-----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, RpQNAWD1HcByZfdhLT+KwOhsZ7QMX44dEx3W12hvGggnkwL5TWPMYm76+ZvdTO4p 6SPqwNL6dxFxxmCk43Q90Q== 0000004904-99-000224.txt : 19991117 0000004904-99-000224.hdr.sgml : 19991117 ACCESSION NUMBER: 0000004904-99-000224 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991115 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: 99752291 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 SEPTEMBER 30, 1999 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period from to
Commission Registrant; State of Incorporation; I. R. S. Employer File Number Address; and Telephone Number Identification No. 1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640 (A New York Corporation) 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP GENERATING COMPANY (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 October 31, 1999 was 194,103,349.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended September 30, 1999
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-21 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . A-22- A-43 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-10 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . C-11- C-22 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-11 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . E-12- E-24 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-8 Management's Narrative Analysis of Results of Operations . . F-9 - F-10
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended September 30, 1999
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-12 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . G-13- G-25 Part II. OTHER INFORMATION Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2 SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 EXHIBITS INDEX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4 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 Nine Months Ended September 30, September 30, 1999 1998 1999 1998 REVENUES: Domestic Regulated Electric Utilities. . $1,758 $1,846 $4,809 $4,916 Worldwide Non-regulated Electric and Gas Operations . . . . . . . . . . . . 156 12 442 20 TOTAL REVENUES . . . . . . . . . 1,914 1,858 5,251 4,936 EXPENSES: Fuel and Purchased Power . . . . . . . . 631 652 1,616 1,691 Maintenance and Other Operation. . . . . 491 496 1,387 1,344 Depreciation and Amortization. . . . . . 151 146 448 434 Taxes Other Than Federal Income Taxes. . 121 120 364 354 Worldwide Non-regulated Electric and Gas Operations . . . . . . . . . . . . 144 31 394 62 TOTAL EXPENSES . . . . . . . . . 1,538 1,445 4,209 3,885 OPERATING INCOME . . . . . . . . . . . . . 376 413 1,042 1,051 NONOPERATING INCOME (LOSS) . . . . . . . . 3 (3) - 6 INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES . . . . . . . 379 410 1,042 1,057 INTEREST AND PREFERRED DIVIDENDS . . . . . 136 110 403 325 INCOME BEFORE INCOME TAXES . . . . . . . . 243 300 639 732 INCOME TAXES . . . . . . . . . . . . . . . 69 105 226 268 NET INCOME . . . . . . . . . . . . . . . . $ 174 $ 195 $ 413 $ 464 AVERAGE NUMBER OF SHARES OUTSTANDING . . . 194 191 193 191 EARNINGS PER SHARE . . . . . . . . . . . . $0.90 $1.02 $2.14 $2.44 CASH DIVIDENDS PAID PER SHARE. . . . . . . $0.60 $0.60 $1.80 $1.80 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 NET INCOME . . . . . . . . . . . . . . . . $174 $195 $413 $464 OTHER COMPREHENSIVE INCOME: Foreign Currency Translation Adjustments. . . . . . . . . . . . . . (1) - 20 - COMPREHENSIVE INCOME . . . . . . . . . . . $173 $195 $433 $464 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (in millions) ASSETS CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . $ 274 $ 173 Accounts Receivable (net). . . . . . . . . . . . . . 978 879 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 297 216 Materials and Supplies . . . . . . . . . . . . . . . 307 280 Accrued Utility Revenues . . . . . . . . . . . . . . 213 214 Energy Marketing and Trading Contracts . . . . . . . 666 372 Prepayments and Other. . . . . . . . . . . . . . . . 93 84 TOTAL CURRENT ASSETS . . . . . . . . . . . . 2,828 2,218 PROPERTY, PLANT AND EQUIPMENT: Electric: Production . . . . . . . . . . . . . . . . . . . . 9,902 9,615 Transmission . . . . . . . . . . . . . . . . . . . 3,793 3,692 Distribution . . . . . . . . . . . . . . . . . . . 5,349 5,125 Other (including gas and coal mining assets and nuclear fuel) . . . . . . . . . . . . . . . . . 2,259 2,118 Construction Work in Progress. . . . . . . . . . . . 661 801 Total Property, Plant and Equipment. . . . . 21,964 21,351 Accumulated Depreciation and Amortization. . . . . . 9,043 8,549 NET PROPERTY, PLANT AND EQUIPMENT. . . . . . 12,921 12,802 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 2,049 1,847 OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 2,640 2,616 TOTAL. . . . . . . . . . . . . . . . . . . $20,438 $19,483 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable . . . . . . . . . . . . . . . . . . $ 647 $ 607 Short-term Debt. . . . . . . . . . . . . . . . . . . 710 617 Long-term Debt Due Within One Year . . . . . . . . . 978 206 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 239 382 Interest Accrued . . . . . . . . . . . . . . . . . . 117 75 Obligations Under Capital Leases . . . . . . . . . . 90 82 Energy Marketing and Trading Contracts . . . . . . . 643 360 Other. . . . . . . . . . . . . . . . . . . . . . . . 483 472 TOTAL CURRENT LIABILITIES. . . . . . . . . . 3,907 2,801 LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . 6,219 6,800 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,647 2,601 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 334 351 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 215 222 DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . 424 263 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,503 1,429 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES . . . . . . 169 174 CONTINGENCIES (Note 9) COMMON SHAREHOLDERS' EQUITY: Common Stock-Par Value $6.50: 1999 1998 Shares Authorized . . . .600,000,000 600,000,000 Shares Issued . . . . . .203,092,805 200,816,469 (8,999,992 shares were held in treasury) . . . . . 1,320 1,305 Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,931 1,854 Accumulated Other Comprehensive Income - Foreign Currency Translation Adjustments. . . . . . 19 (1) Retained Earnings. . . . . . . . . . . . . . . . . . 1,750 1,684 TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . 5,020 4,842 TOTAL. . . . . . . . . . . . . . . . . . . $20,438 $19,483 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in millions) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 413 $ 464 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 532 463 Deferred Federal Income Taxes. . . . . . . . . . . . . . 106 34 Deferred Investment Tax Credits. . . . . . . . . . . . . (17) (17) Amortization of Deferred Property Taxes. . . . . . . . . 138 135 Cook Restart Expense Deferral. . . . . . . . . . . . . . (90) - Deferred Costs Under Fuel Clause Mechanisms. . . . . . . (103) (59) Changes in Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (99) (174) Fuel, Materials and Supplies . . . . . . . . . . . . . . (108) 14 Accounts Payable . . . . . . . . . . . . . . . . . . . . 40 108 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (143) (81) Interest Accrued . . . . . . . . . . . . . . . . . . . . 42 30 Revenue Refunds Accrued. . . . . . . . . . . . . . . . . (43) 55 Other Current Assets and Liabilities . . . . . . . . . . 42 124 Payment of Disputed Tax and Interest Related to COLI . . . (19) (303) Other (net). . . . . . . . . . . . . . . . . . . . . . . . 57 52 Net Cash Flows From Operating Activities . . . . . . 748 845 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (598) (557) Other Investments. . . . . . . . . . . . . . . . . . . . . (15) (10) Proceeds from Sale of Property . . . . . . . . . . . . . . 5 9 Net Cash Flows Used For Investing Activities . . . . (608) (558) FINANCING ACTIVITIES: Issuance of Common Stock . . . . . . . . . . . . . . . . . 91 63 Issuance of Long-term Debt . . . . . . . . . . . . . . . . 545 618 Retirement of Cumulative Preferred Stock . . . . . . . . . (5) - Retirement of Long-term Debt . . . . . . . . . . . . . . . (416) (548) Change in Short-term Debt (net). . . . . . . . . . . . . . 93 (20) Dividends Paid on Common Stock . . . . . . . . . . . . . . (347) (343) Net Cash Flows Used For Financing Activities . . . . (39) (230) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 101 57 Cash and Cash Equivalents at Beginning of Period . . . . . . 173 91 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 274 $ 148 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $344 million and $279 million and for income taxes was $63 million and $150 million in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $67 million and $94 million in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in millions) BALANCE AT BEGINNING OF PERIOD . . . . . $1,692 $1,645 $1,684 $1,605 NET INCOME . . . . . . . . . . . . . . . 174 195 413 464 DEDUCTIONS: Cash Dividends Declared. . . . . . . . 116 114 347 343 BALANCE AT END OF PERIOD . . . . . . . . $1,750 $1,726 $1,750 $1,726 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING AND RELATED ACTIVITIES During the first nine months of 1999, subsidiaries issued $475 million of senior unsecured notes: $150 million at 6.60% due in 2009, $100 million at 6.75% due in 2004, $150 million at 6.875% due in 2004 and $75 million at 7% due in 2004. Also $50 million of pollution control revenue bonds at 5.15% due in 2026 were issued and short-term debt borrowings increased by $93 million. In October 1999 an additional $50 million of senior unsecured notes at 7.45% due in 2004 were issued. Retirements of debt were: first mortgage bonds totaling $311 million with interest rates ranging from 6.55% to 8.43% and due dates ranging from 2003 to 2024, $50 million of pollution control revenue bonds at 7.40% due 2009 and $40 million in term loans with interest rates ranging from 6.42% to 7.69% due in 1999. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income from marking open trading contracts to market is deferred as regulatory assets or liabilities for the portion of those open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes in jurisdictions other than the Virginia retail jurisdiction. As a result of a prohibition against establishing new regulatory assets contained in a Virginia rate settlement agreement, the Virginia retail jurisdictional share of the mark-to-market adjustment is included in net income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. RATE MATTERS The Federal Energy Regulatory Commission (FERC) issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission services tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 29, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers have sought rehearing of the Commission's Order. The Company made a provision in September 1999 for the refund which it anticipates would result if the Commission's Order is upheld including interest. 5. 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 100% of Yorkshire's summarized consolidated financial information: Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in millions) Income Statement Data: Operating Revenues $523.0 $510.2 $1,679.7 $1,677.3 Operating Income 48.5 82.6 200.5 264.8 Net Income 8.3 21.5 38.5 13.6 In August 1999 the Office of Gas and Electricity Markets (OFGEM, which is the U.K. regulator of gas and electricity rates), published draft price proposals for the U.K.'s regional distribution businesses that would be effective for the five-year period beginning April 1, 2000. Under the draft price proposals, the distribution rates for Yorkshire would be reduced 15% to 20% from current rates. Yorkshire filed comments on September 17, 1999 with OFGEM expressing various concerns with the analysis used by OFGEM. Yorkshire also commented that the methodology used failed to justify the magnitude of the price cuts proposed and suggested a more suitable methodology. On October 8, 1999, OFGEM issued updated draft price proposals for Yorkshire's electric distribution business. The updated proposal would require Yorkshire to reduce distribution rates 15% and transfer 8% of costs to Yorkshire's electricity supply business, an overall reduction in distribution prices of 23%. Also on October 8, 1999, OFGEM issued draft price proposals for Yorkshire's electric supply business. Under the proposals, a supply price cap for certain domestic U.K. customers is retained from April 2000 through March 2002. For Yorkshire, these proposals would result in a price reduction of approximately 10.7% on the standard domestic tariff commencing April 2000 and ending March 2001 and a nominal price freeze for the year commencing April 2001 and ending March 2002. OFGEM is expected to publish final proposals on both the distribution and the supply businesses at the end of November 1999. Yorkshire management intends to take all available opportunities to increase revenues and reduce costs to mitigate the impact of the final OFGEM distribution and supply price reductions. Should Yorkshire be unable to increase revenues and reduce costs in amounts sufficient to offset the impact of the OFGEM distribution and supply price reductions, AEP's equity earnings from its investment in Yorkshire will be significantly reduced in comparison to its current level of earnings. 6. 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 electric power wholesale marketing and trading activities that are conducted as part of regulated operations and subject to cost of service rate regulation. Worldwide Non-regulated Electric and Gas Operations are comprised of a Worldwide Energy Investments segment and other business segments. The Worldwide Energy Investments 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 nine months ending September 30, 1999 and 1998 is shown in the following table:
Worldwide Non-regulated Electric and Gas Operations Regulated Domestic World Electric Wide Energy Reconciling AEP Utilities Investments Other Adjustments Consolidated (in millions) September 30, 1999 Revenues from external customers $ 4,809 $ 553 $ 79 $(190) $ 5,251 Revenues from transactions with other operating segments - 47 143 (190) - Segment net income (loss) 409 20 (16) - 413 Total assets 17,375 2,333 730 - 20,438 September 30, 1998 Revenues from external customers 4,916 20 - - 4,936 Revenues from transactions with other operating segments - - - - - Segment net income (loss) 485 (12) (9) - 464 Total assets 16,723 472 281 - 17,476
