-----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, AlkSQCOzf4IN5Y6bmWcH4hzOsGL2fe60LimsSf4cxaBB6hXMZoMNC2CP/5IDJ1NI XPL7pHYzC6yxH3EZJkFjew== 0000004904-00-000082.txt : 20000516 0000004904-00-000082.hdr.sgml : 20000516 ACCESSION NUMBER: 0000004904-00-000082 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20000331 FILED AS OF DATE: 20000515 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-Q SEC ACT: SEC FILE NUMBER: 001-03457 FILM NUMBER: 634222 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-Q 1 THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended MARCH 31, 2000 [ ] 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 (An Ohio Corporation) 31-1033833 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 40 Franklin Road, Roanoke, Virginia 24011 Telephone (540) 985-2300 1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455 One Summit Square P.O. Box 60, Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1701 Central Avenue, Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 301 Cleveland Avenue S.W., Canton, Ohio 44701 Telephone (330) 456-8173 AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 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 The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at April 30, 2000 was 194,103,349. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended March 31, 2000
INDEX Page Part I. FINANCIAL INFORMATION American Electric Power Company, Inc. and Subsidiary Companies: Consolidated Statements of Income and Statements of Comprehensive Income . . . . . . . . . . . . A-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3 Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4 Consolidated Statements of Retained Earnings . . . . . . . . A-5 Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-18 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . A-19- A-32 AEP Generating Company: Statements of Income and Statements of Retained Earnings . . B-1 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . B-2 - B-3 Statements of Cash Flows . . . . . . . . . . . . . . . . . . B-4 Notes to Financial Statements. . . . . . . . . . . . . . . . B-5 Management's Narrative Analysis of Results of Operations . . B-6 - B-7 Appalachian Power Company and Subsidiaries: Consolidated Statements of Income and Consolidated Statements of Retained Earnings . . . . . . . C-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . C-2 - C-3 Consolidated Statements of Cash Flows. . . . . . . . . . . . C-4 Notes to Consolidated Financial Statements . . . . . . . . . C-5 - C-11 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . C-12- C-20 Columbus Southern Power Company and Subsidiaries: Consolidated Statements of Income and Consolidated Statements of Retained Earnings . . . . . . . D-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . D-2 - D-3 Consolidated Statements of Cash Flows. . . . . . . . . . . . D-4 Notes to Consolidated Financial Statements . . . . . . . . . D-5 - D-10 Management's Narrative Analysis of Results of Operations . . D-11- D-12 Indiana Michigan Power Company and Subsidiaries: Consolidated Statements of Income and Consolidated Statements of Retained Earnings . . . . . . . E-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . E-2 - E-3 Consolidated Statements of Cash Flows. . . . . . . . . . . . E-4 Notes to Consolidated Financial Statements . . . . . . . . . E-5 - E-8 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . E-9 - E-15 Kentucky Power Company: Statements of Income and Statements of Retained Earnings . . F-1 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3 Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4 Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-7 Management's Narrative Analysis of Results of Operations . . F-8 - F-9
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended March 31, 2000
INDEX Page Ohio Power Company and Subsidiaries: Consolidated Statements of Income and Consolidated Statements of Retained Earnings . . . . . . G-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3 Consolidated Statements of Cash Flows. . . . . . . . . . . G-4 Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-10 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . G-11- G-18 Part II. OTHER INFORMATION Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2 SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, 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. Each registrant makes no representation as to information relating to the other registrants.
FORWARD-LOOKING INFORMATION This report made by American Electric Power Company, Inc. (AEP) and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: Electric load and customer growth. Abnormal weather conditions. Available sources and costs of fuels. Availability of generating capacity. The impact of the proposed merger with CSW including any regulatory conditions imposed on the merger or the inability to consummate the merger with CSW. The speed and degree to which competition is introduced to our power generation business. The structure and timing of a competitive market and its impact on energy prices or fixed rates. The ability to recover stranded costs in connection with possible/proposed deregulation of generation. New legislation and government regulations. The ability of AEP to successfully control its costs. The success of new business ventures. International developments affecting AEP's foreign investments. The economic climate and growth in AEP's service territory. Unforeseen events affecting AEP's nuclear plant which is on an extended safety related shutdown. Problems or failures related to Year 2000 readiness of computer software and hardware. Inflationary trends. Electricity and gas market prices. Interest rates Other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in millions, except per-share amounts) (UNAUDITED)
Three Months Ended March 31, 2000 1999 REVENUES: Domestic Regulated Electric Utilities. . . . . . . . . . $1,546 $1,550 Worldwide Non-regulated Electric and Gas Operations. . . 200 144 TOTAL REVENUES . . . . . . . . . . . . . . . . . 1,746 1,694 EXPENSES: Fuel and Purchased Power . . . . . . . . . . . . . . . . 511 491 Maintenance and Other Operation. . . . . . . . . . . . . 489 427 Depreciation and Amortization. . . . . . . . . . . . . . 154 148 Taxes Other Than Income Taxes. . . . . . . . . . . . . . 125 124 Worldwide Non-regulated Electric and Gas Operations. . . 164 127 TOTAL EXPENSES. . . . . . . . . . . . . . . . . . 1,443 1,317 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 303 377 OTHER INCOME (LOSS), net . . . . . . . . . . . . . . . . . 3 (1) INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES . . . . . . . . . . . . . . . . . . . . 306 376 INTEREST AND PREFERRED DIVIDENDS . . . . . . . . . . . . . 139 132 INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . 167 244 INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . . 63 93 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 104 $ 151 AVERAGE NUMBER OF SHARES OUTSTANDING . . . . . . . . . . . 194 192 EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . . $0.53 $0.79 CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . . $0.60 $0.60 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended March 31, 2000 1999 (in millions) NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 104 $ 151 OTHER COMPREHENSIVE INCOME (LOSS): Foreign Currency Translation Adjustment . . . . . . . . . . . . . . . . . . . . . . (22) - COMPREHENSIVE INCOME . . . . . . . . . . . . . . . . . . . $ 82 $ 151 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in millions) ASSETS CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . $ 364 $ 333 Accounts Receivable (net). . . . . . . . . . . . . . 993 910 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 260 307 Materials and Supplies . . . . . . . . . . . . . . . 311 311 Accrued Utility Revenues . . . . . . . . . . . . . . 204 246 Energy Trading Contracts . . . . . . . . . . . . . . 1,327 1,001 Prepayments and Other. . . . . . . . . . . . . . . . 116 108 TOTAL CURRENT ASSETS . . . . . . . . . . . . 3,575 3,216 PROPERTY, PLANT AND EQUIPMENT: Electric: Production . . . . . . . . . . . . . . . . . . . 9,984 9,949 Transmission . . . . . . . . . . . . . . . . . . 3,831 3,832 Distribution . . . . . . . . . . . . . . . . . . 5,536 5,536 Other (including gas and coal mining assets and nuclear fuel) . . . . . . . . . . . . . . . . . 2,364 2,307 Construction Work in Progress. . . . . . . . . . . . 558 581 Total Property, Plant and Equipment. . . . . 22,273 22,205 Accumulated Depreciation and Amortization. . . . . . 9,254 9,150 NET PROPERTY, PLANT AND EQUIPMENT. . . . . . 13,019 13,055 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 2,202 2,171 OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 3,106 3,046 TOTAL. . . . . . . . . . . . . . . . . . . $21,902 $21,488 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable . . . . . . . . . . . . . . . . . . $ 729 $ 699 Short-term Debt. . . . . . . . . . . . . . . . . . . 1,118 888 Long-term Debt Due Within One Year . . . . . . . . . 978 1,111 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 416 414 Interest Accrued . . . . . . . . . . . . . . . . . . 114 78 Obligations Under Capital Leases . . . . . . . . . . 127 91 Energy Trading Contracts . . . . . . . . . . . . . . 1,203 964 Other. . . . . . . . . . . . . . . . . . . . . . . . 445 425 TOTAL CURRENT LIABILITIES. . . . . . . . . . 5,130 4,670 LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . 6,239 6,336 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,664 2,745 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 321 326 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 210 213 DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . 716 517 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,487 1,511 CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . 163 164 CONTINGENCIES (Note 9) COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50: 2000 1999 Shares Authorized . . . .600,000,000 600,000,000 Shares Issued . . . . . .203,103,341 203,103,341 (8,999,992 shares were held in treasury) . . . . . $ 1,320 $ 1,320 Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,932 1,932 Accumulated Other Comprehensive Income(Loss) Foreign Currency Translation Adjustments . . . . . (8) 14 Retained Earnings. . . . . . . . . . . . . . . . . . 1,728 1,740 TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . 4,972 5,006 TOTAL. . . . . . . . . . . . . . . . . . . $21,902 $21,488 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in millions) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 104 $ 151 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 195 172 Deferred Federal Income Taxes. . . . . . . . . . . . . . (23) 30 Deferred Investment Tax Credits. . . . . . . . . . . . . (5) (6) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (84) 25 Fuel, Materials and Supplies . . . . . . . . . . . . . . 47 (48) Accrued Utility Revenues . . . . . . . . . . . . . . . . 39 31 Prepayments. . . . . . . . . . . . . . . . . . . . . . . (12) (42) Accounts Payable . . . . . . . . . . . . . . . . . . . . 34 123 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2 5 Interest Accrued . . . . . . . . . . . . . . . . . . . . 36 42 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 37 37 Other (net). . . . . . . . . . . . . . . . . . . . . . . . (82) (117) Net Cash Flows From Operating Activities . . . . . . 288 403 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (186) (212) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (11) (5) Net Cash Flows Used For Investing Activities . . . . (197) (217) FINANCING ACTIVITIES: Issuance of Common Stock . . . . . . . . . . . . . . . . . - 31 Issuance of Long-term Debt . . . . . . . . . . . . . . . . 10 7 Change in Short-term Debt (net). . . . . . . . . . . . . . 230 9 Retirement of Long-term Debt . . . . . . . . . . . . . . . (184) (11) Dividends Paid on Common Stock . . . . . . . . . . . . . . (116) (115) Net Cash Flows Used For Financing Activities . . . . (60) (79) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 31 107 Cash and Cash Equivalents at Beginning of Period . . . . . . 333 173 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 364 $ 280 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $98 million and $84 million and for income taxes was $22 million and $3 million in 2000 and 1999, respectively. Noncash acquisitions under capital leases were $17 million and $18 million in 2000 and 1999, respectively. See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in millions) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $1,740 $1,684 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 104 151 DEDUCTIONS: Cash Dividends Declared. . . . . . . . . . . . . . . . . 116 115 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $1,728 $1,720 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state -ments should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In the first quarter of 2000 subsidiaries retired $180 million principal amount of long-term debt and issued $10 million of long-term debt. 3. COOK NUCLEAR PLANT SHUTDOWN As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. The two-unit, 2,110 MW Cook Plant is owned and operated by the Company's subsidiary, Indiana Michigan Power Company (I&M). In February 2000, I&M was notified by the NRC that the Confirmatory Action Letter had been closed. Closing of the Confirmatory Action Letter is one of the key approvals needed to restart the nuclear units. The Confirmatory Action Letter was issued in September 1997 requiring I&M to address certain issues identified in the letter. Progress to restart the units continues. Refueling of Unit 2, the first unit scheduled to restart, was completed on April 14, 2000. The NRC's final Unit 2 pre-restart inspection began on May 8, 2000, which coincided with the reactor heat-up of Unit 2 and the return to operational service of common plant systems. When testing and other work required for restart are complete, I&M will seek concurrence from the NRC to return Unit 2 to service. Refueling and maintenance work to restart Unit 1 will be performed after Unit 2 is returned to service. Any issues or difficulties encountered in testing of equipment as part of the restart process could delay the restart of the units. Expenditures to restart the Cook units are estimated to total approximately $574 million. Through March 31, 2000, $453 million has been spent. In 2000 $80 million of restart costs were recorded in other operation and maintenance expense, including amortization of $10 million of restart costs previously deferred in accordance with settlement agreements in the Indiana and Michigan retail jurisdictions. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations and on cash flows until the units are restarted. The amortization of restart costs deferred under Indiana and Michigan retail jurisdiction settlement agreements will adversely effect results of operations and possibly financial condition through 2003 when the amortization period ends. Management believes that the Cook units will be successfully returned to service. However, if for some unknown reason the units are not returned to service or their return is delayed significantly it would have an even greater adverse effect on future results of operations, cash flows and financial condition. 4. RATE MATTERS FERC As discussed in Note 3 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the AEP System companies filed a settlement agreement for FERC approval related to an open access transmission tariff. The Company made a provision in 1999 for an agreed to refund including interest. On March 16, 2000, the FERC approved the settlement agreement filed in December 1999 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 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder is to be paid upon approval by the FERC. In addition, a new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers and a future rate of $1.42 kw/month was established to take effect upon the consummation of the AEP and Central and South West Corporation merger. West Virginia As discussed in Note 3 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the Company's subsidiary Appalachian Power Company (APCO) has been involved in a rate proceeding regarding base and expanded net energy cost (ENEC) rates. On February 7, 2000, APCo and other parties to the proceeding filed a Joint Stipulation and Agreement for Settlement (Joint Stipulation) with the Public Service Commission of West Virginia (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 $66 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 cost or obligations that deregulation may impose. Also under the Joint Stipulation APCo's share of any net savings from the pending merger between AEP Co., Inc. and Central and South West Corporation prior to December 31, 2004 shall be retained by APCo. All cost 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 distribution 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 shall be used to recover any generation related regulatory assets that are not recovered under the other 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 a 0.5 mills per kwh wires charge in the WV Restructuring Plan (see Note 5 for discussion of WV Restructuring Plan). Because the Joint Stipulation incorporated rate issues that will affect customers of Wheeling Power Company, another AEP Co., Inc. subsidiary, the WVPSC determined that an opportunity for hearing should be given to Wheeling Power's customers before taking action on the Joint Stipulation. As a result hearings were held on May 10, 2000. 