortized Discount (7,156) (6,041) Total $392,844 $193,959 Junior debentures outstanding were as follows: December 31, 1999 1998 (in thousands) 8-1/4% Series A due 2026 - September 30 $ 75,000 $ 75,000 8% Series B due 2027 - March 31 90,000 90,000 Unamortized Discount (3,772) (3,913) Total $161,228 $161,087 Interest may be deferred and payment of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of the Company. At December 31, 1999, future annual long-term debt payments are as follows: Amount (in thousands) 2000 $ 126,005 2001 100,006 2002 80,006 2003 100,007 2004 121,008 Later Years 1,154,751 Total Principal Amount 1,681,783 Unamortized Discount (16,476) Total $1,665,307 Short-term debt borrowings are limited by provisions of the 1935 Act to $325 million. Lines of credit are shared with other AEP System companies and at December 31, 1999 and 1998 were available in the amounts of $1,056 million and $763 million, respectively. The short-term bank lines of credit require the payment of facility fees and do not require compensating balances. Outstanding short-term debt consisted of: Year-end Balance Weighted Outstanding Average (in thousands) Interest Rate December 31, 1999: Commercial Paper $123,480 6.3% December 31, 1998: Notes Payable $34,600 5.7% Commercial Paper 41,800 6.2% Total $76,400 6.0% 16. LEASES: Leases of property, plant and equipment are for periods of up to 30 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment. The components of rental costs are as follows: Year Ended December 31, 1999 1998 1997 (in thousands) Operating Leases $ 5,647 $ 7,047 $ 8,016 Amortization of Capital Leases 13,749 13,561 11,771 Interest on Capital Leases 4,267 3,541 3,290 Total Rental Costs $23,663 $24,149 $23,077 Properties under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows: December 31, 1999 1998 (in thousands) Electric Utility Plant Under Capital Leases: Production Plant $ 8,354 $ 9,463 General Plant 93,053 87,776 Total Electric Utility Plant Under Capital Leases 101,407 97,239 Accumulated Amortization 36,762 32,064 Net Properties Under Capital Leases $ 64,645 $65,175 Capital Lease Obligations*: Noncurrent Liability $52,009 $52,429 Liability Due Within One Year 12,636 12,746 Total Capital Lease Obligations $64,645 $65,175 *Represents the present value of future minimum lease payments. Capital lease obligations are included in other noncurrent and other current liabilities on the Consolidated Balance Sheets. Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets. Future minimum lease payments consisted of the following at December 31, 1999: Non- Cancelable Capital Operating Leases Leases (in thousands) 2000 $16,451 $2,032 2001 14,464 999 2002 13,327 427 2003 10,793 412 2004 8,443 412 Later Years 14,777 3,301 Total Future Minimum Lease Rentals 78,255 $7,583 Less Estimated Interest Element 13,610 Estimated Present Value of Future Minimum Lease Payments $64,645 17. SUPPLEMENTARY INFORMATION: Year Ended December 31, 1999 1998 1997 (in thousands) Cash was paid for: Interest (net of capitalized amounts) $125,900 $124,027 $115,508 Income Taxes $55,157 $65,102 $71,749 Noncash Acquisitions Under Capital Leases $13,868 $21,146 $15,266 18. UNAUDITED QUARTERLY FINANCIAL INFORMATION: Quarterly Periods Operating Operating Net Ended Revenues Income Income (in thousands) 1999 March 31 $427,702 $71,607 $39,261 June 30 373,766 43,099 11,036 September 30 441,435 66,309 35,661 December 31 408,034 60,221 34,534 1998 March 31 $415,366 $64,249 $33,199 June 30 403,080 46,192 15,124 September 30 474,476 70,951 33,446 December 31 379,322 47,151 11,561 Fourth quarter 1998 net income declined primarily as a result of unseasonably mild weather, provisions for rate refunds recorded for the Virginia retail jurisdiction and severance accruals for staff reductions. In connection with the sale of coal lands and mining assets, the Company will receive cash payments from the buyer of $17.5 million over an 8 year period which has been recorded at a net present value of $14.7 million. INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Appalachian Power Company: We have audited the accompanying consolidated balance sheets of Appalachian Power Company and its subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1999. 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 generally accepted auditing standards. 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, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and its subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with generally accepted accounting principles. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2000 (March 3, 2000 as to Note 6) -----END PRIVACY-ENHANCED MESSAGE-----