7. MERGER As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company and Central and South West Corporation (CSW) announced plans to merge in December 1997. In 1998 the appropriate shareholder proposals for the consummation of the merger were approved. Approval of the merger has been requested from the FERC, the Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC) and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. On July 29, 1999 applications were made with the Federal Communication Commission to authorize the transfer of control of licenses of several CSW entities to the Company. AEP and CSW made a merger filing with the Department of Justice in July 1999. The NRC and the Arkansas Public Service Commission approved the merger in 1998. In 1998 the FERC issued an order which confirmed that a 250 megawatt 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. FERC In November, 1998 the FERC issued an order establishing hearing procedures for the merger. The 1998 FERC order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection. On May 25, 1999 AEP and CSW reached a settlement with the FERC trial staff resolving competition and rate issues relating to the merger. On July 13, 1999 AEP and CSW reached an additional settlement with the FERC trial staff resolving additional issues. The settlements were submitted to the FERC for approval. Under the terms of the settlements, AEP filed with the FERC a regional transmission organization (RTO) proposal whereby it will transfer the operation and control of AEP's bulk transmission facilities to an RTO. The settlements also cover rates for transmission services and ancillary service as well as resolving issues related to system integration agreements and confirm, subject to FERC guidance on certain elements, that the proposed generation divestiture of up to 550 megawatts of capacity will satisfy the staff's market power concerns. The hearings began on June 29, 1999 and concluded on July 19, 1999. On June 28, 1999, the Company and CSW filed a motion asking the FERC to waive the requirement for a post-hearing decision by an administrative law judge (ALJ) who presides over the merger hearing. The motion indicated that the commission could then decide the matter based on the hearing record and briefs submitted by all interested parties. On July 28, 1999, the FERC ordered the ALJ to issue an initial decision as soon as possible, but no later than November 24, 1999. The commission concluded that it needed the benefit of the ALJ's opinion and, therefore, decided not to grant the request. The procedural schedule that follows the ALJ's initial decision should allow the FERC to issue a final order in the first quarter of 2000. Louisiana On July 29, 1999 the Louisiana Public Service Commission (LPSC) approved the merger between the Company and CSW subject to final FERC approval. In granting approval, the LPSC also approved a stipulated settlement in which the Company and CSW agreed to share with SWEPCO's Louisiana customers merger savings created as a result of the merger over the eight years following its consummation. The merger savings are estimated to total more than $18 million during that eight-year period. In addition the settlement also includes: A cap on base rates for five years after consummation of the merger; Sharing of benefits from off-system sales; Establishment of conditions for affiliate transactions with other AEP and CSW subsidiaries; Provisions to ensure continued quality of service; and Provisions to hold SWEPCO's Louisiana customers harmless for adverse effects of the merger, if any. Oklahoma On May 11, 1999, the Oklahoma Corporation Commission (OCC) approved the proposed merger between the Company and CSW. The approval follows an administrative law judge's oral decision on a partial settlement between certain principal parties to the Oklahoma merger proceeding which recommended that the OCC approve the merger. The partial settlement provides for sharing of net merger savings with Oklahoma customers; no increase in Oklahoma base rates prior to January 1, 2003; filing by December 31, 2001 with the FERC an application to join a regional transmission organization; and implementing additional quality of service standards for Oklahoma retail customers. Oklahoma's share (approximately $50 million) of net merger savings over the first five years after the merger is consummated will be shared between Oklahoma customers and AEP shareholders. The partial settlement agreement includes a recommendation by the OCC staff that the OCC file with FERC indicating that it does not oppose the merger, but reserves the right to ensure that there are no adverse impacts on the Oklahoma transmission system. Certain municipal and cooperative customers have appealed the OCC's merger approval order. On October 13, 1999 this appeal was dismissed by the Oklahoma Supreme Court and the cooperative customers have since asked the OCC to dismiss their appeal. Texas On May 4, 1999, AEP and CSW announced that a stipulated settlement had been reached in Texas. The agreement builds upon an earlier settlement agreement signed by AEP, CSW and certain parties to the Texas merger proceeding. In addition to the parties that were signatories to the earlier agreement, the staff of the Public Utility Commission of Texas is a signatory to the new settlement as well as other key parties to the merger proceeding. The stipulated settlement would result in rate reductions totaling $221 million over a six-year period for Texas customers after the merger is completed. The $221 million rate reduction is composed of $84.4 million of net merger savings and $136.6 million to resolve existing issues associated with CSW operating subsidiaries' rate and fuel reconciliation proceedings in Texas. Under the terms of the settlement agreement, base rates would not be increased before January 1, 2003 or three years after the merger, whichever is later. The settlement also calls for the divestiture of a total of 1,604 megawatts of existing and proposed generating capacity within Texas. If it is determined that the divestiture can proceed immediately after the merger closes without jeopardizing pooling-of-interests accounting treatment for the merger, sale of the plants would begin no later than 90 days after the merger closes. Absent that determination, the divestiture would occur approximately two years after the merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. Other provisions in the settlement agreement provide for, among other things, accelerated stranded cost recovery, quality-of-service standards, continuation of programs for disadvantaged customers and transfer of control of bulk transmission facilities to a regional transmission organization. Hearings on the merger in Texas began August 9, 1999 and concluded on August 10, 1999. As the hearings began, settlements were reached with all but one of the parties in the case. The settling parties are all wholesale electric customers of CSW's Texas electric operating companies. The settlements call for the withdrawal of their opposition to the merger in all regulatory approval proceedings. On November 4, 1999 the Texas Commission, in its open meeting approved the application on the pending merger and the stipulated settlement announced in May. Indiana The Indiana Utility Regulatory Commission (IURC) approved a settlement agreement related to the merger on April 26, 1999. The settlement agreement resulted from an investigation of the proposed merger initiated by the IURC. The terms of the settlement agreement provide for, among other things, a sharing of net merger savings through reductions in customers' bills of approximately $67 million over eight years after the merger is completed; a one year extension through January 1, 2005 of a freeze in base rates; additional annual deposits of $5.5 million to the nuclear decommissioning trust fund for the Indiana jurisdiction for the years 2001 through 2003; quality-of-service standards; and participation in a regional transmission organization. As part of the settlement agreement, the IURC agreed not to oppose the merger in the FERC or SEC proceedings. Kentucky On April 15, 1999, in compliance with a request from the staff of the Kentucky Public Service Commission (KPSC) AEP filed an application seeking KPSC approval for the indirect change in control of Kentucky Power Company that will occur as a result of the proposed merger. Although AEP did not believe that the KPSC has the jurisdictional authority to approve the merger, AEP reached a merger settlement agreement on May 24, 1999 with key parties in Kentucky which the KPSC approved on June 14, 1999. Under the terms of the Kentucky settlement, AEP has agreed to share net merger savings with Kentucky customers; establish performance standards that will maintain or improve customer service and system reliability; and to establish rules to protect consumers and promote fair competition. The Kentucky customers' share of the net merger savings are expected to be approximately $28 million. The key parties to the Kentucky settlement agreed not to oppose the merger during the FERC or the SEC proceedings. Ohio On October 21, 1999, the Public Utilities Commission of Ohio (PUCO) issued a decision stating that it will notify the FERC that it will withdraw its opposition to the Company's pending merger with CSW and will not seek conditions on the merger. American Municipal Power - Ohio (AMP-Ohio) and AEP reached a settlement addressing outstanding issues. As part of the settlement AMP-Ohio agreed to withdraw as an intervenor in the merger process. AMP-Ohio is the nonprofit wholesale power supplier and service provider for most of Ohio's 84 community-owned public power systems, two West Virginia public power systems and four Pennsylvania public power systems. Other AEP and CSW have reached settlements with the Missouri Commission, the International Brotherhood of Electrical Workers (IBEW), representing employees of AEP and CSW, and the Utility Worker's Union of America (UWUA) representing AEP employees, and certain wholesale customers. All have agreed not to oppose the merger in the FERC or SEC proceedings. The proposed merger of CSW into AEP would result in common ownership of two United Kingdom (UK) regional electricity companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50% ownership interest in Yorkshire and CSW has a 100% interest in Seeboard. Although the merger of CSW into AEP is not subject to approval by UK regulatory authorities, the common ownership of two UK RECs could be referred by the UK Secretary of State for Trade and Industry to the UK Competition Commission (formerly Monopolies and Mergers Commission) for review and investigation. Completion of the Merger As of September 30, 1999, AEP had deferred $37 million of costs related to the merger on its consolidated balance sheet, which will be charged to expense if AEP and CSW are not successful in completing their proposed merger. If the merger is consummated the deferred costs allocable to the regulated electric operating subsidiaries will be amortized over their recovery period, generally 5-years, in accordance with state regulator orders. The remainder of the deferred merger costs will be expensed upon consummation of the merger. The merger is conditioned upon, among other things, the approval of certain state and federal regulatory agencies. The transaction must satisfy many conditions, a number of which may not be waived by the parties, including the condition that the merger must be accounted for as a pooling of interests. The merger agreement will terminate on December 31, 1999 unless extended for six months by either party as provided in the merger agreement. 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. 8. RESTRUCTURING LEGISLATION Virginia In March 1999 a law was enacted in Virginia to restructure the electric utility industry. Under the restructuring law a transition to choice of electricity supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. The law also provides an opportunity for recovery of just and reasonable net stranded generation costs. Stranded costs are those costs above market including generation related regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001 and the establishment of a wires charge by the fourth quarter of 2001. Management has concluded that as of September 30, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates and the wires charge as provided in the law. The establishment of capped rates and the wires charge should enable the Company to determine its ability to recover stranded costs, a requirement to discontinue application of SFAS 71. When the capped rates and the wires charge are established in Virginia, the application of SFAS 71 will be discontinued for the Virginia retail jurisdiction portion of the Company's generating business. At that time the Company will have to write-off its generation-related regulatory assets to the extent that they cannot be recovered under capped rates and wire charges approved by the Virginia SCC under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of impaired assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of capped rates, wires charges and other pertinent information, it is not possible at this time to determine if any generation related assets are impaired in accordance with SFAS 121 and if generation related regulatory assets will be recovered. The amount of regulatory assets recorded on the books applicable to the Company's Virginia retail generating business at September 30, 1999 is estimated to be $60 million before related tax effects. Should it not be possible under the Virginia law to recover all or a portion of the generation related regulatory assets and/or tangible generating assets, it could have a material adverse impact on results of operations and cash flows. An estimated determination of whether the Company will experience any asset impairment loss regarding its Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation related regulatory assets and other transition costs cannot be made until such time as the transition capped rates and the wires charge are determined under the law; which is not expected to occur before the fourth quarter of 2000. Ohio The Ohio Electric Restructuring Act of 1999 became law on October 4, 1999. The law provides for customer choice of electricity supplier, a residential rate reduction of 5% and a freezing of the unbundled generation base rates and a freezing of fuel rates beginning on January 1, 2001. The law also provides for a five-year transition period to transition from cost based rates to market pricing for generation services. It authorizes the PUCO to address certain major transition issues including unbundling of rates and the recovery of regulatory assets including any unrecovered deferred fuel costs, stranded plant and mining costs and other transition costs. Retail electric services that will be competitive are defined in the law as electric generation service, aggregation service, and power marketing and brokering. Under the legislation the PUCO is granted broad oversight responsibility and is required by the law to promulgate rules for competitive retail electric generation service. The law also gives the PUCO authority to approve a transition plan for each electric utility company. The law provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled frozen generation rates paid through December 31, 2005 by customers who do not switch generation suppliers and through a wires charge for customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Recovery of transition costs can, under certain circumstances, extend beyond the five-year frozen rate transition period but cannot continue beyond December 31, 2010. The Company must file a transition plan with the PUCO by January 3, 2000 and the PUCO is required to issue a transition order no later than October 31, 2000. The law also provides that the property tax assessment percentage on electric generation property be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on kilowatt-hours sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year, deferred as a prepaid expense and amortized to expense during the tax year pursuant to the tax laws whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. The change in the tax law to impose an excise tax based on kilowatt-hours sold to Ohio customers commencing before the expiration of the gross receipts tax privilege period will result in a 12 month period when electric utilities are recording as an expense both the gross receipts tax and the excise tax. Management intends to seek recovery of the overlap of the gross receipts and excise taxes in the Ohio transition plan filing. As discussed in Note 3, "Effects of Regulation and Phase-In Plans," of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company defers as regulatory assets and liabilities certain expenses and revenues consistent with the regulatory process in accordance with SFAS 71. Management has concluded that as of September 30, 1999 the requirements to apply SFAS 71 continue to be met since the Company's rates for generation will continue to be cost-based regulated until the establishment of unbundled frozen generation rates and a wires charge as provided in the law. The establishment of unbundled frozen generation rates and the wires charge should enable the Company to determine its ability to recover transition costs including regulatory assets and other stranded costs, a requirement to discontinue application of SFAS 71. When unbundled generation rates and the wires charge are established, the application of SFAS 71 will be discontinued for the Ohio retail jurisdiction portion of the generation business. At that time the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the unbundled frozen generation rates and distribution wires charges approved by the PUCO under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121. An impairment loss would be recorded to the extent that the cost of generation assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of an unbundled frozen generation rate, the wires charge and other pertinent information, it is not possible at this time to determine if any of the Company's generating assets are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books at September 30, 1999 applicable to the Ohio retail jurisdictional generating business is $638 million before related tax effects. Due to the planned closing of affiliated mines including the Meigs mine, and other anticipated events, generation-related regulatory assets as of December 31, 2000 allocable to the Ohio retail jurisdiction are estimated to exceed $800 million, before federal income tax effects. Recovery of these regulatory assets will be sought as a part of the Company's Ohio transition plan filing. An estimated 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 such time as the unbundled frozen generation rates and the wires charge are determined through the regulatory process. Management will seek full recovery of generation-related regulatory assets, any stranded costs and other transition costs in its transition plan filing. The PUCO is required to complete its regulatory process and issue a transition order establishing the transition rates and wires charges by no later than October 31, 2000. Should the PUCO fail to approve transition rates and wires charges that are sufficient to recover the Company's generation-related regulatory assets, any other stranded costs and transition costs, it could have a material adverse effect on results of operations, cash flows and financial condition. 