5. INDUSTRY RESTRUCTURING Ohio Restructuring Law and Transition Plan Filing As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the Act) provides for, among other things, customer choice of electricity supplier, a residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates beginning on January 1, 2001. The Act also provides for a five-year transition period to move from cost based rates to market pricing for generation services. It authorizes the Public Utilities Commission of Ohio (PUCO) to address certain major transition issues including unbundling of rates and the recovery of transition costs which include regulatory assets, generating asset impair-ments and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Stranded costs are generation costs that would not be recoverable in a competitive market. On March 28, 2000 the PUCO staff issued its report on the Company's transition plan filings. On May 8, 2000, a stipulation agreement between the Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties was filed with the PUCO. The key provisions of the stipulation agreement are: Recovery of regulatory assets over seven years for Ohio Power Company (OPCo) and eight years for Columbus Southern Companies (CSP). A shopping incentive of 2.5 mills/kwh for the first 25% of CSP residential customers that switch suppliers. No shopping incentive for OPCo customers. The absorption by CSP and OPCo of the first $20 million of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. The companies will make available a fund of up to $10 million for certain transmission charges imposed by PJM and/or a Midwest ISO on generation originating in the Midwest ISO or PJM. The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire transition period. The companies' request for a $90 million gross receipts tax rider will be litigated. Hearings to address the gross receipts taxes issue are scheduled for May 31, 2000. The stipulation agreement is subject to approval by the PUCO. Hearings on the stipulation are scheduled for June 7, 2000. Virginia Restructuring Under a 1999 Virginia restructuring law a transition to choice of 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, by January 1, 2004 but not later than January 1, 2005. The Virginia restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may 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 establishment of a wires charge by the fourth quarter of 2001. West Virginia Restructuring Plan As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the WVPSC issued an order on January 28, 2000 approving an electricity restructuring plan. On March 11, 2000, the West Virginia legislature approved the restructuring plan by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes necessary tax law changes to preserve the revenues of the state and local governments. 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 starting 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; establishment of a rate stabilization deferral balance of $81 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 an alternative 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. Currently the Company has a stipulation agreement before the WVPSC in connection with a base rate filing which provides mechanisms to recover the Company's regulatory assets. The agreement requires the approval of the WVPSC. Potential For Write Offs In Ohio, Virginia and West Virginia Jurisdictions Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated in the Ohio, Virginia and West Virginia jurisdictions. The Company's accounting for generation will continue to be in accordance with SFAS 71 in the Ohio and Virginia jurisdictions 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 other transition costs, a requirement to discontinue application of SFAS 71. When the transition plan and tariff schedules are approved, the application of SFAS 71 will be discontinued for the Ohio retail jurisdictional portion of the generating business. Management expects this to occur when the PUCO approves the stipulation agreement for the transition plan filings of the Company's Ohio jurisdictional electric operating subsidiaries. The Ohio Act requires that the PUCO issue its order to approve transition plan filings no later than October 31, 2000. The application of SFAS 71 will be discontinued in the Virginia retail jurisdictional portion of the Company's generating business when the capped rates and the wires charge are known in Virginia which is expected to occur by the fourth quarter of 2000. When the effects of implementation of the West Virginia restructuring plan are known and measurable, the application of SFAS 71 will be discontinued for the West Virginia retail jurisdictional portion of the Company's generating business. Upon the discontinuance of SFAS 71 the Company will have to write off its Ohio, 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 March 31, 2000 applicable to the Ohio, Virginia and West Virginia retail jurisdictional generating business is $724 million, $67 million and $131 million, respectively, before related tax effects. Due to the planned closing of the Company's affiliated mines, including the Meigs mine, projected generation-related regulatory assets as of December 31, 2000 (the date that recoverable generation-related regulatory assets are measured under the Ohio law) allocable to the Ohio retail jurisdiction are estimated to exceed $800 million, before income tax effects. Recovery of these regulatory assets is being sought as a part of the Company's Ohio transition plan filing. 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 PUCO approves the Company's stipulation agreement which provides for their recovery and whether the capped transition rates and allowed wires charges in Virginia and West Virginia will permit their recovery. A determination of whether the Company will experience any asset impairment loss regarding its Ohio, Virginia and West Virginia retail jurisdictional generating assets and any loss from a possible inability to recover Ohio, 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. In the event the Company is unable to recover all or a portion of its generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. 6. INVESTMENT IN YORKSHIRE The Company has a 50% ownership interest in Yorkshire Power Group Limited (Yorkshire) which is accounted for using the equity method of accounting. Equity income in Yorkshire is included in revenues from worldwide non-regulated operations. The following amounts which are not included in AEP's consolidated financial statements represent summarized consolidated financial information of total Yorkshire: Three Months Ended March 31, 2000 1999 (in millions) Income Statement Data: Operating Revenues $662.5 $652.0 Operating Income 117.1 113.5 Net Income 48.3 34.6
7. BUSINESS SEGMENTS The Company's principal business segment is its cost based rate regulated Domestic Electric Utility business consisting of seven regulated utility operating companies providing residential, commercial, industrial and wholesale electric services in seven Atlantic and Midwestern states. Also included in this segment are the Company's wholesale power marketing and trading activities that are conducted as part of regulated operations and subject to regulatory ratemaking oversight. The World Wide Electric and Gas Operations segment represents principally international investments in energy-related projects and operations. It also includes the development and management of such projects and operations. Such investment activities include electric generation, supply and distribution, and natural gas pipeline, storage and other natural gas services. Other business segments include non-regulated electric and gas trading activities, telecommunication services, and the marketing of various energy saving products and services. Financial data for the business segments for the first quarter of 2000 and 1999 is in the following table: Domestic Regulated Worldwide Elimination Electric Electric and Reconciling AEP Utilities Gas Operations Other Adjustments Consolidated (in millions) March 31, 2000 Revenues from external unaffiliated customers $ 1,546 $ 236 $(36) $ - $ 1,746 Revenues from transactions with other operating segments - 25 67 (92) - Segment net income (loss) 87 24 (7) - 104 Total assets 18,596 2,368 938 - 21,902 March 31, 1999 Revenues from external unaffiliated customers 1,550 148 (4) - 1,694 Revenues from transactions with other operating segments - 17 31 (48) - Segment net income (loss) 150 8 (7) - 151 Total assets 17,440 2,148 542 - 20,130
8. MERGER As discussed in Note 8 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company and Central and South West Corporation (CSW) announced plans to merge in December 1997. The appropriate shareholder proposals for the consummation of the merger were approved in 1998. The merger agreement was amended to extend the term of the original agreement to June 30, 2000 and requires the Company to close the merger before that date. The merger has received approval from state regulatory commissions in Arkansas, Louisiana, Oklahoma and Texas, the four states within CSW's service territory which are required to approve the merger. AEP has reached agreements with its state regulatory commission in Indiana, Michigan, Ohio and Kentucky regarding merger costs, savings and other merger related rate matters. These AEP service territory state commissions have agreed not to oppose the merger in federal proceedings. In addition, the Nuclear Regulatory Commission has approved a license transfer application for the transfer of control of CSW subsidiary Central Power and Light's South Texas Nuclear Plant to the Company and the Department of Justice closed its investigation under the Hart-Scott-Rodino Antitrust Improvements Act. Also, in 1998 the Federal Energy Regulatory Commission (FERC) issued an order which confirmed that a 250 MW firm contract path with the Ameren System was available. The contract path was obtained by the Company and CSW to meet the requirement of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. On March 15, 2000, the FERC conditionally approved the merger. Conditions placed on the merger include: The transfer of operational control of AEP's east (the current AEP transmission system) and west (the current CSW transmission system) transmission systems to a fully-functioning, FERC-approved regional transmission organization by December 15, 2001, which is the same implementation date included in the FERC's general order for regional transmission organizations that applies to all transmission-owning utilities. The independent calculation and posting of available transmission capacity to monitor the operation of AEP's east transmission system. The divestiture of 550 MW of generating capacity comprised of 300 MW of capacity in the Southwest Power Pool (SPP) and 250 MW of capacity in the Electric Reliability Council of Texas (ERCOT). The FERC is requiring AEP and CSW to divest their entire ownership interest in and operational control of the entire generating facilities that produce the capacity to be divested. Alternatively, AEP and CSW may choose to divest the same or a greater amount of capacity from different generating units in their entirety. However, such generating units must be of similar cost, operation and location characteristics as the generating units AEP and CSW originally agreed to divest. AEP and CSW must complete divestiture of the ERCOT capacity by March 15, 2001 and divestiture of the SPP capacity by July 1, 2002. The FERC found that certain energy sales in SPP and ERCOT would be reasonable and effective interim mitigation measures until completion of the required SPP and ERCOT divestitures. The FERC will require the proposed interim energy sales to be in effect when the merger is consummated. The Company and CSW submitted a compliance filing to the FERC on March 31, 2000. The filing outlines the companies' plans to comply with conditions placed on the merger in the commission's March 15 conditional approval. The FERC's merger order required the applicants to make the compliance filing at least 60 days before consummating the merger. The two interim transmission - related mitigation measures required as a condition for merger approval are to be in place until the date that the post-merger AEP east transmission system is under operational control of a FERC-approved regional transmission organization (RTO). The conditions and the companies's plans to comply are: Independent calculation and posting of available trans -mission capacity (ATC): AEP has contracted with the SPP to perform independent ATC calculation and postings. The SPP will also perform another critical open access same time information system (OASIS) function -- the disposing of transmission service requests from customers, including marketers affiliated with AEP, seeking service over the AEP east transmission zone. Independent market monitoring: an independent third party will be responsible for reviewing transmission constraint data, the effectiveness of redispatch to alleviate such constraints, and the impacts of redispatch on the volume and price of energy before and after redispatch. The merger also requires approval of the SEC. In October 1998 AEP and CSW jointly filed an application with the SEC for approval of the proposed merger under the Public Utility Holding Company Act of 1935. The SEC merger filing requests approval of the merger and related transactions and outlines the expected combined company benefits of the merger to the Company and CSW customers and shareholders. Since then, the Company and CSW have filed several amendments to the application. Approval of the merger by the SEC is pending. As of March 31, 2000, AEP had deferred $47 million of incremental costs related to the merger on its consolidated balance sheet. Although consummation of the merger is expected to occur in the second quarter of 2000, the Company is unable to predict the outcome or the timing of the required regulatory proceedings. 9. CONTINGENCIES Litigation As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $318 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet in other assets 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at certain of its 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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 where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. NOx Reductions As discussed in Note 7 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the Company and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $1.6 billion 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 and/or future market prices for electricity if generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in the 1999 Annual Report. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 2000 vs. FIRST QUARTER 1999 RESULTS OF OPERATIONS Net income declined by $47 million or 31% due predominately to current expenditures and the amortization of previously deferred expenditures in the Company's domestic regulated electric utility operations to prepare the Cook Plant for restart following an extended outage. The Cook Plant began an extended outage in September 1997 when both generating units were shut down because of questions regarding the operability of certain safety systems. In the first quarter of 1999 certain restart expenses were deferred in accordance with a settlement agreement in Indiana which resolved all Indiana jurisdictional rate-related issues applicable to the Cook Plant's extended outage. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Revenues - Worldwide Non-regulated Operations. . . . . . . . . . $ 56 39 Fuel and Purchased Power Expense . . . . . . 20 4 Maintenance and Other Operation Expense. . . 62 15 Worldwide Non-regulated Operations Expense . 37 29 Income Taxes . . . . . . . . . . . . . . . . (30) (32) Revenues from Worldwide Non-regulated Operations increased by 39% primarily due to increased natural gas and gas liquid product prices. Volumes of natural gas remained consistent with prior year however prices have increased approximately 50% rebounding from the depressed market condition in the first quarter of 1999. The sales volumes for gas liquids have also increased due to the additional capacity of a gas processing facility which became operational in February 1999. The increase in fuel and purchased power expense was primarily attributable to an increase in generation partially offset by deferral of affiliated mine shutdown costs under the Ohio fuel clause mechanism. Net generation increased 3% due to increased availability of generation plant. Maintenance and other operation expense increased significantly largely as a result of expenditures to prepare the Cook Nuclear Plant units for restart following an extended Nuclear Regulatory Commission (NRC) monitored outage which began in September 1997. Worldwide Non-regulated Electric and Gas Operations expenses rose in the current year as prices for natural gas increased significantly. The decrease in income taxes is predominately due to a decrease in pre-tax income. FINANCIAL CONDITION Total plant and property additions including capital leases for the current period were $203 million. During the first three months of 2000 domestic subsidiaries issued $10 million principal amount of long-term obligations at an initial interest rate of 6.305% and retired $180 million amount of long-term debt with interest rates ranging from 6.35% to 8.40% and increased short-term debt by $230 million from year-end balances. OTHER MATTERS Cook Nuclear Plant Shutdown As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. The two-unit, 2,110 MW Cook Plant is owned and operated by the Company's subsidiary, Indiana Michigan Power Company (I&M). In February 2000, I&M was notified by the NRC that the Confirmatory Action Letter had been closed. Closing of the Confirmatory Action Letter is one of the key approvals needed to restart the nuclear units. The Confirmatory Action Letter was issued in September 1997 requiring I&M to address certain issues identified in the letter. Progress to restart the units continues. Refueling of Unit 2, the first unit scheduled to restart, was completed on April 14, 2000. The NRC's final Unit 2 pre-restart inspection began on May 8, 2000, which coincided with the reactor heat-up of Unit 2 and the return to operational service of common plant systems. When testing and other work required for restart are complete, I&M will seek concurrence from the NRC to return Unit 2 to service. Refueling and maintenance work to restart Unit 1 will be performed after Unit 2 is returned to service. Any issues or difficulties encountered in testing of equipment as part of the restart process could delay the restart of the units. Expenditures to restart the Cook units are estimated to total approximately $574 million. Through March 31, 2000, $453 million has been spent. In 2000 $80 million of restart costs were recorded in other operation and maintenance expense, including amortization of $10 million of restart costs previously deferred in accordance with settlement agreements in the Indiana and Michigan retail jurisdictions. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations and cash flows until the units are restarted. The amortization of restart costs deferred under Indiana and Michigan retail jurisdiction settlement agreements will adversely effect results of operations and possibly financial condition through 2003 when the amortization period ends. Management believes that the Cook units will be successfully returned to service. However, if for some unknown reason the units are not returned to service or their return is delayed significantly it would have an even greater adverse effect on future results of operations, cash flows and financial condition. Merger As discussed in Note 8 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company and Central and South West Corporation (CSW) announced plans to merge in December 1997. The appropriate shareholder proposals for the consummation of the merger were approved in 1998. The merger agreement was amended to extend the term of the original agreement to June 30, 2000 and requires the Company to close the merger before that date. The merger has received approval from state regulatory commissions in Arkansas, Louisiana, Oklahoma and Texas, the four states within CSW's service territory which are required to approve the merger. AEP has reached agreements with its state regulatory commission in Indiana, Michigan, Ohio and Kentucky regarding merger costs, savings and other merger related rate matters. These AEP service territory state commissions have agreed not to oppose the merger in federal proceedings. In addition, the Nuclear Regulatory Commission has approved a license transfer application for the transfer of control of CSW subsidiary Central Power and Light's South Texas Nuclear Plant to the Company and the Department of Justice closed its investigation under the Hart-Scott-Rodino Antitrust Improvements Act. Also, in 1998 the Federal Energy Regulatory Commission (FERC) issued an order which confirmed that a 250 MW firm contract path with the Ameren System was available. The contract path was obtained by the Company and CSW to meet the requirement of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. On March 15, 2000, the FERC conditionally approved the merger. Conditions placed on the merger include: The transfer of operational control of AEP's east (the current AEP transmission system) and west (the current CSW transmission system) transmission systems to a fully-functioning, FERC-approved regional transmission organization by December 15, 2001, which is the same implementation date included in the FERC's general order for regional transmission organizations that applies to all transmission-owning utilities. The independent calculation and posting of available transmission capacity to monitor the operation of AEP's east transmission system. The divestiture of 550 MW of generating capacity comprised of 300 MW of capacity in the Southwest Power Pool (SPP) and 250 MW of capacity in the Electric Reliability Council of Texas (ERCOT). The FERC is requiring AEP and CSW to divest their entire ownership interest in and operational control of the entire generating facilities that produce the capacity to be divested. Alternatively, AEP and CSW may choose to divest the same or a greater amount of capacity from different generating units in their entirety. However, such generating units must be of similar cost, operation and location characteristics as the generating units AEP and CSW originally agreed to divest. AEP and CSW must complete divestiture of the ERCOT capacity by March 15, 2001 and divestiture of the SPP capacity by July 1, 2002. The FERC found that certain energy sales in SPP and ERCOT would be reasonable and effective interim mitigation measures until completion of the required SPP and ERCOT divestitures. The FERC will require the proposed interim energy sales to be in effect when the merger is consummated. The Company and CSW submitted a compliance filing to the FERC on March 31, 2000. The filing outlines the companies' plans to comply with conditions placed on the merger in the commission's March 15 conditional approval. The FERC's merger order required the applicants to make the compliance filing at least 60 days before consummating the merger. The two interim transmission - related mitigation measures required as a condition for merger approval are to be in place until the date that the post-merger AEP east transmission system is under operational control of a FERC-approved regional transmission organization (RTO). The conditions and the companies's plans to comply are: Independent calculation and posting of available trans-mission capacity (ATC): AEP has contracted with the SPP to perform independent ATC calculation and postings. The SPP will also perform another critical open access same time information system (OASIS) function -- the disposing of transmission service requests from customers, including marketers affiliated with AEP, seeking service over the AEP east transmission zone. Independent market monitoring: an independent third party will be responsible for reviewing transmission constraint data, the effectiveness of redispatch to alleviate such constraints, and the impacts of redispatch on the volume and price of energy before and after redispatch. The merger also requires approval of the SEC. In October 1998 AEP and CSW jointly filed an application with the SEC for approval of the proposed merger under the Public Utility Holding Company Act of 1935. The SEC merger filing requests approval of the merger and related transactions and outlines the expected combined company benefits of the merger to the Company and CSW customers and shareholders. Since then, the Company and CSW have filed several amendments to the application. Approval of the merger by the SEC is pending. As of March 31, 2000, AEP had deferred $47 million of incremental costs related to the merger on its consolidated balance sheet. Although consummation of the merger is expected to occur in the second quarter of 2000, the Company is unable to predict the outcome or the timing of the required regulatory proceedings. Industry Restructuring Ohio Restructuring Law and Transition Plan Filing As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the Act) provides for, among other things, customer choice of electricity supplier, a residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates beginning on January 1, 2001. The Act also provides for a five-year transition period to move from cost based rates to market pricing for generation services. It authorizes the Public Utilities Commission of Ohio (PUCO) to address certain major transition issues including unbundling of rates and the recovery of transition costs which include regulatory assets, generating asset impairments and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Stranded costs are generation costs that would not be recoverable in a competitive market. On March 28, 2000 the PUCO staff issued its report on the Company's transition plan filings. On May 8, 2000, a stipulation agreement between the Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties was filed with the PUCO. The key provisions of the stipulation agreement are: Recovery of regulatory assets over seven years for Ohio Power Company (OPCo)and eight years for Columbus Southern Company (CSP). A shopping incentive of 2.5 mills/kwh for the first 25% of CSP residential customers that switch suppliers. No shopping incentive for OPCo customers. The absorption by CSP and OPCo of the first $20 million of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. The companies will make available a fund of up to $10 million for certain transmission charges imposed by PJM and/or Midwest ISO on generation originating in the Midwest ISO or PJM. The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire transition period. The companies' request for a $90 million gross receipts tax rider will be litigated. Hearings to address the gross receipts tax issue are scheduled for May 31, 2000. The stipulation agreement is subject to approval by the PUCO. Hearings on the stipulation are scheduled for June 7, 2000. Virginia Restructuring Under a 1999 Virginia restructuring law a transition to choice of 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 January 1, 2004. The Virginia restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may 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 establishment of a wires charge by the fourth quarter of 2001. West Virginia Restructuring Plan As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Public Service Commission of West Virginia (WVPSC) issued an order on January 28, 2000 approving an electricity restructuring plan. On March 11, 2000, the West Virginia legislature approved the restructuring plan by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes necessary tax law changes to preserve the revenues of the state and local governments. 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 starting 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; establishment of a rate stabilization deferral balance of $81 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 an alternative 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. Currently the Company has a stipulation agreement before the WVPSC in connection with a base rate filing which provides mechanisms to recovery the Company's regulatory assets. The agreement requires the approval of the WVPSC. Potential For Write Offs In Ohio, Virginia and West Virginia Jurisdictions Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated in the Ohio, Virginia and West Virginia jurisdictions. The Company's accounting for generation will continue to be in accordance with SFAS 71 in the Ohio and Virginia jurisdictions 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 other transition costs, a requirement to discontinue application of SFAS 71. When the transition plan and tariff schedules are approved, the application of SFAS 71 will be discontinued for the Ohio retail jurisdictional portion of the generating business. Management expects this to occur when the PUCO approves the stipulation agreement for the transition plan filings for the Company's Ohio jurisdictional electric operating subsidiaries. The Ohio Act requires that the PUCO issue its order to approve transition plan filings no later than October 31, 2000. The application of SFAS 71 will be discontinued in the Virginia retail jurisdictional portion of the Company's generating business when the capped rates and the wires charge are known in Virginia which is expected to occur by the fourth quarter of 2000. When the effects of the West Virginia restructuring plan are known and measurable, the application of SFAS 71 will be discontinued for the West Virginia retail jurisdictional portion of the Company's generating business. Upon the discontinuance of SFAS 71 the Company will have to write off its Ohio, 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 March 31, 2000 applicable to the Ohio, Virginia and West Virginia retail jurisdictional generating business is $724 million, $67 million and $131 million, respectively, before related tax effects. Due to the planned closing of the Company's affiliated mines, including the Meigs mine, projected generation-related regulatory assets as of December 31, 2000 (the date that recoverable generation-related regulatory assets are measured under the Ohio law) allocable to the Ohio retail jurisdiction are estimated to exceed $800 million, before income tax effects. Recovery of these regulatory assets is being sought as a part of the Company's Ohio transition plan filing. 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 PUCO approves the Company's request for their recovery and whether the capped transition rates and allowed wires charges in Virginia and West Virginia will permit their recovery. A determination of whether the Company will experience any asset impairment loss regarding its Ohio, Virginia and West Virginia retail jurisdictional generating assets and any loss from a possible inability to recover Ohio, 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 PUCO or the Virginia SCC fail to approve transition rates and wires charges that are sufficient to provide for recovery or it not be possible under the West Virginia restructuring plan to recover all or a portion of the Company's generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Litigation As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $318 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet in other assets 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at certain of its 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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 where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity. NOx Reductions As discussed in Note 7 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the Company and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $1.6 billion 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 and/or future market prices for electricity if generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities which represent the risk of loss that may impact the Company due to adverse changes in electricity and gas commodity prices, foreign currency exchange rates and interest rates. The Company's European energy trading operations which commenced in January 2000 are not material. The Company's exposure to market risk from the trading of electricity and natural gas and related financial derivative instruments has not changed materially since December 31, 1999. There have been no material changes to the Company's exposure to fluctuations in foreign currency exchange rates related to foreign ventures and investments since December 31, 1999. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 2000 is not materially different than at December 31, 1999. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $56,866 $52,827 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 24,435 20,258 Rent - Rockport Plant Unit 2 . . . . . . . . . . . . . . . 17,071 17,071 Other Operation. . . . . . . . . . . . . . . . . . . . . . 3,098 3,370 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . 2,515 2,262 Depreciation . . . . . . . . . . . . . . . . . . . . . . . 5,505 5,440 Taxes Other Than Federal Income Taxes. . . . . . . . . . . 1,126 1,239 Federal Income Taxes . . . . . . . . . . . . . . . . . . . 721 827 TOTAL OPERATING EXPENSES . . . . . . . . . . . . . 54,471 50,467 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 2,395 2,360 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . 869 856 INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 3,264 3,216 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . 819 602 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,445 $ 2,614 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2000 1999 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . $3,673 $2,770 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . 2,445 2,614 CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . . . . . 1,935 1,073 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . $4,183 $4,311 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production. . . . . . . . . . . . . . . . . . . . . . $631,434 $629,286 General . . . . . . . . . . . . . . . . . . . . . . . 2,620 2,400 Construction Work in Progress . . . . . . . . . . . . 5,497 8,407 Total Electric Utility Plant. . . . . . . . . 639,551 640,093 Accumulated Depreciation. . . . . . . . . . . . . . . 298,776 295,065 NET ELECTRIC UTILITY PLANT. . . . . . . . . . 340,775 345,028 CURRENT ASSETS: Cash and Cash Equivalents . . . . . . . . . . . . . . 1,706 317 Accounts Receivable: Affiliated Companies. . . . . . . . . . . . . . . . 16,695 22,464 Miscellaneous . . . . . . . . . . . . . . . . . . . 2,731 2,643 Fuel. . . . . . . . . . . . . . . . . . . . . . . . . 17,002 17,505 Materials and Supplies. . . . . . . . . . . . . . . . 4,008 3,966 Prepayments . . . . . . . . . . . . . . . . . . . . . 116 150 TOTAL CURRENT ASSETS. . . . . . . . . . . . . 42,258 47,045 REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . 5,684 5,744 DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . 3,278 823 TOTAL . . . . . . . . . . . . . . . . . . . $391,995 $398,640 See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $1,000: Authorized and Outstanding - 1,000 Shares . . . . . $ 1,000 $ 1,000 Paid-in Capital . . . . . . . . . . . . . . . . . . . 27,235 29,235 Retained Earnings . . . . . . . . . . . . . . . . . . 4,183 3,673 Total Common Shareholder's Equity . . . . . . 32,418 33,908 TOTAL CAPITALIZATION. . . . . . . . . . . . . 32,418 33,908 OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . 534 592 CURRENT LIABILITIES: Long-term Debt Due Within One Year. . . . . . . . . . 44,802 44,800 Short-term Debt - Notes Payable . . . . . . . . . . . 7,050 24,700 Accounts Payable - General. . . . . . . . . . . . . . 6,068 7,539 Accounts Payable - Affiliated Companies . . . . . . . 16,236 19,451 Taxes Accrued . . . . . . . . . . . . . . . . . . . . 8,483 4,285 Rent Accrued - Rockport Plant Unit 2. . . . . . . . . 23,427 4,963 Other . . . . . . . . . . . . . . . . . . . . . . . . 2,592 4,763 TOTAL CURRENT LIABILITIES . . . . . . . . . . 108,658 110,501 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . 126,366 127,759 REGULATORY LIABILITIES: Deferred Investment Tax Credits . . . . . . . . . . . 62,277 63,114 Amounts Due to Customers for Income Taxes . . . . . . 25,687 26,266 TOTAL REGULATORY LIABILITIES. . . . . . . . . 87,964 89,380 DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . 35,705 36,500 DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . 350 - CONTINGENCIES (Note 2) TOTAL . . . . . . . . . . . . . . . . . . . $391,995 $398,640 See Notes to Financial Statements.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 2,445 $ 2,614 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . 5,505 5,440 Deferred Federal Income Taxes. . . . . . . . . . . . . (1,374) (1,339) Deferred Investment Tax Credits. . . . . . . . . . . . (837) (838) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2. . . . . . . . . . . . . . . . (1,393) (1,393) Deferred Property Taxes. . . . . . . . . . . . . . . . (2,489) (2,410) Changes in Certain Current Assets and Liabilities: Accounts Receivable. . . . . . . . . . . . . . . . . . 5,681 2,700 Fuel, Materials and Supplies . . . . . . . . . . . . . 461 (7,863) Accounts Payable . . . . . . . . . . . . . . . . . . . (4,686) 4,539 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 4,198 5,627 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . 18,464 18,464 Other (net). . . . . . . . . . . . . . . . . . . . . . . (1,735) (1,045) Net Cash Flows From Operating Activities . . . . . 24,240 24,496 INVESTING ACTIVITIES - Net Cash Flows Used for Construction. . . . . . . . . . . . . . . . . . . . . (1,266) (770) FINANCING ACTIVITIES: Return of Capital to Parent Company. . . . . . . . . . . (2,000) (2,000) Change in Short-term Debt (net). . . . . . . . . . . . . (17,650) (18,875) Dividends Paid . . . . . . . . . . . . . . . . . . . . . (1,935) (1,073) Net Cash Flows Used For Financing Activities . . . (21,585) (21,948) Net Increase (Decrease) in Cash and Cash Equivalents . . . 1,389 1,778 Cash and Cash Equivalents at Beginning of Period . . . . . 317 232 Cash and Cash Equivalents at End of Period . . . . . . . . $ 1,706 $ 2,010 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $732,000 and $470,000 in 2000 and 1999, respectively, and for income taxes was $678,000 in 2000. See Notes to Financial Statements.