9. CONTINGENCIES Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $317 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other assets pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States (US) in the US District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the Company's generating plants are located. A number of utilities, including the Company, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $1.5 billion for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through regulated rates, and where generation is being deregulated unbundled generation transition rates, wires charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Muskingum River, Mitchell, Philip Sporn, Tanners Creek and Cardinal plants over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at these same plants as well as Conesville Plant. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders including a Notice of Violation issued to The Cincinnati Gas & Electric Company for Beckjord Plant alleging violations of the New Source Review provisions of the Clean Air Act. Columbus Southern Power Company owns a partial interest in Unit 6 of Beckjord Plant. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Philip Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River Plant, Gavin Plant, Cardinal Plant, Clinch River Plant, Kanawha River Plant, Tanners Creek Plant, Amos Plant and Big Sandy Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, approved unbundled transition generation rates, wires charges and future market prices for energy. Cook Nuclear Plant Shutdown As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, both units of the Cook Plant were shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a NRC architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. In 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The NRC senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The Company's plan to restart the Cook Plant units has Unit 2 scheduled to return to service in April 2000 and Unit 1 to return to service in September 2000. The restart plan was developed based upon a comprehensive systems readiness review of all operating systems at the Cook Plant. When maintenance and other activities required for restart are complete, the Company will seek concurrence from the NRC to return the Cook Plant to service. Management intends to replace the steam generator for Unit 1 before the unit is returned to service. Costs associated with the steam generator replacement are estimated to be approximately $165 million, which will be accounted for as a capital investment unrelated to the restart. At September 30, 1999, $82 million has been spent on the steam generator replacement. The cost of electricity supplied to retail customers increased due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal-based purchased power is being substituted for the unavailable low cost nuclear generation. Actual replacement energy fuel costs that exceeded the costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. On March 30, 1999 the IURC approved a settlement agreement that resolves all matters related to the recovery of replacement energy fuel costs and all outage/restart issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a billing credit of $55 million, including interest, to Indiana retail customers' bills; the deferral of unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including a $52.3 million revenue portion of the $55 million billing credit; the deferral of up to $150 million of incremental operation and maintenance costs in 1999 for Cook Plant above the amount included in base rates; the amortization of the deferred fuel and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit was applied to retail customers' bills during the months of July, August and September 1999. In June 1999 the Company announced that a settlement agreement for two open Michigan power supply cost recovery reconciliation cases had been reached with the staff of the Michigan Public Service Commission (MPSC). The proposed settlement agreement would limit the Company's ability to increase base rates and freeze power supply costs for five years, allow for the amortization of deferred power supply cost for 1997, 1998 and 1999 over five years, allow for the deferral and amortization of non-fuel nuclear operation and maintenance expenses over five years and resolve all issues related to the Cook Plant extended restart outage. The pending Michigan settlement limits deferrals to $50 million of 1999 jurisdictional non-fuel nuclear operation and maintenance costs. Hearings have been held to give the one intervenor who opposed the approval of the settlement agreement the opportunity to voice its objections. The settlement agreement is pending before the MPSC. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as a current period operation and maintenance expense in 1999 and 2000. Through September 30, 1999, $280 million has been spent, of which $196 million was incurred in 1999. Pursuant to the Indiana settlement agreement $112.5 million of incremental operation and maintenance costs were deferred for the nine months ended September 30, 1999. The Indiana jurisdiction deferral is limited to up to $150 million of incremental restart costs incurred in 1999. The amortization of such costs through September 30, 1999 was $22.5 million. At September 30, 1999, the unamortized balance of incremental restart related operation and maintenance costs was $90 million and was included in regulatory assets. Also deferred as a regulatory asset at September 30, 1999 was $148 million of replacement energy fuel costs. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations, cash flows, and possibly financial condition through 2003. Management believes that the Cook units will be successfully returned to service by April and September 2000, 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. Other The Company continues to be involved in certain other matters discussed in the 1998 Annual Report. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased by $21 million or 11% for the quarter and $51 million or 11% for the year-to-date period due predominantly to a decrease in wholesale energy sales and margins, an increase in costs to prepare the Cook Plant for restart following an extended outage in the Company's domestic regulated electric utility operations and an increase in interest expense to finance acquisitions in the Company's worldwide non-regulated operations. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Revenues: Domestic Regulated Electric Utilities. . . $(88) (5) $(107) (2) Worldwide Non-regulated Operations. . . . . . . 144 N.M. 422 N.M. Fuel and Purchased Power Expense . . . . . (21) (3) (75) (4) Maintenance and Other Operation Expense . . . . (5) (1) 43 3 Worldwide Non-regulated Operations Expense. . . . 113 N.M. 332 N.M. Interest and Preferred Dividends . . . . . . . . 26 24 78 24 Income Taxes . . . . . . . (36) (34) (42) (16) N.M. = Not Meaningful Revenues from domestic regulated electric utility operations decreased in both the third quarter and the year-to-date periods due predominantly to decreased energy sales to wholesale customers and a decline in margins on wholesale energy sales. Energy sales to wholesale customers declined 16% in the quarter and 20% in the year-to-date period primarily due to weather and its effect on energy demand. Margins on trading in AEP's marketing area declined $100 million in the quarter and $90 million for the year-to-date period reflecting the effect of milder summer weather. The increase in revenues from worldwide non-regulated operations was predominantly due to the acquisition in December 1998 of CitiPower, an Australian electric distribution utility, and Louisiana Intrastate Gas, a midstream natural gas operation in Louisiana. The decreases in fuel and purchased power expense were primarily attributable to a decrease in coal-fired generation reflecting the decline in demand for electricity and an increase in the deferral of the non-fuel components of the fuel clauses for recovery in later periods in the domestic regulated electric utility operations. In the year-to-date period, a decline in purchased power as a result of the reduced wholesale demand also contributed to the decrease. Maintenance and other operation expense increased for the year-to-date period largely as a result of expenditures to prepare the Cook Plant units for restart following an extended Nuclear Regulatory Commission (NRC) monitored outage which began in September 1997. Worldwide non-regulated expenses increased as a result of the expansion of business development activities and expenses of CitiPower and Louisiana Intrastate Gas which were acquired in December 1998. Additional borrowings to fund the Company's non-regulated operations, primarily the acquisitions of CitiPower and Louisiana Intrastate Gas in December 1998, were the primary reason for the significant increase in interest and preferred dividends. The decrease in income taxes is primarily attributable to a decrease in United States federal income taxes which was due to a decrease in pre-tax income and adjustments to prior years tax returns. FINANCIAL CONDITION Total plant and property additions including capital leases for the first nine months of 1999 were $665 million. During the first nine months of 1999, subsidiaries issued $550 million principal amount of long-term obligations at interest rates ranging from 5.15% to 10.53%; retired $401 million principal amount of long-term debt with interest rates ranging from 6.42% to 8.43%; and increased short-term debt by $93 million. OTHER MATTERS Spent Nuclear Fuel (SNF) Litigation As discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition (MDA) in the 1998 Annual Report, as a result of the Department of Energy's (DOE) failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, the Company along with a number of unaffiliated utilities and states filed suit in the United States (US) Court of Appeals for the District of Columbia Circuit requesting, among other things, that the court order DOE to meet its obligations under the law. The court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In June 1998, the Company filed a complaint in the US Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits have been filed by other utilities. On April 6, 1999, the court granted DOE's motion to dismiss a lawsuit filed by another utility. On May 20, 1999, the other utility appealed this decision to the U.S. Court of Appeals for the Federal Circuit. I&M's case has been stayed pending final resolution of the other utility's appeal. United Kingdom Price Reduction Proposal In August 1999 the Office of Gas and Electricity Markets (OFGEM, which is the U.K. regulator of gas and electricity rates), published draft price proposals for the U.K.'s regional distribution businesses that would be effective for the five-year period beginning April 1, 2000. Under the draft price proposals, the distribution rates for Yorkshire would be reduced 15% to 20% from current rates. Yorkshire filed comments on September 17, 1999 with OFGEM expressing various concerns with the analysis used by OFGEM. Yorkshire also commented that the methodology used failed to justify the magnitude of the price cuts proposed and suggested a more suitable methodology. On October 8, 1999, OFGEM issued updated draft price proposals for Yorkshire's electric distribution business. The updated proposal would require Yorkshire to reduce distribution rates 15% and transfer 8% of costs to Yorkshire's electricity supply business, an overall reduction in distribution prices of 23%. Also on October 8, 1999, OFGEM issued draft price proposals for Yorkshire's electric supply business. Under the proposals, a supply price cap for certain domestic U.K. customers is retained from April 2000 through March 2002. For Yorkshire, these proposals would result in a price reduction of approximately 10.7% on the standard domestic tariff commencing April 2000 and ending March 2001 and a nominal price freeze for the year commencing April 2001 and ending March 2002. OFGEM is expected to publish final proposals on both the distribution and the supply businesses at the end of November 1999. Yorkshire management intends to take all available opportunities to increase revenues and reduce costs to mitigate the impact of the final OFGEM distribution and supply price reductions. Should Yorkshire be unable to increase revenues and reduce costs in amounts sufficient to offset the impact of the OFGEM distribution and supply price reductions, AEP's equity earnings from its investment in Yorkshire will be significantly reduced in comparison to its current level of earnings. Merger As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company and Central and South West Corporation (CSW) announced plans to merge in December 1997. In 1998 the appropriate shareholder proposals for the consummation of the merger were approved. Approval of the merger has been requested from the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC) and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. On July 29, 1999 applications were made with the Federal Communication Commission to authorize the transfer of control of licenses of several CSW entities to the Company. AEP and CSW made a merger filing with the Department of Justice in July 1999. The NRC and the Arkansas Public Service Commission approved the merger in 1998. In 1998 the FERC issued an order which confirmed that a 250 megawatt 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. FERC In November, 1998 the FERC issued an order establishing hearing procedures for the merger. The 1998 FERC order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection. On May 25, 1999 AEP and CSW reached a settlement with the FERC trial staff resolving competition and rate issues relating to the merger. On July 13, 1999 AEP and CSW reached an additional settlement with the FERC trial staff resolving additional issues. The settlements were submitted to the FERC for approval. Under the terms of the settlements, AEP filed with the FERC a regional transmission organization (RTO) proposal whereby it will transfer the operation and control of AEP's bulk transmission facilities to an RTO. The settlements also cover rates for transmission services and ancillary service as well as resolving issues related to system integration agreements and confirm, subject to FERC guidance on certain elements, that the proposed generation divestiture of up to 550 megawatts of capacity will satisfy the staff's market power concerns. The hearings began on June 29, 1999 and concluded on July 19, 1999. On June 28, 1999, the Company and CSW filed a motion asking the FERC to waive the requirement for a post-hearing decision by an administrative law judge (ALJ) who presides over the merger hearing. The motion indicated that the commission could then decide the matter based on the hearing record and briefs submitted by all interested parties. On July 28, 1999, the FERC ordered the ALJ to issue an initial decision as soon as possible, but no later than November 24, 1999. The commission concluded that it needed the benefit of the ALJ's opinion and, therefore, decided not to grant the request. The procedural schedule that follows the ALJ's initial decision should allow the FERC to issue a final order in the first quarter of 2000. Louisiana On July 29, 1999 the Louisiana Public Service Commission (LPSC) approved the merger between the Company and CSW subject to final FERC approval. In granting approval, the LPSC also approved a stipulated settlement in which the Company and CSW agreed to share with SWEPCO's Louisiana customers merger savings created as a result of the merger over the eight years following its consummation. The merger savings are estimated to total more than $18 million during that eight-year period. In addition the settlement also includes: A cap on base rates for five years after consummation of the merger; Sharing of benefits from off-system sales; Establishment of conditions for affiliate transactions with other AEP and CSW subsidiaries; Provisions to ensure continued quality of service; and Provisions to hold SWEPCO's Louisiana customers harmless for adverse effects of the merger, if any. Oklahoma On May 11, 1999, the Oklahoma Corporation Commission (OCC) approved the proposed merger between the Company and CSW. The approval follows an administrative law judge's oral decision on a partial settlement between certain principal parties to the Oklahoma merger proceeding which recommended that the OCC approve the merger. The partial settlement provides for sharing of net merger savings with Oklahoma customers; no increase in Oklahoma base rates prior to January 1, 2003; filing by December 31, 2001 with the FERC an application to join a regional transmission organization; and implementing additional quality of service standards for Oklahoma retail customers. Oklahoma's share (approximately $50 million) of net merger savings over the first five years after the merger is consummated will be shared between Oklahoma customers and AEP shareholders. The partial settlement agreement includes a recommendation by the OCC staff that the OCC file with FERC indicating that it does not oppose the merger, but reserves the right to ensure that there are no adverse impacts on the Oklahoma transmission system. Certain municipal and cooperative customers have appealed the OCC's merger approval order. On October 13, 1999 this appeal was dismissed by the Oklahoma Supreme Court and the cooperative customers have since asked the OCC to dismiss their appeal. Texas On May 4, 1999, AEP and CSW announced that a stipulated settlement had been reached in Texas. The agreement builds upon an earlier settlement agreement signed by AEP, CSW and certain parties to the Texas merger proceeding. In addition to the parties that were signatories to the earlier agreement, the staff of the Public Utility Commission of Texas is a signatory to the new settlement as well as other key parties to the merger proceeding. The stipulated settlement would result in rate reductions totaling $221 million over a six-year period for Texas customers after the merger is completed. The $221 million rate reduction is composed of $84.4 million of net merger savings and $136.6 million to resolve existing issues associated with CSW operating subsidiaries' rate and fuel reconciliation proceedings in Texas. Under the terms of the settlement agreement, base rates would not be increased before January 1, 2003 or three years after the merger, whichever is later. The settlement also calls for the divestiture of a total of 1,604 megawatts of existing and proposed generating capacity within Texas. If it is determined that the divestiture can proceed immediately after the merger closes without jeopardizing pooling-of-interests accounting treatment for the merger, sale of the plants would begin no later than 90 days after the merger closes. Absent that determination, the divestiture would occur approximately two years after the merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. Other provisions in the settlement agreement provide for, among other things, accelerated stranded cost recovery, quality-of-service standards, continuation of programs for disadvantaged customers and transfer of control of bulk transmission facilities to a regional transmission organization. Hearings on the merger in Texas began August 9, 1999 and concluded on August 10, 1999. As the hearings began, settlements were reached with all but one of the parties in the case. The settling parties are all wholesale electric customers of CSW's Texas electric operating companies. The settlements call for the withdrawal of their opposition to the merger in all regulatory approval proceedings. On November 4, 1999 the Texas Commission, in its open meeting approved the application on the pending merger and the stipulated settlement announced in May. Indiana The Indiana Utility Regulatory Commission (IURC) approved a settlement agreement related to the merger on April 26, 1999. The settlement agreement resulted from an investigation of the proposed merger initiated by the IURC. The terms of the settlement agreement provide for, among other things, a sharing of net merger savings through reductions in customers' bills of approximately $67 million over eight years after the merger is completed; a one year extension through January 1, 2005 of a freeze in base rates; additional annual deposits of $5.5 million to the nuclear decommissioning trust fund for the Indiana jurisdiction for the years 2001 through 2003; quality-of-service standards; and participation in a regional transmission organization. As part of the settlement agreement, the IURC agreed not to oppose the merger in the FERC or SEC proceedings. Kentucky On April 15, 1999, in compliance with a request from the staff of the Kentucky Public Service Commission (KPSC) AEP filed an application seeking KPSC approval for the indirect change in control of Kentucky Power Company that will occur as a result of the proposed merger. Although AEP did not believe that the KPSC has the jurisdictional authority to approve the merger, AEP reached a merger settlement agreement on May 24, 1999 with key parties in Kentucky which the KPSC approved on June 14, 1999. Under the terms of the Kentucky settlement, AEP has agreed to share net merger savings with Kentucky customers; establish performance standards that will maintain or improve customer service and system reliability; and to establish rules to protect consumers and promote fair competition. The Kentucky customers' share of the net merger savings are expected to be approximately $28 million. The key parties to the Kentucky settlement agreed not to oppose the merger during the FERC or the SEC proceedings. Ohio On October 21, 1999, the Public Utilities Commission of Ohio (PUCO) issued a decision stating that it will notify the FERC that it will withdraw its opposition to the Company's pending merger with CSW and will not seek conditions on the merger. American Municipal Power - Ohio (AMP-Ohio) and AEP reached a settlement addressing outstanding issues. As part of the settlement AMP-Ohio agreed to withdraw as an intervenor in the merger process. AMP-Ohio is the nonprofit wholesale power supplier and service provider for most of Ohio's 84 community-owned public power systems, two West Virginia public power systems and four Pennsylvania public power systems. Other AEP and CSW have reached settlements with the Missouri Commission, the International Brotherhood of Electrical Workers (IBEW), representing employees of AEP and CSW, and the Utility Worker's Union of America (UWUA) representing AEP employees, and certain wholesale customers. All have agreed not to oppose the merger in the FERC or SEC proceedings. The proposed merger of CSW into AEP would result in common ownership of two United Kingdom (UK) regional electricity companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50% ownership interest in Yorkshire and CSW has a 100% interest in Seeboard. Although the merger of CSW into AEP is not subject to approval by UK regulatory authorities, the common ownership of two UK RECs could be referred by the UK Secretary of State for Trade and Industry to the UK Competition Commission (formerly Monopolies and Mergers Commission) for review and investigation. Completion of the Merger As of September 30, 1999, AEP had deferred $37 million of costs related to the merger on its consolidated balance sheet, which will be charged to expense if AEP and CSW are not successful in completing their proposed merger. If the merger is consummated the deferred costs allocable to the regulated electric operating subsidiaries will be amortized over their recovery period, generally 5-years, in accordance with state regulator orders. The remainder of the deferred merger costs will be expensed upon consummation of the merger. The merger is conditioned upon, among other things, the approval of certain state and federal regulatory agencies. The transaction must satisfy many conditions, a number of which may not be waived by the parties, including the condition that the merger must be accounted for as a pooling of interests. The merger agreement will terminate on December 31, 1999 unless extended for six months by either party as provided in the merger agreement. 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. Cook Nuclear Plant Shutdown As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, both units of the Cook Plant were shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a NRC architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. In 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The NRC senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The Company's plan to restart the Cook Plant units has Unit 2 scheduled to return to service in April 2000 and Unit 1 to return to service in September 2000. The restart plan was developed based upon a comprehensive systems readiness review of all operating systems at the Cook Plant. When maintenance and other activities required for restart are complete, the Company will seek concurrence from the NRC to return the Cook Plant to service. Management intends to replace the steam generator for Unit 1 before the unit is returned to service. Costs associated with the steam generator replacement are estimated to be approximately $165 million, which will be accounted for as a capital investment unrelated to the restart. At September 30, 1999, $82 million has been spent on the steam generator replacement. The cost of electricity supplied to retail customers increased due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal-based purchased power is being substituted for the unavailable low cost nuclear generation. Actual replacement energy fuel costs that exceeded the costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. On March 30, 1999 the IURC approved a settlement agreement that resolves all matters related to the recovery of replacement energy fuel costs and all outage/restart issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a billing credit of $55 million, including interest, to Indiana retail customers' bills; the deferral of unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including a $52.3 million revenue portion of the $55 million billing credit; the deferral of up to $150 million of incremental operation and maintenance costs in 1999 for Cook Plant above the amount included in base rates; the amortization of the deferred fuel and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit was applied to retail customers' bills during the months of July, August and September 1999. In June 1999 the Company announced that a settlement agreement for two open Michigan power supply cost recovery reconciliation cases had been reached with the staff of the Michigan Public Service Commission (MPSC). The proposed settlement agreement would limit the Company's ability to increase base rates and freeze power supply costs for five years, allow for the amortization of deferred power supply cost for 1997, 1998 and 1999 over five years, allow for the deferral and amortization of non-fuel nuclear operation and maintenance expenses over five years and resolve all issues related to the Cook Plant extended restart outage. The pending Michigan settlement limits deferrals to $50 million of 1999 jurisdictional non-fuel nuclear operation and maintenance costs. Hearings have been held to give the one intervenor who opposed the approval of the settlement agreement the opportunity to voice its objections. The settlement agreement is pending before the MPSC. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as a current period operation and maintenance expense in 1999 and 2000. Through September 30, 1999, $280 million has been spent, of which $196 million was incurred in 1999. Pursuant to the Indiana settlement agreement $112.5 million of incremental operation and maintenance costs were deferred for the nine months ended September 30, 1999. The Indiana jurisdiction deferral is limited to up to $150 million of incremental restart costs incurred in 1999. The amortization of such costs through September 30, 1999 was $22.5 million. At September 30, 1999, the unamortized balance of incremental restart related operation and maintenance costs was $90 million and was included in regulatory assets. Also deferred as a regulatory asset at September 30, 1999 was $148 million of replacement energy fuel costs. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations, cash flows, and possibly financial condition through 2003. Management believes that the Cook units will be successfully returned to service by April and September 2000, 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. Restructuring Legislation Virginia In March 1999 a law was enacted in Virginia to restructure the electric utility industry. Under the restructuring law a transition to choice of electricity supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission that an effective competitive market exists, on January 1, 2004. The law also provides an opportunity for recovery of just and reasonable net stranded generation costs. Stranded costs are those costs above market including generation related regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001 and the establishment of a wires charge by the fourth quarter of 2001. Management has concluded that as of September 30, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates and the wires charge as provided in the law. The establishment of capped rates and the wires charge should enable the Company to determine its ability to recover stranded costs, a requirement to discontinue application of SFAS 71. When the capped rates and the wires charge are established in Virginia, the application of SFAS 71 will be discontinued for the Virginia retail jurisdiction portion of the Company's generating business. At that time the Company will have to write-off its generation-related regulatory assets to the extent that they cannot be recovered under capped rates and wire charges approved by the Virginia SCC under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of impaired assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of capped rates, wires charges and other pertinent information, it is not possible at this time to determine if any generation related assets are impaired in accordance with SFAS 121 and if generation related regulatory assets will be recovered. The amount of regulatory assets recorded on the books applicable to the Company's Virginia generating business at September 30, 1999 is estimated to be $60 million before related tax effects. Should it not be possible under the Virginia law to recover all or a portion of the generation related regulatory assets and/or tangible generating assets, it could have a material adverse impact on results of operations. An estimated determination of whether the Company will experience any asset impairment loss regarding its Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation related regulatory assets and other transition costs cannot be made until such time as the transition capped rates and the wires charge are determined under the law which is expected to be no later than the fourth quarter of 2000. Ohio The Ohio Electric Restructuring Act of 1999 became law on October 4, 1999. The law provides for customer choice of electricity supplier, a residential rate reduction of 5% and a freezing of the unbundled generation base rates and a freezing of fuel rates beginning on January 1, 2001. The law also provides for a five-year transition period to transition from cost based rates to market pricing for generation services. It authorizes the PUCO to address certain