AEP GENERATING COMPANY NOTES TO FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. CONTINGENCIES NOx Reductions As discussed in Note 3 of the Notes of Financial Statements of the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 generally upholding the United States Environmental Protection Agency'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 AEP System's generating plants are located. A number of utilities, including the AEP System companies, had filed petitions seeking a review of the final rule in the Appeals Court. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $125 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 and/or reflected in the future market price of electricity if generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2000 vs. FIRST QUARTER 1999 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies and in 1999 one unaffiliated utility pursuant to Federal Energy Regulatory Commission (FERC) approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Although operating revenues increased 8%, net income declined $0.2 million or 6% for the first quarter 2000 as a result of the return of capital to the parent company in February 1999, May 1999 and March 2000. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues $ 4.0 8 Fuel 4.2 21 Other Operation (0.3) (8) Maintenance 0.3 11 Taxes Other Than Federal Income Taxes (0.1) (9) Federal Income Taxes (0.1) (13) Interest Charges 0.2 36 The increase in operating revenues resulted from an increase in generation due to the availability of the Rockport Plant partially offset by reduced billings for the return on equity component under the unit power agreements, reflecting the return of capital. In 1999 planned outages reduced the availability of the Rockport Plant units. Shorter outages in the first quarter of 2000 allowed the Rockport units to generate 16% more electricity than in 1999. Fuel expense increased due to the increase in generation and a rise in the average cost of fuel. The increase in generation is attributable to the increased availability of the Rockport Plant units. The rise in the cost of fuel results from fluctuations in the market price of coal. Changes in the cost of coal are reflected in the unit power bills and do not affect net income. The decrease in other operation expense is primarily due to a 1999 payment to the City of Rockport in settlement of an annexation issue. Although the duration of the planned outages was shorter in 2000 than 1999, the nature of the work performed resulted in more maintenance expense. Taxes other than federal income taxes declined due to a decrease in taxable income calculated for state taxes. Federal income taxes attributable to operations decreased due to a decrease in pre-tax operating income. Interest charges increased due to an increase in average interest rates on short-term and variable rate debt and an increase in the average outstanding short-term debt balance reflecting market conditions for short-term interest rates and the Company's short-term cash demands. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $455,595 $427,702 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 98,557 123,573 Purchased Power. . . . . . . . . . . . . . . . . . . . . 92,564 50,591 Other Operation. . . . . . . . . . . . . . . . . . . . . 60,641 62,749 Maintenance. . . . . . . . . . . . . . . . . . . . . . . 28,325 28,511 Depreciation and Amortization. . . . . . . . . . . . . . 38,338 36,551 Taxes Other Than Federal Income Taxes. . . . . . . . . . 30,645 29,975 Federal Income Taxes . . . . . . . . . . . . . . . . . . 28,279 24,145 TOTAL OPERATING EXPENSES . . . . . . . . . . . . 377,349 356,095 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 78,246 71,607 NONOPERATING INCOME (LOSS) . . . . . . . . . . . . . . . . 781 (1,088) INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 79,027 70,519 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 31,363 31,258 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 47,664 39,261 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 633 675 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 47,031 $ 38,586 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2000 1999 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $175,854 $179,461 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 47,664 39,261 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . 31,653 30,348 Cumulative Preferred Stock . . . . . . . . . . . . . . 525 567 Capital Stock Expense. . . . . . . . . . . . . . . . . . 108 108 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $191,232 $187,699 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,027,997 $2,014,968 Transmission . . . . . . . . . . . . . . . . . . . . 1,155,336 1,151,377 Distribution . . . . . . . . . . . . . . . . . . . . 1,759,361 1,741,685 General. . . . . . . . . . . . . . . . . . . . . . . 251,634 247,798 Construction Work in Progress. . . . . . . . . . . . 94,906 107,123 Total Electric Utility Plant . . . . . . . . 5,289,234 5,262,951 Accumulated Depreciation and Amortization. . . . . . 2,104,479 2,079,490 NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,184,755 3,183,461 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 189,913 160,546 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 10,923 64,828 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 104,867 109,525 Affiliated Companies . . . . . . . . . . . . . . . 37,470 37,827 Miscellaneous. . . . . . . . . . . . . . . . . . . 9,254 9,154 Allowance for Uncollectible Accounts . . . . . . . (4,697) (2,609) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 49,260 58,161 Materials and Supplies . . . . . . . . . . . . . . . 56,261 56,917 Accrued Utility Revenues . . . . . . . . . . . . . . 38,120 53,418 Energy Trading Contracts . . . . . . . . . . . . . . 269,416 143,777 Prepayments. . . . . . . . . . . . . . . . . . . . . 6,848 7,713 TOTAL CURRENT ASSETS . . . . . . . . . . . . 577,722 538,711 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 436,744 436,894 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 40,737 34,788 TOTAL. . . . . . . . . . . . . . . . . . . $4,429,871 $4,354,400 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (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. . . . . . . . . . . . . . . . . . 714,434 714,259 Retained Earnings. . . . . . . . . . . . . . . . . 191,232 175,854 Total Common Shareholder's Equity. . . . . 1,166,124 1,150,571 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . 18,260 18,491 Subject to Mandatory Redemption. . . . . . . . . 20,310 20,310 Long-term Debt . . . . . . . . . . . . . . . . . . 1,535,052 1,539,302 TOTAL CAPITALIZATION . . . . . . . . . . . 2,739,746 2,728,674 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . 124,047 132,130 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . 48,005 126,005 Short-term Debt. . . . . . . . . . . . . . . . . . 128,425 123,480 Accounts Payable - General . . . . . . . . . . . . 43,369 59,150 Accounts Payable - Affiliated Companies. . . . . . 45,117 42,459 Taxes Accrued. . . . . . . . . . . . . . . . . . . 65,481 49,038 Customer Deposits. . . . . . . . . . . . . . . . . 12,764 12,898 Interest Accrued . . . . . . . . . . . . . . . . . 29,894 19,079 Energy Trading Contracts . . . . . . . . . . . . . 245,596 140,279 Other. . . . . . . . . . . . . . . . . . . . . . . 66,761 71,044 TOTAL CURRENT LIABILITIES. . . . . . . . . 685,412 643,432 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 676,645 671,917 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . 56,093 57,259 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . 147,928 120,988 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . $4,429,871 $4,354,400 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 47,664 $ 39,261 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . 38,366 36,814 Deferred Federal Income Taxes. . . . . . . . . . . . . 8,180 12,362 Deferred Investment Tax Credits. . . . . . . . . . . . (1,166) (1,172) Deferred Power Supply Costs (net). . . . . . . . . . . (8,157) 14,706 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . 7,003 46,450 Fuel, Materials and Supplies . . . . . . . . . . . . . 9,557 (5,799) Accrued Utility Revenues . . . . . . . . . . . . . . . 15,298 10,977 Prepayments. . . . . . . . . . . . . . . . . . . . . . 865 (6,348) Accounts Payable . . . . . . . . . . . . . . . . . . . (13,123) (13,802) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 16,443 14,702 Interest Accrued . . . . . . . . . . . . . . . . . . . 10,815 9,298 Other (net). . . . . . . . . . . . . . . . . . . . . . . (35,164) (41,060) Net Cash Flows From Operating Activities . . . . . 96,581 116,389 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . (39,901) (38,129) Proceeds from Sale of Property . . . . . . . . . . . . . 16 127 Net Cash Flows Used For Investing Activities . . . (39,885) (38,002) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . 4,945 (19,125) Retirement of Cumulative Preferred Stock . . . . . . . . (164) (4) Retirement of Long-term Debt . . . . . . . . . . . . . . (83,201) - Dividends Paid on Common Stock . . . . . . . . . . . . . (31,653) (30,348) Dividends Paid on Cumulative Preferred Stock . . . . . . (528) (567) Net Cash Flows Used For Financing Activities . . . (110,601) (50,044) Net Increase (Decrease) in Cash and Cash Equivalents . . . (53,905) 28,343 Cash and Cash Equivalents at Beginning of Period . . . . . 64,828 7,755 Cash and Cash Equivalents at End of Period . . . . . . . . $ 10,923 $ 36,098 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $19,610,000 and $21,009,000 and for income taxes was $6,693,000 and $57,000 in 2000 and 1999, respectively. Noncash acquisitions under capital leases were $3,361,000 and $2,453,000 in 2000 and 1999, respectively. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In January 2000 the Company redeemed $30 million of 7.40% pollution control bonds due 2014 at 102%. In March 2000 the Company redeemed at maturity $48 million of 6.35% first mortgage bonds. 3. RATE MATTERS FERC As discussed in Note 4 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the AEP System companies filed a settlement agreement for Federal Energy Regulatory Commission (FERC) approval related to an open access transmission tariff. The Company made a provision in 1999 for an agreed to refund including interest. On March 16, 2000, the FERC approved the settlement agreement filed in December 1999 resolving the issues on rehearing of a 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 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder is to be paid upon approval by the FERC. In addition, a new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers and a future rate of $1.42 kw/month was established to take effect upon the consummation of the AEP and Central and South West Corporation merger. West Virginia As discussed in Note 4 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the Company has been involved in a rate proceeding regarding base and expanded net energy cost (ENEC) rates. On February 7, 2000, APCo and other parties to the proceeding filed a Joint Stipulation and Agreement for Settlement (Joint Stipulation) with the Public Service Commission of West Virginia (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 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; and the net cumulative deferred ENEC recovery balance as established by a WVPSC order on December 27, 1996, which is $66 million at December 31, 1999, shall remain on the books as a regulatory liability. If deregulation of generation occurs in West Virginia (WV), the Company will use this $66 million regulatory liability to reduce unrecoverable generation-related regulatory assets and, to the extent possible, any additional costs or obligations that deregulation may impose. Also under the Joint Stipulation the Company's share of any net savings from the pending merger between AEP Co., Inc. and Central and South West Corporation prior to December 31, 2004 shall be retained by the Company. All cost incurred in the merger that are allocated to the Company, 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 distribution 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 shall be used to recover any generation related regulatory assets that are not recovered under the other 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 the Company. Regardless of whether the net cumulative deferred ENEC recovery balance and the net merger savings are sufficient to offset all of the Company's generation-related regulatory assets, under the terms of the Joint Stipulation there will be no further explicit adjustment to the Company's rates to provide for recovery of generation-related regulatory assets beyond the above discussed adjustments provided in the Joint Stipulation and a 0.5 mills per kwh wires charge in the WV Restructuring Plan (see Note 4 for discussion of WV Restructuring Plan). Because the Joint Stipulation incorporated rate issues that will affect customers of Wheeling Power Company, another AEP Co., Inc. subsidiary, the WVPSC determined that an opportunity for hearing should be given to Wheeling Power's customers before taking action on the Joint Stipulation. Hearings were held May 10, 2000. 4. RESTRUCTURING Virginia Restructuring Under a 1999 Virginia restructuring law a transition to choice of 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, by January 1, 2004 but not later than January 1, 2005. The Virginia restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may 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 Plan As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the WVPSC issued an order on January 28, 2000 approving an electricity restructuring plan for West Virginia. On March 11, 2000, the West Virginia legislature approved the restructuring plan by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes necessary tax law changes to preserve the revenues of the state and local governments. Until the West Virginia legislature makes the required tax law changes, the restructuring plan cannot take effect. 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 on the starting date; functional separation of the generation, transmission and distribution businesses on the starting 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 deferral 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 an alternative supplier. Default rates for residential and small commercial customers are capped for four years after the starting date and then increase 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 reduced 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. Potential For Write Offs In Virginia and West Virginia Jurisdictions Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated in the Virginia and West Virginia jurisdictions. The Company's accounting for generation will continue to be in accordance with SFAS 71 in the Virginia jurisdictions and will continue to be considered to be cost-based regulated for accounting purposes until the amount of capped rates and stranded cost wires charges are determined and known. The establishment of capped rates and wire charges should enable management to determine the Company's ability to recover stranded costs including regulatory assets and other transition costs, a requirement to discontinue application of SFAS 71. The application of SFAS 71 will be discontinued for the Virginia retail jurisdictional portion of the Company's generating 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 effects of implementation of the West Virginia restructuring plan are known and measurable. 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 capped rates and stranded cost 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 March 31, 2000 applicable to the Virginia and West Virginia retail jurisdictional generating business is $67 million and $131 million, respectively, before related tax effects. 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 and whether the Company can reduce its cost under the capped rates. A 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 a 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 it not be possible under the West Virginia restructuring plan to recover all or a portion of the Company's generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. 5. CONTINGENCIES Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 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 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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, unbundled transition period generation rates, stranded cost wires charges and future market prices for energy. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals 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 and/or future market prices for electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1999 Annual Report. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 2000 vs. FIRST QUARTER 1999 RESULTS OF OPERATIONS Net income increased due to a rise in operating income reflecting a reduction in fuel costs and an increase in nonoperating income. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues. . . . . . . . . . $ 27.9 7 Fuel. . . . . . . . . . . . . . . . . (25.0) (20) Purchased Power . . . . . . . . . . . 42.0 83 Federal Income Taxes. . . . . . . . . 4.1 17 Nonoperating Income . . . . . . . . . 1.9 N.M. N.M. = Not Meaningful The increases in operating revenues and purchased power expense reflect a significant increase in American Electric Power System Power Pool (AEP Power Pool) transactions. The Company as a member of the AEP Power Pool shares in the revenues and cost of fuel and purchase power expenses from the AEP Power Pool's wholesale sales to neighboring utilities and marketers. As a result of an affiliated company's major industrial customer's decision not to extend its purchase power agreement, additional power was available to the AEP Power Pool for sale on the wholesale market providing the opportunity to increase Power Pool revenues. The increase in operating revenues were partially offset by the effect of a favorable adjustment in 1999 to a provision for revenue refunds in the Company's Virginia jurisdiction in connection with the payment of the refund. Fuel expense decreased due to a discontinuance of deferral accounting for the over or under recovery of fuel cost effective January 1, 2000 as a result of a Joint Stipulation in the Company's West Virginia jurisdiction. Fuel costs have declined since discontinuance of deferral accounting favorably impacting fuel expense. The increase in federal income tax expense attributable to operations is primarily due to an increase in pre-tax operating income. Nonoperating income increased due to the favorable effect of non-regulated power trading transactions outside the AEP Power Pool's traditional marketing area and the effect of a provision for loss related to litigation recorded in 1999. FINANCIAL CONDITION Total plant and property additions including capital leases for the first three months of 2000 were $43 million. Short-term debt increased by $5 million during the quarter. In January 2000 the Company redeemed $30 million of 7.40% pollution control bonds due 2014 at 102%. In March 2000 the Company redeemed at maturity $48 million of 6.35% first mortgage bonds. OTHER MATTERS Virginia Restructuring Under a 1999 Virginia restructuring law a transition to choice of 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, by January 1, 2004 but not later than January 1, 2005. The Virginia restructuring law provides an opportunity for recovery of just and reasonable net stranded generation costs. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may 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 Plan As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the WVPSC issued an order on January 28, 2000 approving an electricity restructuring plan for West Virginia. On March 11, 2000, the West Virginia legislature approved the restructuring plan by joint resolution. The joint resolution provides that the WVPSC cannot implement the plan until the legislature makes necessary tax law changes to preserve the revenues of the state and local governments. Until the West Virginia legislature makes the required tax law changes, the restructuring plan cannot take effect. The provisions of the proposed restructuring plan provide for customer choice of electricity supplier 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 on the starting date; functional separation of the generation, transmission and distribution businesses on the starting 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 choose to 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 deferral 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 an alternative supplier. Default rates for residential and small commercial customers are capped for four years after the starting date and then increase 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 reduced by 1% for four and a half years, beginning July 1, 2000, and then increase to 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. Potential For Write Offs In Virginia and West Virginia Jurisdictions Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated in the Virginia and West Virginia jurisdictions. The Company's accounting for generation will continue to be in accordance with SFAS 71 in the Virginia jurisdictions and will continue to be considered to be cost-based regulated for accounting purposes until the amount of capped rates and stranded cost wires charges are determined and known. The establishment of capped rates and wire charges should enable management to determine the Company's ability to recover stranded costs including regulatory assets and other transition costs, a requirement to discontinue application of SFAS 71. The application of SFAS 71 will be discontinued for the Virginia retail jurisdictional portion of the Company's generating 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 effects of implementation of the West Virginia restructuring plan are known and measurable. 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 capped 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 generating 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, 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 March 31, 2000 applicable to the Company's Virginia and West Virginia retail jurisdictional generating business is $67 million and $131 million, respectively, before related tax effects. 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 and whether the Company can reduce its cost under the capped rates. A 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 a 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 enable management to provide for recovery or should it not be possible under the West Virginia restructuring plan to recover all or a portion of the Company's generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 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 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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 where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for energy. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals 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 and/or future market prices for electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities which represent the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The Company's exposure to market risk from the trading of electricity and related financial derivative instruments, which are allocated to the Company through the AEP Power Pool, has not changed materially since December 31, 1999. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 2000 is not materially different than at December 31, 1999. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $298,306 $279,067 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,748 45,856 Purchased Power. . . . . . . . . . . . . . . . . . . . . . 79,703 55,191 Other Operation. . . . . . . . . . . . . . . . . . . . . . 45,289 45,969 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . 14,696 13,946 Depreciation . . . . . . . . . . . . . . . . . . . . . . . 24,544 23,184 Taxes Other Than Federal Income Taxes. . . . . . . . . . . 31,477 31,078 Federal Income Taxes . . . . . . . . . . . . . . . . . . . 17,725 17,796 TOTAL OPERATING EXPENSES. . . . . . . . . . . . . . 254,182 233,020 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 44,124 46,047 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . 1,684 361 INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 45,808 46,408 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . 18,337 18,990 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . 27,471 27,418 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . 533 533 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . $ 26,938 $ 26,885 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2000 1999 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . $246,584 $186,441 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . 27,471 27,418 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . . 23,650 21,999 Cumulative Preferred Stock . . . . . . . . . . . . . . . 437 437 Capital Stock Expense. . . . . . . . . . . . . . . . . . . 96 96 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . $249,872 $191,327 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,553,596 $1,544,858 Transmission . . . . . . . . . . . . . . . . . . . . 353,410 350,826 Distribution . . . . . . . . . . . . . . . . . . . . 1,049,831 1,032,550 General. . . . . . . . . . . . . . . . . . . . . . . 147,786 141,137 Construction Work in Progress. . . . . . . . . . . . 68,682 82,248 Total Electric Utility Plant . . . . . . . . 3,173,305 3,151,619 Accumulated Depreciation . . . . . . . . . . . . . . 1,231,138 1,210,994 NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,942,167 1,940,625 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 115,406 101,286 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 7,451 5,107 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 66,557 77,418 Affiliated Companies . . . . . . . . . . . . . . . 17,987 28,453 Miscellaneous. . . . . . . . . . . . . . . . . . . 5,422 8,887 Allowance for Uncollectible Accounts . . . . . . . (2,310) (3,045) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 20,284 21,484 Materials and Supplies . . . . . . . . . . . . . . . 42,807 41,696 Accrued Utility Revenues . . . . . . . . . . . . . . 40,727 48,117 Energy Trading Contracts . . . . . . . . . . . . . . 156,270 90,103 Prepayments. . . . . . . . . . . . . . . . . . . . . 43,518 37,969 TOTAL CURRENT ASSETS . . . . . . . . . . . . 398,713 356,189 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 339,968 339,103 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 55,372 72,787 TOTAL. . . . . . . . . . . . . . . . . . . $2,851,626 $2,809,990 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 24,000,000 Shares Outstanding - 16,410,426 Shares. . . . . . . . . $ 41,026 $ 41,026 Paid-in Capital. . . . . . . . . . . . . . . . . . 572,968 572,873 Retained Earnings. . . . . . . . . . . . . . . . . 249,872 246,584 Total Common Shareholder's Equity. . . . . 863,866 860,483 Cumulative Preferred Stock - Subject to Mandatory Redemption . . . . . . . . . . . . . . 25,000 25,000 Long-term Debt . . . . . . . . . . . . . . . . . . 922,690 924,545 TOTAL CAPITALIZATION . . . . . . . . . . . 1,811,556 1,810,028 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . 40,857 43,056 CURRENT LIABILITIES: Short-term Debt. . . . . . . . . . . . . . . . . . 39,475 45,500 Accounts Payable - General . . . . . . . . . . . . 24,058 28,279 Accounts Payable - Affiliated Companies. . . . . . 46,557 52,776 Taxes Accrued. . . . . . . . . . . . . . . . . . . 113,923 143,477 Interest Accrued . . . . . . . . . . . . . . . . . 22,636 13,936 Energy Trading Contracts . . . . . . . . . . . . . 142,453 87,911 Other. . . . . . . . . . . . . . . . . . . . . . . 33,027 34,375 TOTAL CURRENT LIABILITIES. . . . . . . . . 422,129 406,254 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 448,453 447,607 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . 43,869 44,716 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . 84,762 58,329 CONTINGENCIES (Note 4) TOTAL. . . . . . . . . . . . . . . . . . $2,851,626 $2,809,990 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 27,471 $ 27,418 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . 24,669 23,232 Deferred Federal Income Taxes. . . . . . . . . . . . . 5,072 (48) Deferred Investment Tax Credits. . . . . . . . . . . . (847) (868) Deferred Fuel Costs (net). . . . . . . . . . . . . . . (5,408) 836 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . 24,057 (1,756) Fuel, Materials and Supplies . . . . . . . . . . . . . 89 1,616 Accrued Utility Revenues . . . . . . . . . . . . . . . 7,390 4,484 Prepayments. . . . . . . . . . . . . . . . . . . . . . (5,549) (9,228) Accounts Payable . . . . . . . . . . . . . . . . . . . (10,440) (7,199) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . (29,554) (13,918) Interest Accrued . . . . . . . . . . . . . . . . . . . 8,700 9,939 Other (net). . . . . . . . . . . . . . . . . . . . . . . 15,474 18,912 Net Cash Flows From Operating Activities . . . . . 61,124 53,420 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . (27,022) (16,908) Other. . . . . . . . . . . . . . . . . . . . . . . . . . 330 246 Net Cash Flows Used For Investing Activities . . . (26,692) (16,662) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . (6,025) (6,800) Retirement of Long-term Debt . . . . . . . . . . . . . . (1,976) - Dividends Paid on Common Stock . . . . . . . . . . . . . (23,650) (21,999) Dividends Paid on Cumulative Preferred Stock . . . . . . (437) (437) Net Cash Flows Used For Financing Activities . . . (32,088) (29,236) Net Increase in Cash and Cash Equivalents. . . . . . . . . 2,344 7,522 Cash and Cash Equivalents at Beginning of Period . . . . . 5,107 7,206 Cash and Cash Equivalents at End of Period . . . . . . . . $ 7,451 $ 14,728 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $8,684,000 and $8,115,000 and for income taxes was $6,607,000 and $44,000 in 2000 and 1999, respectively. Noncash acquisitions under capital leases were $1,377,000 and $2,182,000 in 2000 and 1999, respectively. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. RATE MATTERS As discussed in Note 2 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the AEP System companies filed a settlement agreement for Federal Energy Regulatory Commission (FERC) approval related to an open access transmission tariff. The Company made a provision in 1999 for an agreed to refund including interest. On March 16, 2000, the FERC approved the settlement agreement filed in December 1999 resolving the issues on rehearing of a 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 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder is to be paid upon approval by the FERC. In addition, a new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers and a future rate of $1.42 kw/month was established to take effect upon the consummation of the AEP and Central and South West Corporation merger. 3. OHIO RESTRUCTURING LAW AND TRANSITION PLAN FILING As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the Act) provides for, among other things, customer choice of electricity supplier, a residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates beginning on January 1, 2001. The Act also provides for a five-year transition period to move from cost based rates to market pricing for generation services. It authorizes the Public Utilities Commission of Ohio (PUCO) to address certain major transition issues including unbundling of rates and the recovery of transition costs which include regulatory assets, generating asset impairments and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Stranded costs are generation costs that would not be recoverable in a competitive market. On March 28, 2000 the PUCO staff issued its report on the Company's transition plan filing. On May 8, 2000, a stipulation agreement between the Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties was filed with the PUCO. The key provisions of the stipulation agreement are: Recovery of regulatory assets over eight years. A shopping incentive of 2.5 mills/kwh for the first 25% of residential customers that switch suppliers. The Company is to absorb the first $20 million of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. The Company and its affiliate Ohio Power Company, will make available a fund of up to $10 million for cerain transmission charges imposed by PJM and/or Midwest ISO on generation originating in the Midwest ISO or PJM. The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire transition period. The Company's request for a $40 million gross receipts tax rider will be litigated. Hearings to address the gross receipts tax issue are scheduled for May 31, 2000. The stipulation agreement is subject to approval by the PUCO. Hearings on the stipulation are scheduled for June 7, 2000. Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated until the PUCO takes action on the transition plan as required by the Act. The establishment of rates and wires charges under the transition plan should enable the Company to determine its ability to recover stranded costs including regulatory assets, and other transition costs, a requirement to discontinue application of SFAS 71. When the transition plan and tariff schedules are approved, the application of SFAS 71 will be discontinued for the Ohio retail jurisdictional portion of the generating business. Management expects this to occur when the PUCO approves the stipulation agreement for the Company's transition plan filing. The Act requires that the PUCO issue its order to approve transition plan filings no later than October 31, 2000. Upon the discontinuance of SFAS 71 the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the tariff schedules in the transition plan approved by the PUCO and record any asset accounting 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 generating assets cannot be recovered through non-discounted generation-related revenues during the transition period and future market prices. Until the PUCO completes its regulatory process and issues an order related to the Company's transition plan, it is not possible for management to determine if any of the Company's generating assets are impaired for accounting purposes in accordance with SFAS 121. The amount of regulatory assets recorded on the books at March 31, 2000 applicable to the Ohio retail jurisdictional generating business is $302 million before related tax effects. Recovery of these regulatory assets is being sought as a part of the Company's Ohio transition plan filing. 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 PUCO approves the Company's stipulation agreement. A determination of whether the Company will experience any asset impairment loss regarding its Ohio retail jurisdictional generating assets and any loss from a possible inability to recover Ohio generation-related regulatory assets and other transition costs cannot be made until the PUCO takes action on the Company's stipulation agreement. Should the PUCO fail to fully approve the Company's stipulation agreement and its tariff schedules which include recovery of the Company's generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. 4. CONTINGENCIES COLI Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $43 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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 transition rates, stranded costs wires charges and/or future market prices for electricity. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 generally upholding Federal EPA's final rule (the NOx rule) that requires substantial reductions in nitrogen oxide (NOx) emissions in 22 eastern states, including Ohio where 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. In May 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $136 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 transition rates, stranded costs wire charges and/or future market prices for electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other The company continues to be involved in certain other matters discussed in the 1999 annual report. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2000 vs. FIRST QUARTER 1999 Net income was relatively unchanged in the first quarter as a decline in operating income was offset by an increase in nonoperating income and a reduction in interest charges. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues . . . . . . . . . . . $19.2 7 Fuel . . . . . . . . . . . . . . . . . . (5.1) (11) Purchased Power. . . . . . . . . . . . . 24.5 44 Maintenance. . . . . . . . . . . . . . . 0.8 5 Depreciation . . . . . . . . . . . . . . 1.4 6 Nonoperating Income. . . . . . . . . . . 1.3 366 Interest Charges . . . . . . . . . . . . (0.7) (3) The increases in operating revenues and purchased power expense are due to a significant increase in American Electric Power System Power Pool (AEP Power Pool) transactions. The Company as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketers. As a result of an affiliated company's major industrial customer's decision not to continue its purchased power agreement, additional power was available to the AEP Power Pool for sale on the wholesale market accounting for the increase in the Company's revenues and purchased power expense. Fuel expense decreased due to the operation of the fuel clause adjustment mechanism which resulted in a credit to fuel expense for underrecovery of emission allowance costs which were deferred as a regulatory asset. Maintenance of distribution and transmission lines accounted for the increase in maintenance expense. Additional investment in distribution plant resulted in the increase in depreciation expense. The increase in nonoperating income was due to the reversal of a provision for potential liability for clean-up of possible environmental contamination from underground storage tanks at a Company facility after the state of Ohio reviewed the matter and determined that no further corrective action would be required. The decline in interest charges was due to a decrease in outstanding long-term debt balances reflecting the partial redemption in 1999 without replacement of three different series of first mortgage bonds totaling $36 million. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $343,986 $334,113 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 47,860 41,800 Purchased Power. . . . . . . . . . . . . . . . . . . . . 85,106 62,315 Other Operation. . . . . . . . . . . . . . . . . . . . . 133,551 91,575 Maintenance. . . . . . . . . . . . . . . . . . . . . . . 55,384 31,202 Depreciation and Amortization. . . . . . . . . . . . . . 38,211 36,985 Taxes Other Than Federal Income Taxes. . . . . . . . . . 17,209 19,029 Federal Income Tax Expense (Credit). . . . . . . . . . . (18,084) 12,369 TOTAL OPERATING EXPENSES . . . . . . . . . . . . 359,237 295,275 OPERATING INCOME (LOSS). . . . . . . . . . . . . . . . . . (15,251) 38,838 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . 565 1,735 INCOME (LOSS) BEFORE INTEREST CHARGES. . . . . . . . . . . (14,686) 40,573 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 21,867 20,503 NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . . (36,553) 20,070 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 1,160 1,214 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . $(37,713) $ 18,856 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2000 1999 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $166,389 $253,154 NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . . (36,553) 20,070 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . 26,290 28,664 Cumulative Preferred Stock . . . . . . . . . . . . . . 1,125 1,182 Capital Stock Expense. . . . . . . . . . . . . . . . . . 57 32 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $102,364 $243,346 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,593,200 $2,587,288 Transmission . . . . . . . . . . . . . . . . . . . . 934,200 928,758 Distribution . . . . . . . . . . . . . . . . . . . . 826,783 818,697 General (including nuclear fuel) . . . . . . . . . . 252,702 244,981 Construction Work in Progress. . . . . . . . . . . . 212,810 190,303 Total Electric Utility Plant . . . . . . . . 4,819,695 4,770,027 Accumulated Depreciation and Amortization. . . . . . 2,222,404 2,194,397 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,597,291 2,575,630 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS . . . . . . . . . . . . . . . . 723,697 707,967 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 226,373 213,658 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 8,244 3,863 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 90,706 91,268 Affiliated Companies . . . . . . . . . . . . . . . 37,655 48,901 Miscellaneous. . . . . . . . . . . . . . . . . . . 17,516 18,644 Allowance for Uncollectible Accounts . . . . . . . (1,622) (1,848) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 23,720 27,597 Materials and Supplies . . . . . . . . . . . . . . . 83,417 84,149 Accrued Utility Revenues . . . . . . . . . . . . . . 41,992 44,428 Energy Trading Contracts . . . . . . . . . . . . . . 169,876 97,946 Prepayments. . . . . . . . . . . . . . . . . . . . . 10,205 7,631 TOTAL CURRENT ASSETS . . . . . . . . . . . . 481,709 422,579 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 598,632 624,810 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 43,072 32,052 TOTAL. . . . . . . . . . . . . . . . . . . $4,670,774 $4,576,696 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584 Paid-in Capital. . . . . . . . . . . . . . . . . . . 732,802 732,739 Retained Earnings. . . . . . . . . . . . . . . . . . 102,364 166,389 Total Common Shareholder's Equity. . . . . . 891,750 955,712 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 8,989 9,248 Subject to Mandatory Redemption. . . . . . . . . . 64,945 64,945 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,129,334 1,126,326 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,095,018 2,156,231 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning. . . . . . . . . . . . . . . 515,587 501,185 Other. . . . . . . . . . . . . . . . . . . . . . . . 198,129 242,522 TOTAL OTHER NONCURRENT LIABILITIES . . . . . 713,716 743,707 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 150,000 198,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 348,393 224,262 Accounts Payable - General . . . . . . . . . . . . . 51,533 78,784 Accounts Payable - Affiliated Companies. . . . . . . 39,437 31,118 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 52,764 48,970 Interest Accrued . . . . . . . . . . . . . . . . . . 17,101 13,955 Obligations Under Capital Leases . . . . . . . . . . 47,081 11,072 Energy Trading Contracts . . . . . . . . . . . . . . 154,856 95,564 Other. . . . . . . . . . . . . . . . . . . . . . . . 107,891 91,684 TOTAL CURRENT LIABILITIES. . . . . . . . . . 969,056 793,409 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 609,435 622,157 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 119,740 121,627 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 84,079 85,005 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 79,730 54,560 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $4,670,774 $4,576,696 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING ACTIVITIES: Net Income (Loss). . . . . . . . . . . . . . . . . . . . . $(36,553) $ 20,070 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 39,191 37,995 Amortization of Incremental Nuclear Refueling Outage Expenses (net). . . . . . . . . . . . 2,035 2,347 Unrecovered Fuel and Purchased Power Costs . . . . . . . 9,375 (52,664) Amortization (Deferral) of Nuclear Outage Costs (net). . 10,000 (30,000) Deferred Federal Income Taxes. . . . . . . . . . . . . . (7,801) 5,365 Deferred Investment Tax Credits. . . . . . . . . . . . . (1,887) (1,898) Deferred Property Taxes. . . . . . . . . . . . . . . . . (10,241) (9,325) Rate Refunds . . . . . . . . . . . . . . . . . . . . . . (3,740) - Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 12,710 (1,247) Fuel, Materials and Supplies . . . . . . . . . . . . . . 4,609 (15,154) Accrued Utility Revenues . . . . . . . . . . . . . . . . 2,436 9,094 Accounts Payable . . . . . . . . . . . . . . . . . . . . (18,932) 5,225 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 3,794 14,541 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464 Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 8,296 55,000 Other Current Liabilities. . . . . . . . . . . . . . . . (16,095) 14,308 Other (net). . . . . . . . . . . . . . . . . . . . . . . . (9,787) (7,492) Net Cash Flows From Operating Activities . . . . . . 5,874 64,629 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (51,435) (30,114) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 250 903 Net Cash Flows Used For Investing Activities . . . . (51,185) (29,211) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . . 124,131 1,595 Retirement of Long-term Debt . . . . . . . . . . . . . . . (48,000) - Retirement of Cumulative Preferred Stock . . . . . . . . . (149) (5) Dividends Paid on Common Stock . . . . . . . . . . . . . . (26,290) (28,664) Dividends Paid on Cumulative Preferred Stock . . . . . . . - (1,182) Net Cash Flows From (Used For) Financing Activities. 49,692 (28,256) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 4,381 7,162 Cash and Cash Equivalents at Beginning of Period . . . . . . 3,863 5,424 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,244 $ 12,586 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $17,965,000 and $18,527,000 in 2000 and 1999, respectively and for income taxes was $(8,966,000)in 2000. Noncash acquisitions under capital leases were $1,184,000 and $3,783,000 in 2000 and 1999, respectively. See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In March 2000 the Company redeemed at maturity $48 million of its 6.40% series of first mortgage bonds. 3. RATE MATTERS As discussed in Note 3 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the AEP System companies filed a settlement agreement for Federal Energy Regulatory Commission (FERC) approval related to an open access transmission tariff. The Company made a provision in 1999 for an agreed to refund including interest. On March 16, 2000, the FERC approved the settlement agreement filed in December 1999 resolving the issues on rehearing of a 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 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder is to be paid upon approval by the FERC. In addition, a new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers and a future rate of $1.42 kw/month was established to take effect upon the consummation of the AEP and Central and South West Corporation merger. 4. COOK NUCLEAR PLANT SHUTDOWN As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. In February 2000, the Company was notified by the NRC that the Confirmatory Action Letter had been closed. Closing of the Confirmatory Action Letter is one of the key approvals needed to restart the nuclear units. The Confirmatory Action Letter was issued in September 1997 requiring the Company to address certain issues identified in the letter. Progress to restart the units continues. Refueling of Unit 2, the first unit scheduled to restart, was completed on April 14, 2000. The NRC's final Unit 2 pre-restart inspection began on May 8, 2000, which coincided with the reactor heat-up of Unit 2 and the return to operational service of common plant systems. When testing and other work required for restart are complete, the Company will seek concurrence from the NRC to return Unit 2 to service. Refueling and maintenance work to restart Unit 1 will be performed after Unit 2 is returned to service. Any issues or difficulties encountered in testing of equipment as part of the restart process could delay the restart of the units. Expenditures to restart the Cook units are estimated to total approximately $574 million. Through March 31, 2000, $453 million has been spent. In 2000 $80 million of restart costs were recorded in other operation and maintenance expense, including amortization of $10 million of restart costs previously deferred in accordance with settlement agreements in the Indiana and Michigan retail jurisdictions. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations and cash flows until the units are restarted. The amortization of restart costs deferred under Indiana and Michigan retail jurisdiction settlement agreements will adversely effect results of operations and possibly financial condition through 2003 when the amortization period ends. Management believes that the Cook units will be successfully returned to service. However, if for some unknown reason the units are not returned to service or their return is delayed significantly it would have an even greater adverse effect on future results of operations, cash flows and financial condition. 5. CONTINGENCIES Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $66 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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 where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for energy. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $202 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 and/or future market prices for electricity if generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in other matters discussed in its 1999 Annual Report. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 2000 vs. FIRST QUARTER 1999 RESULTS OF OPERATIONS The Company reported a loss of $37 million for the first quarter of 2000 compared with net income of $20 million in 1999. Expenditures to prepare the Company's two unit Donald C. Cook Nuclear Plant (Cook Plant) for restart following an extended outage are the primary reasons for the loss. An extended outage of the Cook Plant began in September 1997 when both nuclear generating units were shut down because of questions regarding the operability of certain safety systems. In accordance with a settlement agreement in Indiana which resolved all Indiana jurisdictional rate-related issues applicable to the Cook Plant's extended outage certain restart expenses were deferred in the first quarter of 1999. A settlement to resolve all rate-related issues in the Michigan jurisdiction was approved in December 1999 retroactive to January 1, 1999. These deferrals are being amortized on a straight-line basis through December 31, 2003. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues. . . . . . . . . . . . $ 9.9 3 Fuel. . . . . . . . . . . . . . . . . . . 6.1 14 Purchased Power . . . . . . . . . . . . . 22.8 37 Other Operation . . . . . . . . . . . . . 42.0 46 Maintenance . . . . . . . . . . . . . . . 24.2 78 Federal Income Tax. . . . . . . . . . . . (30.5) N.M. N.M. = Not meaningful The increase in operating revenues resulted from increased sales to the American Electric Power System Power Pool (AEP Power Pool) and increased sales to neighboring utility systems and power marketers by the AEP Power Pool on behalf of the Company offset in part by the amortization of previously accrued fuel-related revenues. As a member of the AEP Power Pool, the Company shares in the revenues and costs of the AEP Power Pool's wholesale sales. AEP Power Pool members are 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. As a result of the Company's obligation to purchase power from an affiliated company, the Company was required to purchase more energy due to the expiration of that affiliate's unit power agreement to supply power to an unaffiliated utility. The Company, therefore, was able to deliver additional power to the AEP Power Pool, accounting for the increase in sales to the AEP Power Pool. The increase in operating revenues from sales by the AEP Power Pool is due to the significant increase in AEP Power Pool transactions, which also contributed to the increase in purchased power. As a result of an affiliated company's major industrial customer's decision not to extend its purchase power agreement, additional power was delivered to the AEP Power Pool allowing the Power Pool to increase its wholesale sales. The decrease in revenues caused by the amortization of previously accrued fuel-related revenues resulted from the amortization in the current period of revenues accrued through 1999 for the increased cost of replacement power and increased fossil fuel usage necessitated by the extended outage of the Cook Nuclear Plant. The accrual of revenues was authorized under the terms of approved settlement agreements for the Indiana and Michigan jurisdictions. Fuel expense increased due to a 13.9% rise in generation reflecting the higher availability of the Company's coal-fired generating units due to shorter planned maintenance outages. The increase in other operation and maintenance expense was primarily caused by the continuing work to restart the Cook Plant, combined with the amortization of deferred expenditures under the terms of the approved settlement agreements in Indiana and Michigan. The decrease in federal income tax expense attributable to operations was primarily due to a decrease in pre-tax operating income. FINANCIAL CONDITION Total plant and property additions including capital leases for the period were $53 million. During the first three months of 2000 short-term debt outstanding increased by $124 million. In March the Company redeemed at maturity $48 million of 6.40% first mortgage bonds. OTHER MATTERS Cook Nuclear Plant Shutdown As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. In February 2000, the Company was notified by the NRC that the Confirmatory Action Letter had been closed. Closing of the Confirmatory Action Letter is one of the key approvals needed to restart the nuclear units. The Confirmatory Action Letter was issued in September 1997 requiring the Company to address certain issues identified in the letter. Progress to restart the units continues. Refueling of Unit 2, the first unit scheduled to restart, was completed on April 14, 2000. The NRC's final Unit 2 pre-restart inspection began on May 8, 2000, which coincided with the reactor heat-up of Unit 2 and the return to operational service of common plant systems. When testing and other work required for restart are complete, the Company will seek concurrence from the NRC to return Unit 2 to service. Refueling and maintenance work to restart Unit 1 will be performed after Unit 2 is returned to service. Any issues or difficulties encountered in testing of equipment as part of the restart process could delay the restart of the units. Expenditures to restart the Cook units are estimated to total approximately $574 million. Through March 31, 2000, $453 million has been spent. In 2000 $80 million of restart costs were recorded in other operation and maintenance expense, including amortization of $10 million of restart costs previously deferred in accordance with settlement agreements in the Indiana and Michigan retail jurisdictions. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations and cash flows until the units are restarted. The amortization of restart costs deferred under Indiana and Michigan retail jurisdiction settlement agreements will adversely effect results of operations and possibly financial condition through 2003 when the amortization period ends. Management believes that the Cook units will be successfully returned to service. However, if for some unknown reason the units are not returned to service or their return is delayed significantly it would have an even greater adverse effect on future results of operations, cash flows and financial condition. Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $66 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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 where states are deregulating generation, unbundled transition period generation rates, stranded cost wires charges and future market prices for energy. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $202 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 and/or future market prices for electricity if generation is deregulated, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities which represent the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The Company's exposure to market risk from the trading of electricity and related financial derivative instruments, which are allocated to the Company through the AEP Power Pool, has not changed materially since December 31, 1999. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 2000 is not materially different than at December 31, 1999. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . $97,204 $90,741 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . 16,802 19,691 Purchased Power. . . . . . . . . . . . . . . . . . 33,482 24,427 Other Operation. . . . . . . . . . . . . . . . . . 10,384 12,351 Maintenance. . . . . . . . . . . . . . . . . . . . 6,367 4,791 Depreciation and Amortization. . . . . . . . . . . 7,603 7,190 Taxes Other Than Federal Income Taxes. . . . . . . 2,834 2,534 Federal Income Taxes . . . . . . . . . . . . . . . 4,175 4,397 TOTAL OPERATING EXPENSES . . . . . . . . . 81,647 75,381 OPERATING INCOME . . . . . . . . . . . . . . . . . . 15,557 15,360 NONOPERATING LOSS. . . . . . . . . . . . . . . . . . (46) (114) INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . 15,511 15,246 INTEREST CHARGES . . . . . . . . . . . . . . . . . . 7,459 7,037 NET INCOME . . . . . . . . . . . . . . . . . . . . . $ 8,052 $ 8,209 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2000 1999 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . $67,110 $71,452 NET INCOME . . . . . . . . . . . . . . . . . . . . . 