major transition issues including unbundling of rates and the recovery of regulatory assets including any unrecovered deferred fuel costs, stranded plant and mining costs and other transition costs. Retail electric services that will be competitive are defined in the law as electric generation service, aggregation service, and power marketing and brokering. Under the legislation the PUCO is granted broad oversight responsibility and is required by the law to promulgate rules for competitive retail electric generation service. The law also gives the PUCO authority to approve a transition plan for each electric utility company. The law provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled frozen generation rates paid through December 31, 2005 by customers who do not switch generation suppliers and through a wires charge for customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Recovery of transition costs can, under certain circumstances, extend beyond the five-year frozen rate transition period but cannot continue beyond December 31, 2010. The Company must file a transition plan with the PUCO by January 3, 2000 and the PUCO is required to issue a transition order no later than October 31, 2000. The law also provides that the property tax assessment percentage on electric generation property be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on kilowatt-hours sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year, deferred as a prepaid expense and amortized to expense during the tax year pursuant to the tax laws whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. The change in the tax law to impose an excise tax based on kilowatt-hours sold to Ohio customers commencing before the expiration of the gross receipts tax privilege period will result in a 12 month period when electric utilities are recording as an expense both the gross receipts tax and the excise tax. Management intends to seek recovery of the overlap of the gross receipts and excise taxes in the Ohio transition plan filing. As discussed in Note 3, "Effects of Regulation and Phase-In Plans," of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company defers as regulatory assets and liabilities certain expenses and revenues consistent with the regulatory process in accordance with SFAS 71. Management has concluded that as of September 30, 1999 the requirements to apply SFAS 71 continue to be met since the Company's rates for generation will continue to be cost-based regulated until the establishment of unbundled frozen generation rates and a wires charge as provided in the law. The establishment of unbundled frozen generation rates and the wires charge should enable the Company to determine its ability to recover transition costs including regulatory assets and other stranded costs, a requirement to discontinue application of SFAS 71. When unbundled generation rates and the wires charge are established, the application of SFAS 71 will be discontinued for the Ohio retail jurisdiction portion of the generation business. At that time the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the unbundled frozen generation rates and distribution wires charges approved by the PUCO under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121. An impairment loss would be recorded to the extent that the cost of generation assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of an unbundled frozen generation rate, the wires charge and other pertinent information, it is not possible at this time to determine if any of the Company's generating assets are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books at September 30, 1999 applicable to the Ohio retail jurisdictional generating business is $638 million before related tax effects. Due to the planned closing of affiliated mines including the Meigs mine, and other anticipated events, generation-related regulatory assets as of December 31, 2000 allocable to the Ohio retail jurisdiction are estimated to exceed $800 million, before federal income tax effects. Recovery of these regulatory assets will be sought as a part of the Company's Ohio transition plan filing. An estimated 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 such time as the unbundled frozen generation rates and the wires charge are determined through the regulatory process. Management will seek full recovery of generation-related regulatory assets, any stranded costs and other transition costs in its transition plan filing. The PUCO is required to complete its regulatory process and issue a transition order establishing the transition rates and wires charges by no later than October 31, 2000. Should the PUCO fail to approve transition rates and wires charges that are sufficient to recover the Company's generation-related regulatory assets, any other stranded costs and transition costs, it could have a material adverse effect on results of operations, cash flows and financial condition. COLI Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $317 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the Company's generating plants are located. A number of utilities, including the Company, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $1.5 billion for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through regulated rates, and where generation is being deregulated unbundled generation transition rates, wires charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Muskingum River, Mitchell, Philip Sporn, Tanners Creek and Cardinal plants over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at these same plants as well as Conesville Plant. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders including a Notice of Violation issued to The Cincinnati Gas & Electric Company for Beckjord Plant alleging violations of the New Source Review provisions of the Clean Air Act. Columbus Southern Power Company owns a partial interest in Unit 6 of Beckjord Plant. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Philip Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River Plant, Gavin Plant, Cardinal Plant, Clinch River Plant, Kanawha River Plant, Tanners Creek Plant, Amos Plant and Big Sandy Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where states are deregulating generation, approved unbundled transition generation rates, wires charges and future market prices for energy. Market Risks The Company has certain market risks inherent in its business activities from changes in electricity commodity prices, foreign currency exchange rates and interest rates. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices, foreign currency exchange rates and interest rates. The Company's exposure to market risk from the trading of electricity, natural gas and related financial derivative instruments has not changed materially since December 31, 1998. There have been no material changes to the Company's exposure to fluctuation in foreign currency exchange rates related to foreign ventures and investments since December 31, 1998. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at September 30, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness and has been meeting with key vendors in this connection. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. AEP, along with other electric utilities in North America, has submitted information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reported summary information to the DOE regarding the Y2K readiness of electric utilities. The fourth and final NERC report, dated August 3, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - A Status Report and Work Plan, Second Quarter 1999 states that: "Mission-critical component testing indicates that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages caused by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. NERC has classified AEP as a "Y2K Ready" organization with respect to its electric systems. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities also participated in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The drill gave electric utilities in North America an opportunity to test how workers would respond in emergency situations, such as an outage at a major power plant or loss of the normal communications system. The drill did not reveal any major problems or issues for AEP. Through the Electric Power Research Institute, AEP is participating in an electric utility industry-wide effort that has been established to deal with Y2K problems affecting embedded systems. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. Except for AEP's Louisiana gas operations and CitiPower, AEP has completed the process of modifying, replacing or retiring and testing its mission critical and high priority digital-based systems with problems processing dates in the Year 2000. The mission critical systems for the Louisiana gas operations are expected to be ready by December 10, 1999 and the mission critical systems for CitiPower are expected to be ready by November 30, 1999. The Company has upgraded its meteorological reporting system used at the Donald C. Cook Nuclear Plant, a mission critical IT system, for Y2K readiness. It was originally anticipated that the upgrade was to have been completed by December 15, 1999. Costs to Address the Company's Y2K Issues - Through September 30, 1999, the Company has spent $41 million on the Y2K project and estimates spending an additional $7 million to $15 million to achieve Y2K readiness. Most Y2K costs are for software, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. The cost of becoming Y2K ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restorable in a reasonable period of time. CitiPower operates under a legal and regulatory system which may expose it to customer claims for service interruptions and/or power quality problems resulting from Y2K problems. Such claims differ from claims under the US legal and regulatory system. In addition, although the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Y2K-related issues could materially adversely affect AEP. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a Y2K contingency plan and submitted it to the East Central Area Reliability Council (ECAR) as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company has established detailed contingency plans for its business units to address alternatives if Y2K related failures occur, including an operating plan which is coordinated with other ECAR member utilities. These contingency plans will be refined by the end of 1999. AEP's Y2K contingency plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, in order to place key employees on duty at those locations during the Y2K transition. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $57,235 $59,262 $161,674 $167,596 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 28,556 27,953 68,983 71,718 Rent - Rockport Plant Unit 2 . . . . . 17,071 17,071 51,212 51,212 Other Operation. . . . . . . . . . . . 2,447 2,174 7,909 7,547 Maintenance. . . . . . . . . . . . . . 1,457 2,703 8,208 9,110 Depreciation . . . . . . . . . . . . . 5,459 5,405 16,382 16,229 Taxes Other Than Federal Income Taxes. 1,398 882 3,890 2,759 Federal Income Tax Expense (Credit). . (74) 845 807 2,562 TOTAL OPERATING EXPENSES . . . 56,314 57,033 157,391 161,137 OPERATING INCOME . . . . . . . . . . . . 921 2,229 4,283 6,459 NONOPERATING INCOME. . . . . . . . . . . 885 837 2,630 2,457 INCOME BEFORE INTEREST CHARGES . . . . . 1,806 3,066 6,913 8,916 INTEREST CHARGES . . . . . . . . . . . . 848 903 2,119 2,494 NET INCOME . . . . . . . . . . . . . . . $ 958 $ 2,163 $ 4,794 $ 6,422 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $4,460 $2,435 $2,770 $2,528 NET INCOME . . . . . . . . . . . . . . . 958 2,163 4,794 6,422 CASH DIVIDENDS DECLARED. . . . . . . . . 2,073 2,176 4,219 6,528 BALANCE AT END OF PERIOD . . . . . . . . $3,345 $2,422 $3,345 $2,422 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)
September 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production. . . . . . . . . . . . . . . . . . . . . . . . $627,950 $630,260 General . . . . . . . . . . . . . . . . . . . . . . . . . 1,941 2,009 Construction Work in Progress . . . . . . . . . . . . . . 7,524 4,191 Total Electric Utility Plant. . . . . . . . . . . 637,415 636,460 Accumulated Depreciation. . . . . . . . . . . . . . . . . 289,255 277,855 NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 348,160 358,605 CURRENT ASSETS: Cash and Cash Equivalents . . . . . . . . . . . . . . . . 1,988 232 Accounts Receivable . . . . . . . . . . . . . . . . . . . 22,122 22,894 Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 19,174 11,308 Materials and Supplies. . . . . . . . . . . . . . . . . . 3,920 3,900 Prepayments . . . . . . . . . . . . . . . . . . . . . . . 33 267 TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 47,237 38,601 REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 5,804 5,984 DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 1,741 702 TOTAL . . . . . . . . . . . . . . . . . . . . . $402,942 $403,892 See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (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 . . . . . . . . . . . . . . . . . . . . . 29,235 35,235 Retained Earnings . . . . . . . . . . . . . . . . . . . . 3,345 2,770 Total Common Shareholder's Equity . . . . . . . . 33,580 39,005 Long-term Debt. . . . . . . . . . . . . . . . . . . . . . - 44,792 TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 33,580 83,797 OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 653 896 CURRENT LIABILITIES: Long-term Debt Due Within One Year. . . . . . . . . . . . 44,798 - Short-term Debt - Notes Payable . . . . . . . . . . . . . 13,825 24,450 Accounts Payable: General . . . . . . . . . . . . . . . . . . . . . . . . 5,209 6,419 Affiliated Companies. . . . . . . . . . . . . . . . . . 14,277 6,177 Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 6,146 3,227 Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 23,427 4,963 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 3,775 6,023 TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 111,457 51,259 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 129,152 133,330 REGULATORY LIABILITIES: Deferred Investment Tax Credits . . . . . . . . . . . . . 64,046 66,562 Deferred Amounts Due to Customers for Income Tax. . . . . 26,910 28,644 TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 90,956 95,206 DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 37,144 39,404 TOTAL . . . . . . . . . . . . . . . . . . . . . $402,942 $403,892 See Notes to Financial Statements.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 4,794 $ 6,422 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . . 16,382 16,229 Deferred Federal Income Taxes. . . . . . . . . . . . . . (3,994) 3,975 Deferred Investment Tax Credits. . . . . . . . . . . . . (2,516) (2,522) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2. . . . . . . . . (4,178) (4,178) Deferred Property Taxes. . . . . . . . . . . . . . . . . (827) (794) Changes in Certain Current Assets and Liabilities: Accounts Receivable. . . . . . . . . . . . . . . . . . . 772 (1,964) Fuel, Materials and Supplies . . . . . . . . . . . . . . (7,886) (1,870) Accounts Payable . . . . . . . . . . . . . . . . . . . . 6,890 3,522 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,919 1,331 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464 Other (net). . . . . . . . . . . . . . . . . . . . . . . . (2,549) 1,968 Net Cash Flows From Operating Activities . . . . . . 28,271 40,583 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (5,671) (4,829) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . - 2,254 Net Cash Flows Used For Investing Activities . . . . (5,671) (2,575) FINANCING ACTIVITIES: Return of Capital to Parent Company. . . . . . . . . . . . (6,000) (3,000) Retirement of Long-term Debt . . . . . . . . . . . . . . . - (25,000) Change in Short-term Debt (net). . . . . . . . . . . . . . (10,625) (3,575) Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (4,219) (6,528) Net Cash Flows Used For Financing Activities . . . . (20,844) (38,103) Net Increase (Decrease) in Cash and Cash Equivalents . . . . 1,756 (95) Cash and Cash Equivalents at Beginning of Period . . . . . . 232 237 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,988 $ 142 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $1,889,000 and $2,508,000 and for income taxes was $4,458,000 and $(1,188,000) in 1999 and 1998, respectively. See Notes to Financial Statements.
AEP GENERATING COMPANY NOTES TO FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES Under the terms of installment purchase contracts, the Company is required to pay the City of Rockport amounts sufficient to enable the payment of interest and principal on pollution control revenue bonds issued to finance the construction costs of pollution control facilities at the Rockport Plant. On the Series 1995 A and B bonds the principal is payable at maturity (July 1, 2025) or on the demand of the bondholders. The Company has agreements that provide for brokers to remarket bonds tendered. In the event the bonds cannot be remarketed, the Company has a standby bond purchase agreement with a bank that provides for the bank to purchase any bonds not remarketed. The purchase agreement expires in 2000. Therefore, the installment purchase contracts have been classified as due within one year. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies and 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. Net income decreased $1.2 million or 56% for the third quarter and $1.6 million or 25% for the year-to-date period as a result of the return of capital to the parent company in 1998, February 1999 and May 1999 and the reduction of revenues under the long-term power agreement. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $(2.0) (3) $(5.9) (4) Fuel Expense. . . . . . . . 0.6 2 (2.7) (4) Other Operation Expense . . 0.3 13 0.4 5 Maintenance Expense . . . . (1.2) (46) (0.9) (10) Taxes Other Than Federal Income Taxes . . . . . . . 0.5 59 1.1 41 Federal Income Taxes. . . . (0.9) (109) (1.8) (69) Interest Charges. . . . . . (0.1) (6) (0.4) (15) The decrease in operating revenues for the third quarter results from the recovery through the unit power agreements of less return on common equity reflecting the return of capital and less return on other capital reflecting lower interest charges due to the retirement of debt. In the year-to-date period, operating revenues declined reflecting the lower returns on common equity and other capital and a reduction in recoverable operating expenses. Fuel expense increased in the third quarter due to increases in generation and average cost of fuel. The increase in generation is attributable to an increase in the availability of the Rockport Plant units. The rise in the cost of fuel results from fluctuations in the market price of coal. In the year-to-date period a 6% reduction in generation, due to planned maintenance outages in the first and second quarters of 1999 at both units, reduced fuel expense. The increase in other operation expense in both the quarter and year-to-date periods is primarily due to the effect of unfavorable accrual adjustments for a FERC operating assessment and allocated employee benefits. Maintenance expense decreased due to a decline in maintenance repair and staff expenditures reflecting the effect of staffing reductions. Taxes other than federal income taxes increased due to an increase in state income taxes which resulted from an increase in taxable income due to the completion of state tax depreciation for Rockport Plant Unit 1. Federal income taxes attributable to operations decreased due to a decrease in pre-tax operating income and the amortization of deferred taxes in excess of the statutory tax rate. The decline in interest charges in the year-to-date period was primarily due to a reduction in outstanding long-term debt balances reflecting the redemption of $25 million in March 1998 of pollution control revenue bonds. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $441,435 $474,476 $1,242,903 $1,292,922 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 108,701 113,059 331,933 322,459 Purchased Power. . . . . . . . . . . . 93,041 101,779 204,680 258,275 Other Operation. . . . . . . . . . . . 59,090 73,988 182,001 191,297 Maintenance. . . . . . . . . . . . . . 26,240 30,691 93,112 97,519 Depreciation and Amortization. . . . . 37,700 36,059 111,475 107,252 Taxes Other Than Federal Income Taxes. 29,201 29,003 89,242 89,181 Federal Income Taxes . . . . . . . . . 21,153 18,946 49,445 45,547 TOTAL OPERATING EXPENSES . . . 375,126 403,525 1,061,888 1,111,530 OPERATING INCOME . . . . . . . . . . . . 66,309 70,951 181,015 181,392 NONOPERATING INCOME (LOSS) . . . . . . . 1,925 (5,664) 1,152 (4,490) INCOME BEFORE INTEREST CHARGES . . . . . 68,234 65,287 182,167 176,902 INTEREST CHARGES . . . . . . . . . . . . 32,573 31,841 96,209 95,133 NET INCOME . . . . . . . . . . . . . . . 35,661 33,446 85,958 81,769 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 667 675 2,015 1,822 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,994 $ 32,771 $ 83,943 $ 79,947 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $167,714 $195,262 $179,461 $207,544 NET INCOME . . . . . . . . . . . . . . . 35,661 33,446 85,958 81,769 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 30,348 29,729 91,044 89,187 Cumulative Preferred Stock . . . . . 558 567 1,690 1,499 Capital Stock Expense. . . . . . . . . 109 108 325 323 BALANCE AT END OF PERIOD . . . . . . . . $172,360 $198,304 $172,360 $198,304 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)
September 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,007,970 $1,979,180 Transmission . . . . . . . . . . . . . . . . . . . . 1,139,940 1,118,726 Distribution . . . . . . . . . . . . . . . . . . . . 1,686,801 1,641,523 General. . . . . . . . . . . . . . . . . . . . . . . 240,726 228,464 Construction Work in Progress. . . . . . . . . . . . 123,378 119,466 Total Electric Utility Plant . . . . . . . . 5,198,815 5,087,359 Accumulated Depreciation and Amortization. . . . . . 2,061,813 1,984,856 NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,137,002 3,102,503 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 132,612 111,020 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 30,850 7,755 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 111,847 122,746 Affiliated Companies . . . . . . . . . . . . . . . 20,854 35,802 Miscellaneous. . . . . . . . . . . . . . . . . . . 13,400 8,572 Allowance for Uncollectible Accounts . . . . . . . (2,981) (2,234) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 56,387 49,826 Materials and Supplies . . . . . . . . . . . . . . . 62,256 60,440 Accrued Utility Revenues . . . . . . . . . . . . . . 40,576 45,985 Energy Marketing and Trading Contracts . . . . . . . 95,526 22,436 Prepayments. . . . . . . . . . . . . . . . . . . . . 9,665 8,151 TOTAL CURRENT ASSETS . . . . . . . . . . . . 438,380 359,479 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 417,551 433,516 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 27,805 40,520 TOTAL. . . . . . . . . . . . . . . . . . . $4,153,350 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 30,000,000 Shares Outstanding - 13,499,500 Shares. . . . . . . . . . $ 260,458 $ 260,458 Paid-in Capital. . . . . . . . . . . . . . . . . . . 689,099 663,633 Retained Earnings. . . . . . . . . . . . . . . . . . 172,360 179,461 Total Common Shareholder's Equity. . . . . . 1,121,917 1,103,552 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 18,575 19,359 Subject to Mandatory Redemption. . . . . . . . . . 22,310 22,310 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,439,573 1,472,451 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,602,375 2,617,672 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 133,558 120,281 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 176,005 80,004 Short-term Debt. . . . . . . . . . . . . . . . . . . 119,380 76,400 Accounts Payable - General . . . . . . . . . . . . . 48,736 60,569 Accounts Payable - Affiliated Companies. . . . . . . 34,564 50,313 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 33,944 35,719 Customer Deposits. . . . . . . . . . . . . . . . . . 12,831 14,123 Interest Accrued . . . . . . . . . . . . . . . . . . 30,245 19,990 Revenue Refunds Accrued. . . . . . . . . . . . . . . - 95,267 Energy Marketing and Trading Contracts . . . . . . . 91,941 24,076 Other. . . . . . . . . . . . . . . . . . . . . . . . 67,527 78,808 TOTAL CURRENT LIABILITIES. . . . . . . . . . 615,173 535,269 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 648,203 643,711 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 58,715 62,231 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 95,326 67,874 CONTINGENCIES (Note 6) TOTAL. . . . . . . . . . . . . . . . . . . $4,153,350 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 85,958 $ 81,769 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 112,264 108,158 Deferred Federal Income Taxes. . . . . . . . . . . . . . 10,947 (1,452) Deferred Investment Tax Credits. . . . . . . . . . . . . (3,516) (3,548) Provision for Rate Refunds . . . . . . . . . . . . . . . 5,139 9,342 Deferred Power Supply Costs (net). . . . . . . . . . . . 27,715 25,137 Amortization of Deferred Property Taxes. . . . . . . . . 13,302 12,940 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 21,766 3,840 Fuel, Materials and Supplies . . . . . . . . . . . . . . (8,377) (7,025) Accrued Utility Revenues . . . . . . . . . . . . . . . . 5,409 10,578 Accounts Payable . . . . . . . . . . . . . . . . . . . . (27,582) (16,191) Revenue Refunds Accrued. . . . . . . . . . . . . . . . . (95,267) 39,107 Payment of Disputed Tax and Interest Related to COLI . . . (4,124) (68,316) Other (net). . . . . . . . . . . . . . . . . . . . . . . . (22,882) 24,056 Net Cash Flows From Operating Activities . . . . . . 120,752 218,395 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (134,645) (138,297) Proceeds from Sale of Property . . . . . . . . . . . . . . 274 914 Net Cash Flows Used For Investing Activities . . . . (134,371) (137,383) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . 25,000 25,000 Issuance of Long-term Debt . . . . . . . . . . . . . . . . 148,751 193,431 Change in Short-term Debt (net). . . . . . . . . . . . . . 42,980 (68,325) Retirement of Cumulative Preferred Stock . . . . . . . . . (587) (229) Retirement of Long-term Debt . . . . . . . . . . . . . . . (86,687) (138,472) Dividends Paid on Common Stock . . . . . . . . . . . . . . (91,044) (89,187) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,699) (1,710) Net Cash Flows From (Used For) Financing Activities. 36,714 (79,492) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 23,095 1,520 Cash and Cash Equivalents at Beginning of Period . . . . . . 7,755 6,947 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 30,850 $ 8,467 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $83,069,000 and $83,359,000 and for income taxes was $33,996,000 and $38,378,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $12,132,000 and $16,909,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. VIRGINIA RESTRUCTURING As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, in February 1999 the Virginia legislature passed comprehensive legislation, which became law in March 1999, to restructure the electric utility industry. Under the restructuring law a transition to choice of electricity supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. The law also provides an opportunity for recovery of just and reasonable net stranded generation costs. Stranded costs are those costs above market including generation related regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001 and the establishment of a wires charge by the fourth quarter of 2001. Management has concluded that as of September 30, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates and the wires charge as provided in the law. The establishment of capped rates and the wires charge should enable the Company to determine its ability to recover stranded costs, a requirement to discontinue application of SFAS 71. When the capped rates and the wires charge are established in Virginia, the application of SFAS 71 will be discontinued for the Virginia retail jurisdiction portion of the Company's generating business. At that time the Company will have to write-off its generation-related regulatory assets to the extent that they cannot be recovered under capped rates and wire charges approved by the Virginia SCC under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of impaired assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of capped rates, wires charges and other pertinent information, it is not possible at this time to determine if any generation related assets are impaired in accordance with SFAS 121 and if generation related regulatory assets will be recovered. The amount of regulatory assets recorded on the books applicable to the Company's Virginia retail generating business at September 30, 1999 is estimated to be $60 million before related tax effects. Should it not be possible under the Virginia law to recover all or a portion of the generation related regulatory assets and/or tangible generating assets, it could have a material adverse impact on results of operations and cash flows. An estimated determination of whether the Company will experience any asset impairment loss regarding its Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation related regulatory assets and other transition costs cannot be made until such time as the transition capped rates and the wires charge are determined under the law; which is not expected to occur before the fourth quarter of 2000. 3. RATE MATTER The Federal Energy Regulatory Commission (FERC) issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission service tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 29, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers have sought rehearing of the Commission's Order. The Company made a provision in September 1999 for its share of the refund which it anticipates would result if the Commission's order is upheld including interest. 4. FINANCING ACTIVITIES In May 1999 the Company issued $150 million of 6.60% senior unsecured notes due 2009. During the first nine months of 1999, the Company reacquired the following first mortgage bonds: Principal Amount % Rate Due Date Reacquired (in thousands) 8.43 June 1, 2022 $37,471 7.80 May 1, 2023 9,763 7.90 June 1, 2023 30,000 7.15 November 1, 2023 10,000 In September 1999, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital. In October 1999 the Company issued $50 million of 7.45% senior unsecured notes due 2004. During the first nine months of 1999, the Company increased short-term debt by $43 million. 5. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for the portion of those open trading transactions within the AEP Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes in the Company's non-Virginia jurisdictions. A Virginia jurisdiction net mark-to-market pre-tax gain of $1.4 million as of September 30, 1999 is included in net income as a result of an agreed prohibition against establishing new regulatory assets in a February 1999 Virginia SCC approved settlement agreement. Open contracts outside of AEP Power Pool's marketing area are marked-to-market in non-operating income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 6. CONTINGENCIES Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $79 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management believes, and has been advised by outside counsel, that it has a meritorious position and will vigorously pursue its lawsuit. In the event the resolutions of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates , filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $410 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through regulated rates, and where generation is being deregulated unbundled generation transition rates, wires charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Philip Sporn Plant over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at this plant. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Clinch River Plant, Kanawha River Plant and Amos Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where generation is being deregulated, approved unbundled transition generation rates, wires charges and future market prices for energy. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income increased $2.2 million or 7% for the quarter and $4.2 million or 5% for the year-to-date period primarily due to an increase in sales to retail customers, a decline in operating expenses and an increase in nonoperating income. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $(33.0) (7) $(50.0) (4) Fuel Expense . . . . . . . (4.4) (4) 9.5 3 Purchased Power Expense. . (8.7) (9) (53.6) (21) Other Operation Expense. . (14.9) (20) (9.3) (5) Maintenance Expense. . . . (4.5) (15) (4.4) (5) Federal Income Taxes . . . 