8,052 8,209 CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . 7,590 7,443 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . $67,572 $72,218 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . $ 269,012 $ 268,618 Transmission . . . . . . . . . . . . . . . . 356,402 355,442 Distribution . . . . . . . . . . . . . . . . 375,974 372,752 General. . . . . . . . . . . . . . . . . . . 67,866 67,608 Construction Work in Progress. . . . . . . . 13,837 14,628 Total Electric Utility Plant . . . . 1,083,091 1,079,048 Accumulated Depreciation and Amortization. . 344,027 340,008 NET ELECTRIC UTILITY PLANT . . . . . 739,064 739,040 OTHER PROPERTY AND INVESTMENTS . . . . . . . . 25,692 20,416 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . 1,384 674 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . 20,287 18,952 Affiliated Companies . . . . . . . . . . . 14,335 15,223 Miscellaneous. . . . . . . . . . . . . . . 7,979 8,343 Allowance for Uncollectible Accounts . . . (615) (637) Fuel . . . . . . . . . . . . . . . . . . . . 11,954 10,441 Materials and Supplies . . . . . . . . . . . 17,397 18,113 Accrued Utility Revenues . . . . . . . . . . 10,463 13,737 Energy Trading Contracts . . . . . . . . . . 64,006 33,919 Prepayments. . . . . . . . . . . . . . . . . 947 1,450 TOTAL CURRENT ASSETS . . . . . . . . 148,137 120,215 REGULATORY ASSETS. . . . . . . . . . . . . . . 98,289 96,296 DEFERRED CHARGES . . . . . . . . . . . . . . . 9,136 10,671 TOTAL. . . . . . . . . . . . . . . $1,020,318 $ 986,638 See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $50: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares . . . . . . $ 50,450 $ 50,450 Paid-in Capital. . . . . . . . . . . . . . . 158,750 158,750 Retained Earnings. . . . . . . . . . . . . . 67,572 67,110 Total Common Shareholder's Equity. . 276,772 276,310 Long-term Debt . . . . . . . . . . . . . . . 260,852 260,782 TOTAL CAPITALIZATION . . . . . . . . 537,624 537,092 OTHER NONCURRENT LIABILITIES . . . . . . . . . 22,456 23,797 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . 105,000 105,000 Short-term Debt. . . . . . . . . . . . . . . 37,600 39,665 Accounts Payable - General . . . . . . . . . 6,666 9,923 Accounts Payable - Affiliated Companies. . . 20,666 19,743 Customer Deposits. . . . . . . . . . . . . . 4,168 4,143 Taxes Accrued. . . . . . . . . . . . . . . . 10,573 9,860 Interest Accrued . . . . . . . . . . . . . . 7,199 4,843 Energy Trading Contracts . . . . . . . . . . 58,347 33,094 Other. . . . . . . . . . . . . . . . . . . . 10,684 12,020 TOTAL CURRENT LIABILITIES. . . . . . 260,903 238,291 DEFERRED INCOME TAXES. . . . . . . . . . . . . 166,931 165,007 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . 12,610 12,908 DEFERRED CREDITS . . . . . . . . . . . . . . . 19,794 9,543 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . $1,020,318 $986,638 See Notes to Financial Statements.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . $ 8,052 $ 8,209 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . 7,605 7,192 Deferred Federal Income Taxes. . . . . . . . . . 1,961 (254) Deferred Investment Tax Credits. . . . . . . . . (298) (300) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . (105) 4,039 Fuel, Materials and Supplies . . . . . . . . . . (797) (1,893) Accrued Utility Revenues . . . . . . . . . . . . 3,274 (13) Accounts Payable . . . . . . . . . . . . . . . . (2,334) (1,542) Taxes Accrued. . . . . . . . . . . . . . . . . . 713 5,131 Interest Accrued . . . . . . . . . . . . . . . . 2,356 2,554 Other (net). . . . . . . . . . . . . . . . . . . . (2,489) 1,519 Net Cash Flows From Operating Activities . . 17,938 24,642 INVESTING ACTIVITIES - Construction Expenditures . . (7,573) (6,483) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . (2,065) (8,400) Dividends Paid . . . . . . . . . . . . . . . . . . (7,590) (7,443) Net Cash Flows Used For Financing Activities . . . . . . . . . . . (9,655) (15,843) Net Increase in Cash and Cash Equivalents. . . . . . 710 2,316 Cash and Cash Equivalents at Beginning of Period . . 674 1,935 Cash and Cash Equivalents at End of Period . . . . . $ 1,384 $ 4,251 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $5,029,000 and $4,374,000 in 2000 and 1999, respectively and for income taxes was $2,001,000 in 2000. Noncash acquisitions under capital leases were $374,000 and $568,000 in 2000 and 1999, respectively. See Notes to Financial Statements. KENTUCKY POWER COMPANY NOTES TO FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. RATE MATTERS As discussed in Note 3 of the Notes to Financial Statements of the 1999 Annual Report, the AEP System companies filed a settlement agreement for Federal Energy Regulatory Commission (FERC) approval related to an open access transmission tariff. The Company made a provision in 1999 for an agreed to refund including interest. On March 16, 2000, the FERC approved the settlement agreement filed in December 1999 resolving the issues on rehearing of a 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 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder is to be paid upon approval by the FERC. In addition, a new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers and a future rate of $1.42 kw/month was established to take effect upon the consummation of the AEP and Central and South West Corporation merger. 3. CONTINGENCIES COLI Litigation As discussed in Note 4 of the Notes to Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1992 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $8 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1992 through 1998 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 balance sheet in other property and investments pending the resolution of this matter. The Company is seeking refund of all amounts paid plus interest. In order to resolve this issue, AEP Co., Inc. filed suit against the United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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. Federal EPA Complaint and Notice of Violation As discussed in Note 4 of the Notes to Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges certain AEP System companies 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by AEP System companies alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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. NOx Reductions As discussed in Note 6 of the Notes to Financial Statements of the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 generally upholding Federal EPA's final rule (the NOx rule) that requires substantial reductions in nitrogen oxide (NOx) emissions in 22 eastern states, including Kentucky where the Company's generating plant is located. A number of utilities, including the Company, had filed petitions seeking a review of the final rule in the Appeals Court. In May 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $106 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, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1999 Annual Report. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2000 vs. FIRST QUARTER 1999 Although revenues rose 7%, net income decreased in the first quarter primarily as a result of increased interest expense. Income statement line items which changed significantly were: Increase(Decrease) (in millions) % Operating Revenues. . . . . . . . . . . $ 6.5 7 Fuel. . . . . . . . . . . . . . . . . . (2.9) (15) Purchased Power . . . . . . . . . . . . 9.1 37 Other Operation . . . . . . . . . . . . (2.0) (16) Maintenance . . . . . . . . . . . . . . 1.6 33 Depreciation. . . . . . . . . . . . . . 0.4 6 Net Interest Charges. . . . . . . . . . 0.4 6 The increases in operating revenues and purchased power expense are due to a significant increase in American Electric Power System Power Pool (AEP Power Pool) wholesale electricity sales. The Company as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale electricity marketing to neighboring utility system and power marketers. As a result of an affiliated company's major industrial customer's decision not to continue its purchased power agreement, additional power was available for AEP Power Pool sales. Purchased power also increased due to an increase in the availability of the Rockport Plant. Under a non-AEP Power Pool purchase power agreement with an affiliate, the Company purchases 15% of the available power of the Rockport Plant. Rockport Plant generated 16% more kwh in 2000 than 1999. Fuel expense decreased due to an outage of the Company's Big Sandy Plant Unit 2 which began in March 2000. The Company as a party to the AEP System's Transmission Agreement shares the costs associated with the ownership of the AEP System's extra-high voltage transmission system and certain facilities at lower voltages. Like the AEP Power Pool, the sharing is based upon each company's member load ratio (MLR) and applicable investment in transmission facilities. The decrease in other operation expense was primarily due to an increase in transmission equalization credits as a result of an increase in the Company's MLR and increased investment in transmission facilities. Member load ratio is calculated monthly on the basis of each company's maximum peak demand in relation to the sum of the maximum peak demands of all five signatories to the agreement during the preceding 12 months. The Big Sandy Plant began an outage in March 2000 for the repair and maintenance of Unit 2. Unit 2 returned to service in April 2000. The increase in transmission plant investment caused the increase in depreciation expense. Interest charges increased due to an increase in the average outstanding short-term debt balances and an increase in average short-term debt interest rates reflecting the Company's short-term cash demands and short-term debt interest market conditions.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . $545,411 $518,221 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215,248 189,163 Purchased Power. . . . . . . . . . . . . . . . . . . . . . . 35,302 21,273 Other Operation. . . . . . . . . . . . . . . . . . . . . . . 84,452 85,061 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 28,030 25,490 Depreciation and Amortization. . . . . . . . . . . . . . . . 38,489 36,785 Taxes Other Than Federal Income Taxes. . . . . . . . . . . . 43,732 43,853 Federal Income Taxes . . . . . . . . . . . . . . . . . . . . 35,045 37,640 TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . 480,298 439,265 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . 65,113 78,956 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . 2,900 2,000 INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . 68,013 80,956 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . 21,797 20,135 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . 46,216 60,821 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . . 321 367 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . $ 45,895 $ 60,454 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2000 1999 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . $587,424 $587,500 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . 46,216 60,821 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . . . 37,703 57,703 Cumulative Preferred Stock . . . . . . . . . . . . . . . . 317 367 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . $595,620 $590,251 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,722,614 $2,713,421 Transmission . . . . . . . . . . . . . . . . . . . . 860,900 857,420 Distribution . . . . . . . . . . . . . . . . . . . . 1,010,110 999,679 General (including mining assets). . . . . . . . . . 715,814 713,882 Construction Work in Progress. . . . . . . . . . . . 114,260 116,515 Total Electric Utility Plant . . . . . . . . 5,423,698 5,400,917 Accumulated Depreciation and Amortization. . . . . . 2,668,873 2,621,711 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,754,825 2,779,206 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 277,790 253,668 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 226,877 157,138 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 235,875 246,310 Affiliated Companies . . . . . . . . . . . . . . . 158,457 89,215 Miscellaneous. . . . . . . . . . . . . . . . . . . 27,395 22,055 Allowance for Uncollectible Accounts . . . . . . . (2,100) (2,223) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 131,478 146,317 Materials and Supplies . . . . . . . . . . . . . . . 97,092 95,967 Accrued Utility Revenues . . . . . . . . . . . . . . 33,056 45,575 Energy Trading Contracts . . . . . . . . . . . . . . 234,374 134,567 Prepayments and Other. . . . . . . . . . . . . . . . 43,413 38,472 TOTAL CURRENT ASSETS . . . . . . . . . . . . 1,185,917 973,393 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 584,216 577,090 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 80,289 93,852 TOTAL. . . . . . . . . . . . . . . . . . . $4,883,037 $4,677,209 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 2000 1999 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 40,000,000 Shares Outstanding - 27,952,473 Shares. . . . . . . . . . $ 321,201 $ 321,201 Paid-in Capital. . . . . . . . . . . . . . . . . . . 462,402 462,376 Retained Earnings. . . . . . . . . . . . . . . . . . 595,620 587,424 Total Common Shareholder's Equity. . . . . . 1,379,223 1,371,001 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 16,865 16,937 Subject to Mandatory Redemption. . . . . . . . . . 8,850 8,850 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,130,492 1,139,834 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,535,430 2,536,622 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 431,672 414,837 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 11,881 11,677 Short-term Debt. . . . . . . . . . . . . . . . . . . 241,424 194,918 Accounts Payable - General . . . . . . . . . . . . . 183,173 180,383 Accounts Payable - Affiliated Companies. . . . . . . 81,424 64,599 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 160,788 179,112 Interest Accrued . . . . . . . . . . . . . . . . . . 23,412 16,863 Obligations Under Capital Leases . . . . . . . . . . 34,166 34,284 Energy Trading Contracts . . . . . . . . . . . . . . 213,651 131,844 Other. . . . . . . . . . . . . . . . . . . . . . . . 110,299 96,445 TOTAL CURRENT LIABILITIES. . . . . . . . . . 1,060,218 910,125 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 666,369 676,460 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 35,021 35,838 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 154,327 103,327 CONTINGENCIES (Note 4) TOTAL. . . . . . . . . . . . . . . . . . . $4,883,037 $4,677,209 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 2000 1999 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 46,216 $ 60,821 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . 60,294 45,129 Deferred Federal Income Taxes. . . . . . . . . . . . . (14,957) (3,601) Deferred Fuel Costs (net). . . . . . . . . . . . . . . (3,961) (7,227) Amortization of Deferred Property Taxes. . . . . . . . 19,666 19,426 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . (64,270) (107,053) Fuel, Materials and Supplies . . . . . . . . . . . . . 13,714 (20,409) Accrued Utility Revenues . . . . . . . . . . . . . . . 12,519 4,082 Prepayments and Other. . . . . . . . . . . . . . . . . (4,941) (13,013) Accounts Payable . . . . . . . . . . . . . . . . . . . 19,615 6,374 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . (18,324) 3,019 Interest Accrued . . . . . . . . . . . . . . . . . . . 6,549 9,025 Operating Reserves . . . . . . . . . . . . . . . . . . . 22,694 17,519 Other (net). . . . . . . . . . . . . . . . . . . . . . . 16,082 24,364 Net Cash Flows From Operating Activities . . . . . 110,896 38,456 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . (40,684) (41,888) Proceeds from Sale of Property and Other . . . . . . . . - 629 Net Cash Flows Used For Investing Activities . . . (40,684) (41,259) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . 46,506 96,695 Retirement of Cumulative Preferred Stock . . . . . . . . (46) (10) Retirement of Long-term Debt . . . . . . . . . . . . . . (8,883) (10,679) Dividends Paid on Common Stock . . . . . . . . . . . . . (37,733) (57,703) Dividends Paid on Cumulative Preferred Stock . . . . . . (317) (367) Net Cash Flows From (Used For) Financing Activities . . . . . . . . . . . . . . (473) 27,936 Net Increase in Cash and Cash Equivalents. . . . . . . . . 69,739 25,133 Cash and Cash Equivalents at Beginning of Period . . . . . 157,138 89,652 Cash and Cash Equivalents at End of Period . . . . . . . . $ 226,877 $ 114,785 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $15,043,000 and $10,562,000 and for income taxes was $20,652,000 and $2,219,000 in 2000 and 1999, respectively. Noncash acquisitions under capital leases were $2,791,000 and $5,634,000 in 2000 and 1999, respectively. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2000 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1999 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. RATE MATTERS As discussed in Note 2 of the Notes to Consolidated Financial Statements of the 1999 Annual Report, the AEP System companies filed a settlement agreement for Federal Energy Regulatory Commission (FERC) approval related to an open access transmission tariff. The Company made a provision in 1999 for an agreed to refund including interest. On March 16, 2000, the FERC approved the settlement agreement filed in December 1999 resolving the issues on rehearing of a 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 2000 pursuant to a FERC order granting AEP's request to make interim refunds. The remainder is to be paid upon approval by the FERC. In addition, a new lower rate of $1.55 kw/month was made effective January 1, 2000, for all transmission service customers and a future rate of $1.42 kw/month was established to take effect upon the consummation of the AEP and Central and South West Corporation merger. 3. OHIO RESTRUCTURING LAW AND TRANSITION PLAN FILING As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the Act) provides for, among other things, customer choice of electricity supplier, a residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates beginning on January 1, 2001. The Act also provides for a five-year transition period to move from cost based rates to market pricing for generation services. It authorizes the Public Utilities Commission of Ohio (PUCO) to address certain major transition issues including unbundling of rates and the recovery of transition costs which include regulatory assets, generating asset impairments and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Stranded costs are generation costs that would not be recoverable in a competitive market. On March 28, 2000 the PUCO staff issued its report on the Company's transition plan filing. On May 8, 2000, a stipulation agreement between the Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties was filed with the PUCO. The key provisions of the stipulation agreement are: Recovery of regulatory assets over seven years. No shopping incentive for the Company's customers. The Company is to absorb first $20 million of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. The Company and its affiliate Columbus Southern Power Company, will make available a fund of up to $10 million for certain transmission charges imposed by PJM and/or Midwest ISO on generation originating in the Midwest ISO or PJM. The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire transition period. The Company's request for a $50 million gross receipts tax rider will be litigated. Hearings to address the gross receipts tax issue are scheduled for May 31, 2000. The stipulation agreement is subject to approval by the PUCO. Hearings on the stipulation are scheduled for June 7, 2000. Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated until the PUCO takes action on the transition plan as required by the Act. The establishment of rates and wires charges under the transition plan should enable the Company to determine its ability to recover stranded costs including regulatory assets, and other transition costs, a requirement to discontinue application of SFAS 71. When the transition plan and tariff schedules are approved, the application of SFAS 71 will be discontinued for the Ohio retail jurisdictional portion of the generating business. Management expects this to occur when the PUCO approves the stipulation agreement for the Company's transition plan filing. The Act requires that the PUCO issue its order to approve transition plan filings no later than October 31, 2000. Upon the discontinuance of SFAS 71 the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the tariff schedules in the transition plan approved by the PUCO and record any asset accounting 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 generating assets cannot be recovered through non-discounted generation-related revenues during the transition period and future market prices. Until the PUCO completes its regulatory process and issues an order related to the Company's transition plan, it is not possible for management to determine if any of the Company's generating assets are impaired for accounting purposes in accordance with SFAS 121. The amount of regulatory assets recorded on the books at March 31, 2000 applicable to the Ohio retail jurisdictional generating business is $422 million before related tax effects. Due to the planned closing of the Company's affiliated mines, including the Meigs mine, projected generation-related regulatory assets as of December 31, 2000 (the date that recoverable generation-related regulatory assets are measured under the Ohio law) allocable to the Ohio retail jurisdiction are estimated to exceed $520 million, before income tax effects. Recovery of these regulatory assets is being sought as a part of the Company's Ohio transition plan filing. 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 PUCO approves the Company's stipulation agreement. A determination of whether the Company will experience any asset impairment loss regarding its Ohio retail jurisdictional generating assets and any loss from a possible inability to recover Ohio generation-related regulatory assets and other transition costs cannot be made until the PUCO takes action on the Company's stipulation agreement. Should the PUCO fail to fully approve the Company's stipulation agreement and its tariff schedules which include recovery of the Company's generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. 4. CONTINGENCIES Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $118 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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, stranded cost wires charges and future market prices for energy. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $624 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 and/or future market prices for electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in the 1999 Annual Report. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 2000 vs. FIRST QUARTER 1999 RESULTS OF OPERATIONS Net income decreased $15 million or 24% due mainly to an increase in fuel and purchased power expense. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues . . . . . . . . . . $27.2 5 Fuel . . . . . . . . . . . . . . . . . 26.1 14 Purchased Power. . . . . . . . . . . . 14.0 66 Maintenance. . . . . . . . . . . . . . 2.5 10 Federal Income Taxes . . . . . . . . . (2.5) (7) The increase in operating revenues resulted from increased sales to the American Electric Power System Power Pool (AEP Power Pool) and the Company's share of revenues from increased sales to neighboring utility systems and power marketers by the AEP Power Pool. As a member of the AEP Power Pool, the Company shares in the revenues and costs of the AEP Power Pool's wholesale sales. AEP Power Pool members are 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. As a result of a major industrial customer's decision not to continue its purchased power agreement with the Company, additional power was delivered to the AEP Power Pool, accounting for the increase in sales to the AEP Power Pool. Fuel expense increased due to an increase in the average cost of fuel consumed reflecting shutdown costs included in the cost of coal delivered from affiliated mining operations. The significant increase in purchased power expense resulted from the shared costs of AEP Power Pool purchases and power purchased from non-associated companies for sale in the wholesale market. Additional boiler repairs accounted for the increase in maintenance expense. The decrease in federal income tax expense attributable to operations was primarily due to a decrease in pre-tax operating income offset in part by changes in certain book/tax differences accounted for on a flow-through basis. FINANCIAL CONDITION Total plant and property additions including capital leases for the current period were $43 million. Short-term debt increased by $47 million from the beginning of 2000. OTHER MATTERS Ohio Restructuring Law and Transition Plan Filing As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the Act) provides for, among other things, customer choice of electricity supplier, a residential rate reduction of 5% for the generation portion of rates and a freezing of generation rates including fuel rates beginning on January 1, 2001. The Act also provides for a five-year transition period to move from cost based rates to market pricing for generation services. It authorizes the Public Utilities Commission of Ohio (PUCO) to address certain major transition issues including unbundling of rates and the recovery of transition costs which include regulatory assets, generating asset impairments and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Stranded costs are generation costs that would not be recoverable in a competitive market. On March 28, 2000 the PUCO staff issued its report on the Company's transition plan filing. On May 8, 2000, a stipulation agreement between the Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties was filed with the PUCO. The key provisions of the stipulation agreement are: Recovery of regulatory assets over seven years. No shopping incentive for the Company's customers. The Company is to absorb first $20 million of consumer education, implementation and transition plan filing costs with deferral of the remaining costs, plus a carrying charge, as a regulatory asset for recovery in future distribution rates. The Company and its affiliate Columbus Southern Power Company, will make available a fund of up to $10 million for certain transmission charges imposed by PJM and/or Midwest ISO on generation originating in the Midwest ISO or PJM. The statutory 5% reduction in the generation component of residential tariffs will remain in effect for the entire transition period. The Company's request for a $50 million gross receipts tax rider will be litigated. Hearings to address the gross receipts tax issue are scheduled for May 31, 2000. The stipulation agreement is subject to approval by the PUCO. Hearings on the stipulation are scheduled for June 7, 2000. Management has concluded that as of March 31, 2000 the requirements to apply Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met since the Company's rates for generation will continue to be cost-based regulated until the PUCO takes action on the transition plan as required by the Act. The establishment of rates and wires charges under the transition plan should enable the Company to determine its ability to recover stranded costs including regulatory assets, and other transition costs, a requirement to discontinue application of SFAS 71. When the transition plan and tariff schedules are approved, the application of SFAS 71 will be discontinued for the Ohio retail jurisdictional portion of the generating business. Management expects this to occur when the PUCO approves the stipulation agreement for the Company's transition plan filing. The Act requires that the PUCO issue its order to approve transition plan filings no later than October 31, 2000. Upon the discontinuance of SFAS 71 the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the tariff schedules in the transition plan approved by the PUCO and record any asset accounting 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 generating assets cannot be recovered through non-discounted generation-related revenues during the transition period and future market prices. Until the PUCO completes its regulatory process and issues an order related to the Company's transition plan, it is not possible for management to determine if any of the Company's generating assets are impaired for accounting purposes in accordance with SFAS 121. The amount of regulatory assets recorded on the books at March 31, 2000 applicable to the Ohio retail jurisdictional generating business is $422 million before related tax effects. Due to the planned closing of the Company's affiliated mines, including the Meigs mine, projected generation-related regulatory assets as of December 31, 2000 (the date that recoverable generation-related regulatory assets are measured under the Ohio law) allocable to the Ohio retail jurisdiction are estimated to exceed $520 million, before income tax effects. Recovery of these regulatory assets is being sought as a part of the Company's Ohio transition plan filing. 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 PUCO approves the Company's stipulation agreement. A determination of whether the Company will experience any asset impairment loss regarding its Ohio retail jurisdictional generating assets and any loss from a possible inability to recover Ohio generation-related regulatory assets and other transition costs cannot be made until the PUCO takes action on the Company's stipulation agreement. Should the PUCO fail to fully approve the Company's stipulation agreement and its tariff schedules which include recovery of the Company's generation-related regulatory assets, stranded costs and other transition costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Litigation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991 through 1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of the COLI interest deductions through March 31, 2000 would reduce earnings by approximately $118 million (including interest). The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991 through 1998 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 sheet 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 United States in the U.S. District Court for the Southern District of Ohio in 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 deduction 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, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the Company has been involved in litigation regarding generating plant emissions. Notices of Violation were issued and a complaint was filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S. District Court for the Southern District of Ohio that alleges the Company and certain other affiliated utilities 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. The complaint was amended in March 2000 to add allegations for certain generating units previously named in the complaint and to include additional AEP System generating units previously named only in the Notices of Violation in the complaint. 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. Federal EPA also issued Notices of Violation, complaints or administrative orders to eight unaffiliated utilities. A number of northeastern and eastern states were granted leave to intervene in the Federal EPA's action against the Company under the Clean Air Act. A lawsuit against power plants owned by the Company alleging similar violations to those in the Federal EPA complaint and Notices of Violation was filed by a number of special interest groups and 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. On May 10, 2000, the Company filed motions to dismiss all or portions of the complaints. 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, stranded cost wires charges and future market prices for energy. NOx Reductions As discussed in Note 6 of the Notes to Consolidated Financial Statements in the 1999 Annual Report, the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court) issued a decision on March 3, 2000 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. In May 1999, the Appeals Court 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 20, 2000, the AEP System companies and other industry petitioners filed for rehearing of the March 3, 2000 decision including a rehearing by the entire Appeals Court. Preliminary estimates indicate that compliance with the NOx rule upheld by the Appeals Court could result in required capital expenditures of approximately $624 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 and/or future market prices for electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities which represent the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates from changes in electricity commodity prices and interest rates. The Company's exposure to market risk from the trading of electricity and related financial derivative instruments, which are allocated to the Company through the American Electric Power System Power Pool, has not changed materially since December 31, 1999. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 2000 is not materially different than at December 31, 1999. PART II. OTHER INFORMATION Item 5. Other Information. American Electric Power Company, Inc. ("AEP"), AEP Generating Company ("AEGCo"), Appalachian Power Company ("APCo"), Columbus Southern Power Company ("CSPCo"), Indiana Michigan Power Company ("I&M"), Kentucky Power Company ("KEPCo") and Ohio Power Company ("OPCo") Reference is made to page 36 of the Annual Report on Form 10-K for the year ended December 31, 1999 ("1999 10-K") for a discussion of the review by the United States Environmental Protection Agency ("Federal EPA") of low volume coal combustion wastes. On April 25, 2000, Federal EPA issued a regulatory determination that low volume wastes from coal combustion that are mixed with and co-treated or co-disposed with high volume coal combustion wastes do not warrant regulation under RCRA Subtitle C as hazardous waste. Instead, Federal EPA indicated that it would develop national Subtitle D solid waste standards applicable to disposal of all coal combustion wastes in surface impoundments and landfills. According to Federal EPA's regulatory determination, Federal EPA intends to apply these national regulations to both high volume coal combustion wastes co-managed with low volume wastes and high volume coal combustion wastes previously addressed in the 1993 regulatory determination that are separately disposed of. Federal EPA also determined that additional regulation would be necessary for use of coal combustion by-products to fill surface or underground mines. If the RCRA Subtitle D national standards that are to be developed by Federal EPA for coal combustion wastes would be more stringent than currently applicable state regulations, AEP System facilities could incur additional waste management expenses. The significance of these cost increases, or the timing of Federal EPA's finalization of these national standards, cannot be determined at this time. AEP and OPCo Reference is made to page 43 of the 1999 10-K for a discussion of litigation with Ormet Corporation involving the ownership of sulfur dioxide allowances. On March 27, 2000, the U.S. Court of Appeals for the Fourth Circuit issued a decision affirming the judgment of the District Court that granted the motion of OPCo and AEP Service Corporation for summary judgment. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 12 - Statement re: Computation of Ratios. AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 27 - Financial Data Schedule. (b) Reports on Form 8-K: AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo No reports on Form 8-K were filed during the quarter ended March 31, 2000. Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/ Armando A. Pena By: /s/ Leonard V. Assante Armando A. Pena Leonard V. Assante Treasurer Controller and Chief Accounting Officer (Duly Authorized Officer) (Chief Accounting Officer) AEP GENERATING COMPANY APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY By: /s/ Armando A. Pena By: /s/ Leonard V. Assante Armando A. Pena Leonard V. Assante Vice President, Treasurer, Controller and and Chief Financial Officer Chief Accounting Officer (Duly Authorized Officer) (Chief Accounting Officer) Date: May 11, 2000 II-3 EX-12 2 EXHIBIT 12 APPALACHIAN POWER COMPANY Computation of Consolidated Ratio of Earnings to Fixed Charges (in thousands except ratio data)
Twelve Months Year Ended December 31, Ended 1995 1996 1997 1998 1999 3/31/00 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . $ 80,777 $ 82,082 $ 81,009 $ 72,057 $ 65,697 $ 63,101 Interest on Other Long-term Debt. . . . . . . . 16,404 18,025 28,163 40,642 50,712 54,091 Interest on Short-term Debt . . . . . . . . . . 5,119 3,639 4,569 4,245 5,959 6,865 Miscellaneous Interest Charges. . . . . . . . . 5,323 7,327 6,857 11,470 8,212 6,699 Estimated Interest Element in Lease Rentals . . 7,000 6,600 6,000 5,900 6,100 6,100 Total Fixed Charges. . . . . . . . . . . . $114,623 $117,673 $126,598 $134,314 $136,680 $136,856 Earnings: Net Income. . . . . . . . . . . . . . . . . . . $115,900 $133,689 $120,514 $ 93,330 $120,492 $128,895 Plus Federal Income Taxes . . . . . . . . . . . 53,355 65,801 54,835 43,941 70,950 75,867 Plus State Income Taxes . . . . . . . . . . . . 7,273 10,180 8,109 6,845 5,085 5,557 Plus Fixed Charges (as above) . . . . . . . . . 114,623 117,673 126,598 134,314 136,680 136,856 Total Earnings . . . . . . . . . . . . . . $291,151 $327,343 $310,056 $278,430 $333,207 $347,175 Ratio of Earnings to Fixed Charges. . . . . . . . 2.54 2.78 2.44 2.07 2.43 2.53
EX-27 3 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000006879 APPALACHIAN POWER COMPANY 1,000 3-MOS DEC-31-1999 MAR-31-2000 PER-BOOK 3,184,755 189,913 577,722 40,737 436,744 4,429,871 260,458 714,434 191,232 1,166,124 20,310 18,260 1,535,052 0 0 128,425 48,005 0 51,528 12,334 1,449,833 4,429,871 455,595 30,436 346,913 377,349 78,246 781 79,027 31,363 47,664 633 47,031 31,653 63,101 96,581 0 0 All common stock owned by parent company; no EPS required.
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