2.2 12 3.9 9 Nonoperating Income (Loss) 7.6 134 5.6 126 Operating revenues decreased in both the third quarter and the year-to-date periods due predominantly to a decline in wholesale power sales margins and a revenue refund provision for wholesale transmission service. Also contributing to the year-to-date decrease in wholesale revenues was the termination of a contract with several municipal customers effective July 1, 1998. These decreases in wholesale power revenues and sales were partially offset by increases in retail revenues from increased energy sales to residential and commercial customers reflecting changes in the weather. Colder winter weather and warmer summer temperatures led to increased energy usage by residential and commercial customers. The decrease in fuel expense for the quarter was due to a lower average cost of fuel consumed and a reduction in the over recovery of power supply costs in the West Virginia retail jurisdiction through the operation of the West Virginia power supply cost recovery mechanism, partially offset by increased fuel consumed for additional generation. A decline in the market price of coal accounted for the decrease in the average cost of fuel consumed. Pursuant to the West Virginia retail jurisdictional power supply cost recovery mechanism, over collections of power supply costs are deferred for future refund to customers through a charge to fuel expense. The over recovery of West Virginia non-fuel power supply costs declined in the third quarter primarily due to the decreased wholesale energy sales and margins on off-system sales included in the West Virginia power supply cost recovery mechanism. Also in the third quarter, fuel expense rose due to increased coal fired generation to meet the increased retail demand resulting from the warmer summer weather. In the year-to-date period, fuel expense rose primarily due to increased coal fired generation to meet the increased retail demand resulting from the first quarter's colder winter weather and the warmer summer weather. Purchased power expense decreased primarily as a result of decreased purchases from the American Electric Power (AEP) System Power Pool (AEP Power Pool), reflecting increased generation, and a decline in capacity charges paid to the AEP Power Pool. Under the terms of the AEP Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. The Company pays net capacity charges to the AEP Power Pool because its peak demand is greater than its internal generating capacity. The decrease in capacity charges was attributed to a decrease in the Company's prior twelve month peak demand relative to the total peak demand of all AEP Power Pool members. The reduction in other operation expense was mainly due to cost savings from staff reductions and reduced accruals and adjustments for incentive compensation and liability insurance. Maintenance expense decreased in the third quarter mainly as a result of an adjustment to the cost of materials used for power plant repairs. In the year-to-date period, the decline in maintenance expense was due to significant costs incurred in 1998 for repair and restoration of distribution service caused by two severe snowstorms. Federal income tax expense attributable to operations increased primarily due to changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes which were partially offset in the quarter by a decrease in pre-tax operating income. The increase in nonoperating income is primarily due to the effect of losses in 1998 on certain power marketing and trading transactions. These transactions, which are marked-to-market, represent non-regulated trading activities outside the Company's traditional marketing area. FINANCIAL CONDITION Total plant and property additions including capital leases for the first nine months of 1999 were $147 million. During the first nine months of 1999, the Company issued one series of senior unsecured notes of $150 million with a rate of 6.60% due in 2009 and redeemed $87 million principal amount of first mortgage bonds with interest rates from 7.15% to 8.43%. Short-term debt increased by $43 million from year-end balances. In September 1999, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital. In October 1999 the Company issued $50 million of 7.45% senior unsecured notes due 2004. OTHER MATTERS Virginia Restructuring As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, in February 1999 the Virginia legislature passed comprehensive legislation, which became law in March 1999, to restructure the electric utility industry. Under the restructuring law a transition to choice of electricity supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. The law also provides an opportunity for recovery of just and reasonable net stranded generation costs. Stranded costs are those costs above market including generation related regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of rates until as late as July 1, 2007, and the application of a wires charge upon customers who depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001 and the establishment of a wires charge by the fourth quarter of 2001. Management has concluded that as of September 30, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates and the wires charge as provided in the law. The establishment of capped rates and the wires charge should enable the Company to determine its ability to recover stranded costs, a requirement to discontinue application of SFAS 71. When the capped rates and the wires charge are established in Virginia, the application of SFAS 71 will be discontinued for the Virginia retail jurisdiction portion of the Company's generating business. At that time the Company will have to write-off its generation-related regulatory assets to the extent that they cannot be recovered under capped rates and wires charges approved by the Virginia SCC under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of impaired assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of capped rates, wires charges and other pertinent information, it is not possible at this time to determine if any generation related assets are impaired in accordance with SFAS 121 and if generation related regulatory assets will be recovered. The amount of regulatory assets recorded on the books applicable to the Company's Virginia retail generating business at September 30, 1999 is estimated to be $60 million before related tax effects. Should it not be possible under the Virginia law to recover all or a portion of the generation related regulatory assets and/or tangible generating assets, it could have a material adverse impact on results of operations and cash flows. An estimated determination of whether the Company will experience any asset impairment loss regarding its Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation related regulatory assets and other transition costs cannot be made until such time as the transition capped rates and the wires charge are determined under the law; which is not expected to occur before the fourth quarter of 2000. COLI Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $79 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management believes, and has been advised by outside counsel, that it has a meritorious position and will vigorously pursue its lawsuit. In the event the resolutions of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates , filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $410 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through regulated rates, and where generation is being deregulated unbundled generation transition rates, wires charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Philip Sporn Plant over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at this plant. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Clinch River Plant, Kanawha River Plant and Amos Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates, and where generation is being deregulated, approved unbundled transition generation rates, wires charges and future market prices for energy. Market Risks The Company has certain market risks inherent in its business activities 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, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at September 30, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness and has been meeting with key vendors in this connection. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The AEP System, along with other electric utilities in North America, has submitted information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reported summary information to the U.S. Department of Energy (DOE) regarding the Y2K readiness of electric utilities. The fourth and final NERC report, dated August 3, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - A Status Report and Work Plan, Second Quarter 1999, states that: "Mission-critical component testing indicates that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages caused by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. NERC has classified the AEP System as a "Y2K Ready" organization with respect to its electric systems. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities also participated in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The drill gave electric utilities in North America an opportunity to test how workers would respond in emergency situations, such as an outage at a major power plant or loss of the normal communications system. The drill did not reveal any major problems or issues for AEP. Through the Electric Power Research Institute, AEP is participating in an electric utility industry-wide effort that has been established to deal with Y2K problems affecting embedded systems. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The AEP System has completed the process of modifying, replacing, retiring and testing those mission critical and high priority digital-based systems with problems processing dates in the Year 2000. Costs to Address the Company's Year 2000 Issues - Through September 30, 1999, the Company has spent $12 million on the Y2K project and, estimates spending an additional $2 million to $4 million to achieve Y2K readiness. Most Y2K costs are for software modifications, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. The Company has benefited from the sharing of costs with its affiliates in the AEP System. The cost of becoming Y2K ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restored. In addition, although relationships with third parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others who impact the AEP System's operations but are not affiliated with the AEP System, fail for critical applications, Y2K-related issues could materially adversely affect the Company. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a Y2K contingency plan and submitted it to the East Central Area Reliability Council (ECAR) as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company has established detailed contingency plans for its business units to address alternatives if Y2K related failures occur, including an operating plan which is coordinated with other ECAR member utilities. These contingency plans will be refined by the end of 1999. The Company's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, in order to place key employees on duty at those locations during the Y2K transition. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $368,946 $361,405 $949,432 $926,067 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 44,416 49,693 139,416 143,533 Purchased Power. . . . . . . . . . . . 90,272 80,210 204,718 186,829 Other Operation. . . . . . . . . . . . 46,829 59,478 139,312 150,843 Maintenance. . . . . . . . . . . . . . 16,693 13,932 49,013 43,128 Depreciation . . . . . . . . . . . . . 23,723 22,760 70,429 68,454 Taxes Other Than Federal Income Taxes. 31,558 29,295 92,687 86,921 Federal Income Taxes . . . . . . . . . 31,977 31,774 69,859 69,716 TOTAL OPERATING EXPENSES . . . 285,468 287,142 765,434 749,424 OPERATING INCOME . . . . . . . . . . . . 83,478 74,263 183,998 176,643 NONOPERATING LOSS. . . . . . . . . . . . (1,076) (2,337) (1,193) (1,109) INCOME BEFORE INTEREST CHARGES . . . . . 82,402 71,926 182,805 175,534 INTEREST CHARGES . . . . . . . . . . . . 18,683 19,635 57,109 58,856 NET INCOME . . . . . . . . . . . . . . . 63,719 52,291 125,696 116,678 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 533 532 1,598 1,598 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 63,186 $ 51,759 $124,098 $115,080 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $203,354 $160,171 $186,441 $138,172 NET INCOME . . . . . . . . . . . . . . . 63,719 52,291 125,696 116,678 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 21,999 20,661 65,997 61,983 Cumulative Preferred Stock . . . . . 437 437 1,312 1,312 Capital Stock Expense. . . . . . . . . 95 95 286 286 BALANCE AT END OF PERIOD . . . . . . . . $244,542 $191,269 $244,542 $191,269 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)
September 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,537,121 $1,526,869 Transmission . . . . . . . . . . . . . . . . . . . . 349,376 339,934 Distribution . . . . . . . . . . . . . . . . . . . . 987,274 938,283 General. . . . . . . . . . . . . . . . . . . . . . . 139,565 130,002 Construction Work in Progress. . . . . . . . . . . . 106,534 118,477 Total Electric Utility Plant . . . . . . . . 3,119,870 3,053,565 Accumulated Depreciation . . . . . . . . . . . . . . 1,194,857 1,134,348 NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,925,013 1,919,217 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 92,441 73,088 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 8,735 7,206 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 88,401 89,522 Affiliated Companies . . . . . . . . . . . . . . . 29,312 17,966 Miscellaneous. . . . . . . . . . . . . . . . . . . 8,732 11,989 Allowance for Uncollectible Accounts . . . . . . . (3,900) (2,598) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 21,762 22,140 Materials and Supplies . . . . . . . . . . . . . . . 39,918 33,263 Accrued Utility Revenues . . . . . . . . . . . . . . 45,203 40,127 Energy Marketing and Trading Contracts . . . . . . . 59,865 12,670 Prepayments and Other Current Assets . . . . . . . . 29,641 29,084 TOTAL CURRENT ASSETS . . . . . . . . . . . . 327,669 261,369 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 342,000 353,369 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 15,989 74,647 TOTAL. . . . . . . . . . . . . . . . . . . $2,703,112 $2,681,690 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (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. . . . . . . . . . . . . . . . . . . 572,777 572,492 Retained Earnings. . . . . . . . . . . . . . . . . . 244,542 186,441 Total Common Shareholder's Equity. . . . . . 858,345 799,959 Cumulative Preferred Stock - Subject to Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000 Long-term Debt . . . . . . . . . . . . . . . . . . . 924,412 959,786 TOTAL CAPITALIZATION . . . . . . . . . . . . 1,807,757 1,784,745 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 44,670 42,176 CURRENT LIABILITIES: Short-term Debt. . . . . . . . . . . . . . . . . . . 28,200 52,500 Accounts Payable - General . . . . . . . . . . . . . 32,603 34,631 Accounts Payable - Affiliated Companies. . . . . . . 44,054 37,132 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 99,297 141,831 Interest Accrued . . . . . . . . . . . . . . . . . . 23,139 14,355 Energy Marketing and Trading Contracts . . . . . . . 57,608 13,682 Other. . . . . . . . . . . . . . . . . . . . . . . . 33,485 37,197 TOTAL CURRENT LIABILITIES. . . . . . . . . . 318,386 331,328 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 442,198 442,100 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 46,105 48,710 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 43,996 32,631 CONTINGENCIES (Note 6) TOTAL. . . . . . . . . . . . . . . . . . . $2,703,112 $2,681,690 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 125,696 $ 116,678 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . 70,727 68,617 Deferred Federal Income Taxes. . . . . . . . . . . . . . 7,854 12,398 Deferred Investment Tax Credits. . . . . . . . . . . . . (2,605) (2,662) Deferred Fuel Costs (net). . . . . . . . . . . . . . . . 3,765 (10,169) Amortization of Deferred Property Taxes. . . . . . . . . 51,680 48,775 Changes in Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (5,666) (18,967) Fuel, Materials and Supplies . . . . . . . . . . . . . . (6,277) 879 Accrued Utility Revenues . . . . . . . . . . . . . . . . (5,076) 1,228 Accounts Payable . . . . . . . . . . . . . . . . . . . . 4,894 (19,234) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (42,534) (36,055) Interest Accrued . . . . . . . . . . . . . . . . . . . . 8,784 10,029 Other Current Assets and Current Liabilities . . . . . . (7,538) 10,114 Payment of Disputed Tax and Interest Related to COLI . . . (2,239) (37,243) Other (net). . . . . . . . . . . . . . . . . . . . . . . . 2,634 16,799 Net Cash Flows From Operating Activities . . . . . . 204,099 161,187 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (75,933) (84,178) Proceeds from Sale of Property and Other . . . . . . . . . 495 2,546 Net Cash Flows Used For Investing Activities . . . . (75,438) (81,632) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 111,075 Change in Short-term Debt (net). . . . . . . . . . . . . . (24,300) (11,250) Retirement of Long-term Debt . . . . . . . . . . . . . . . (35,523) (122,206) Dividends Paid on Common Stock . . . . . . . . . . . . . . (65,997) (61,983) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,312) (1,312) Net Cash Flows Used For Financing Activities . . . . (127,132) (85,676) Net Increase (Decrease) in Cash and Cash Equivalents . . . . 1,529 (6,121) Cash and Cash Equivalents at Beginning of Period . . . . . . 7,206 12,626 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,735 $ 6,505 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $45,659,000 and $46,014,000 and for income taxes was $41,866,000 and $27,254,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $5,573,000 and $10,029,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES During the first nine months of 1999 the Company redeemed $20 million of 7.45% first mortgage bonds due in 2024, $9 million of 7.60% first mortgage bonds due in 2024 and $7 million of 7.75% first mortgage bonds due 2023. During the first nine months of 1999, the Company decreased short-term debt by $24.3 million. The short-term debt limitation of the Company was increased from $300 million to $350 million with approval of the Securities and Exchange Commission. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions within the AEP Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes. Open contracts outside of AEP Power Pool's marketing area are marked-to-market in non-operating income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. RATE MATTERS The Federal Energy Regulatory Commission (FERC) issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission service tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 29, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers have sought rehearing of the Commission's Order. The Company made a provision in September 1999 for its share of the refund which it anticipates would result if the Commission's order is upheld including interest. 5. OHIO RESTRUCTURING LEGISLATION The Ohio Electric Restructuring Act of 1999 became law on October 4, 1999. The law provides for customer choice of electricity supplier and a residential rate reduction of 5% and a freezing of the unbundled generation base rates and a freezing of fuel rates beginning on January 1, 2001. The law also provides for a five-year transition period to transition 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 regulatory assets, stranded plant costs and other transition costs. Retail electric services that will be competitive are defined in the law as electric generation service, aggregation service, and power marketing and brokering. Under the legislation the PUCO is granted broad oversight responsibility and is required by the law to promulgate rules for competitive retail electric generation service. The law also gives the PUCO authority to approve a transition plan for each electric utility company. The law provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled frozen generation rates paid through December 31, 2005 by customers who do not switch generation suppliers and through a wires charge for customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Recovery of transition costs can, under certain circumstances, extend beyond the five-year frozen rate transition period but cannot continue beyond December 31, 2010. The Company must file a transition plan with the PUCO by January 3, 2000 and the PUCO is required to issue a transition order no later than October 31, 2000. The law also provides that the property tax assessment percentage on electric generation property be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on kilowatt-hours sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year, deferred as a prepaid expense and amortized to expense during the tax year pursuant to the tax laws whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. The change in the tax law to impose an excise tax based on kilowatt-hours sold to Ohio customers commencing before the expiration of the gross receipts tax privilege period will result in a 12 month period when electric utilities are recording as an expense both the gross receipts tax and the excise tax. Management intends to seek recovery of the overlap of the gross receipts and excise taxes in the Ohio transition plan filing. As discussed in Note 2, "Effects of Regulation and the Zimmer Phase-in Plan," of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company defers as regulatory assets and liabilities certain expenses and revenues consistent with the regulatory process in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." Management has concluded that as of September 30, 1999 the requirements to apply SFAS 71 continue to be met since the Company's rates for generation will continue to be cost-based regulated until the establishment of unbundled frozen generation rates and a wires charge as provided in the law. The establishment of unbundled frozen generation rates and the wires charge should enable the Company to determine its ability to recover transition costs including regulatory assets and other stranded costs, a requirement to discontinue application of SFAS 71. When unbundled generation rates and the wires charge are established, the application of SFAS 71 will be discontinued for the Ohio retail jurisdiction portion of the generation business. At that time the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the unbundled frozen generation rates and distribution wires charges approved by the PUCO under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of generation assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of an unbundled frozen generation rate, the wires charge and other pertinent information, it is not possible at this time to determine if any of the Company's generating assets are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books at September 30, 1999 applicable to the Ohio retail jurisdictional generating business is $311 million before related tax effects. Recovery of these regulatory assets will be sought as a part of the Company's Ohio transition plan filing. An estimated 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 such time as the unbundled frozen generation rates and the wires charge are determined through the regulatory process. Management will seek full recovery of generation-related regulatory assets, any stranded costs and other transition costs in its transition plan filing. The PUCO is required to complete its regulatory process and issue a transition order establishing the transition rates and wires charges by no later than October 31, 2000. Should the PUCO fail to approve transition rates and wires charges that are sufficient to recover the Company's generation-related regulatory assets, any other stranded costs and transition costs, it could have a material adverse effect on results of operations, cash flows and financial condition. 6. CONTINGENCIES Litigation As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $43 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the United States (U.S.) District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $175 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through PUCO approved unbundled generation transition rates, wire charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Notice of Violation On November 3, 1999, Federal EPA issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at its Conesville Plant. A number of unaffiliated utilities also received Notices of Violation or administrative orders including a Notice of Violation issued to The Cincinnati Gas & Electric Company for Beckjord Plant alleging violations of the New Source Review provisions of the Clean Air Act. The Company owns a partial interest in Unit 6 at Beckjord Plant. Federal EPA's Notice of Violation is based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed, and the cost of any required new pollution control equipment, if all of Federal EPA's contentions are upheld, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through PUCO approved unbundled generation transition rates, wires charges and the future market price for electricity. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 Net income increased $11.4 million or 22% for the third quarter and $9 million or 8% for the year-to-date period primarily due to increased sales to retail customers reflecting customer growth and in the year-to-date period colder winter weather. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $ 7.5 2 $ 23.4 3 Fuel Expense. . . . . . . . (5.3) (11) (4.1) (3) Purchased Power Expense . . 10.1 13 17.9 10 Other Operation Expense . . (12.6) (21) (11.5) (8) Maintenance Expense . . . . 2.8 20 5.9 14 Operating revenues increased in both the third quarter and the year-to-date period due predominantly to increased retail sales. The increase in retail revenues resulted from increased sales to residential and commercial customers reflecting growth in the number of customers and in the year-to-date period colder winter weather. Revenues from wholesale customers declined, due to a decline in wholesale margins, partially offsetting the retail revenue gains. The decrease in fuel expense was due to a decline in generation reflecting a decrease in availability of certain generating units in 1999 due to power plant maintenance outages. The increase in purchased power expense in the third quarter was primarily the result of increased purchases of electricity from the American Electric Power (AEP) System Power Pool (AEP Power Pool) and unaffiliated companies to replace unavailable generation and to meet the increase in demand from retail customers. In the year-to-date period, increased capacity charges from the AEP Power Pool were the primary reason for the increase in purchased power expense. Under the terms of the AEP Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. The Company pays net capacity charges to the AEP Power Pool because its peak demand is greater than its internal generating capacity. The increase in capacity charge was attributed to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all AEP Power Pool members. The reduction in other operation expense was mainly due to cost savings from staffing reductions, a reduction in bad debt expense, reduced accruals and adjustments for incentive compensation and liability insurance, and a gain on the sale of excess emission allowances. Maintenance expense increased due to tree trimming for overhead distribution lines and scheduled power plant maintenance outages in 1999. The cost of plant maintenance outages was mitigated by cost savings from planned staffing reductions. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $411,248 $412,908 $1,081,914 $1,089,647 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 51,908 51,014 135,831 133,768 Purchased Power. . . . . . . . . . . . 93,683 92,728 223,508 237,391 Other Operation. . . . . . . . . . . . 139,997 97,985 346,830 257,268 Maintenance. . . . . . . . . . . . . . 43,526 39,107 99,349 99,444 Depreciation and Amortization. . . . . 37,626 36,380 112,106 108,407 Taxes Other Than Federal Income Taxes. 12,356 16,514 48,641 49,011 Federal Income Taxes . . . . . . . . . 6,067 20,541 23,760 52,157 TOTAL OPERATING EXPENSES . . . 385,163 354,269 990,025 937,446 OPERATING INCOME . . . . . . . . . . . . 26,085 58,639 91,889 152,201 NONOPERATING INCOME (LOSS) . . . . . . . 2,407 (2,404) 5,698 191 INCOME BEFORE INTEREST CHARGES . . . . . 28,492 56,235 97,587 152,392 INTEREST CHARGES . . . . . . . . . . . . 20,408 17,544 59,688 51,421 NET INCOME . . . . . . . . . . . . . . . 8,084 38,691 37,899 100,971 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,218 1,208 3,647 3,627 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 6,866 $ 37,483 $ 34,252 $ 97,344 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $223,212 $279,943 $253,154 $278,814 NET INCOME . . . . . . . . . . . . . . . 8,084 38,691 37,899 100,971 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 28,664 29,366 85,992 88,098 Cumulative Preferred Stock . . . . . 1,182 1,183 3,546 3,550 Capital Stock Expense. . . . . . . . . 65 25 130 77 BALANCE AT END OF PERIOD . . . . . . . . $201,385 $288,060 $201,385 $288,060 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)
September 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,586,427 $2,565,041 Transmission . . . . . . . . . . . . . . . . . . . . 924,028 913,495 Distribution . . . . . . . . . . . . . . . . . . . . 791,768 768,888 General (including nuclear fuel) . . . . . . . . . . 233,394 228,013 Construction Work in Progress. . . . . . . . . . . . 183,358 156,411 Total Electric Utility Plant . . . . . . . . 4,718,975 4,631,848 Accumulated Depreciation and Amortization. . . . . . 2,175,163 2,081,355 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,543,812 2,550,493 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . . 693,532 648,307 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 207,141 197,368 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 19,784 12,465 Accounts Receivable (net). . . . . . . . . . . . . . 131,878 130,746 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 25,551 20,857 Materials and Supplies . . . . . . . . . . . . . . . 83,515 78,009 Accrued Utility Revenues . . . . . . . . . . . . . . 43,045 37,277 Energy Marketing and Trading Contracts . . . . . . . 65,076 14,105 Prepayments. . . . . . . . . . . . . . . . . . . . . 6,403 4,848 TOTAL CURRENT ASSETS . . . . . . . . . . . . 375,252 298,307 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 566,226 421,475 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 17,602 32,573 TOTAL. . . . . . . . . . . . . . . . . . . $4,403,565 $4,148,523 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (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. . . . . . . . . . . . . . . . . . . 732,711 732,605 Retained Earnings. . . . . . . . . . . . . . . . . . 201,385 253,154 Total Common Shareholder's Equity. . . . . . 990,680 1,042,343 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 9,255 9,273 Subject to Mandatory Redemption. . . . . . . . . . 67,445 68,445 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,123,841 1,140,789 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,191,221 2,260,850 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning. . . . . . . . . . . . . . . 488,931 445,934 Other. . . . . . . . . . . . . . . . . . . . . . . . 247,620 240,320 TOTAL OTHER NONCURRENT LIABILITIES . . . . . 736,551 686,254 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 133,000 35,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 190,850 108,700 Accounts Payable - General . . . . . . . . . . . . . 50,019 53,187 Accounts Payable - Affiliated Companies. . . . . . . 10,808 37,647 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 30,510 35,161 Interest Accrued . . . . . . . . . . . . . . . . . . 17,808 15,279 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963 Obligations Under Capital Leases . . . . . . . . . . 11,047 9,667 Energy Marketing and Trading Contracts . . . . . . . 62,624 15,228 Other. . . . . . . . . . . . . . . . . . . . . . . . 88,700 67,102 TOTAL CURRENT LIABILITIES. . . . . . . . . . 618,793 381,934 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 603,133 559,288 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 124,085 129,779 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 85,932 88,712 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 43,850 41,706 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $4,403,565 $4,148,523 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 37,899 $ 100,971 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 115,014 111,510 Amortization of Incremental Nuclear Refueling Outage Expenses (net). . . . . . . . . . . . . . . . . 6,413 11,368 Under-recovery of Fuel and Purchased Power . . . . . . . (82,213) (42,676) Deferred Nuclear Outage Costs (net). . . . . . . . . . . (90,000) - Deferred Federal Income Taxes. . . . . . . . . . . . . . 57,254 11,226 Deferred Investment Tax Credits. . . . . . . . . . . . . (5,694) (5,727) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (1,132) (33,328) Fuel, Materials and Supplies . . . . . . . . . . . . . . (10,200) (308) Accrued Utility Revenues . . . . . . . . . . . . . . . . (5,768) (9,857) Accounts Payable . . . . . . . . . . . . . . . . . . . . (30,007) 10,617 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464 Payment of Disputed Taxes and Interest Related to COLI . . (3,228) (53,628) Other (net). . . . . . . . . . . . . . . . . . . . . . . . 30,208 21,002 Net Cash Flows From Operating Activities . . . . . . 37,010 139,634 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (97,044) (98,218) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,904 4,154 Net Cash Flows Used For Investing Activities . . . . (95,140) (94,064) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . 148,379 122,222 Retirement of Cumulative Preferred Stock . . . . . . . . . (1,042) (65) Retirement of Long-term Debt . . . . . . . . . . . . . . . (74,500) (55,000) Change in Short-term Debt (net). . . . . . . . . . . . . . 82,150 (16,100) Dividends Paid on Common Stock . . . . . . . . . . . . . . (85,992) (88,098) Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,546) (3,551) Net Cash Flows From (Used For) Financing Activities. 65,449 (40,592) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 7,319 4,978 Cash and Cash Equivalents at Beginning of Period . . . . . . 12,465 5,860 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 19,784 $ 10,838 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $54,928,000 and $49,041,000 and for income taxes was $(29,106,000) and $20,224,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $9,005,000 and $7,050,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In July 1999 the Company issued $150 million of 6.875% senior unsecured notes due 2004. During the first nine months of 1999, the Company reacquired the following first mortgage bonds: Principal Amount % Rate Due Date Reacquired (in thousands) 6.80 July 1, 2003 $20,000 6.55 October 1, 2003 20,000 6.55 March 1, 2004 25,000 7.20 February 1, 2024 10,000 During the first nine months of 1999, the Company increased short-term debt by $82 million. The short-term debt limitation of the Company was increased from $300 million to $500 million with approval of the Securities and Exchange Commission. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions within the American Electric Power (AEP) System Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes. Open contracts outside of AEP System Power Pool's marketing area are marked-to-market in nonoperating income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. RATE MATTERS The Federal Energy Regulatory Commission (FERC) issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission services tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 29, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers have sought rehearing of the Commission's Order. The Company made a provision in September 1999 for its share of the refund which it anticipates would result if the Commission's order is upheld including interest. 5. CONTINGENCIES Litigation As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $66 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the U.S. District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $215 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless 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. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Tanners Creek Plant over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at this plant. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Tanners Creek Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and/or reflected in the future market prices of electricity if generation is deregulated. Cook Plant Shutdown As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, both units of the Cook Plant were 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 NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. In 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The NRC senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The Company's plan to restart the Cook Plant units has Unit 2 scheduled to return to service in April 2000 and Unit 1 to return to service in September 2000. The restart plan was developed based upon a comprehensive systems readiness review of all operating systems at the Cook Plant. When maintenance and other activities required for restart are complete, the Company will seek concurrence from the NRC to return the Cook Plant to service. Management intends to replace the steam generator for Unit 1 before the unit is returned to service. Costs associated with the steam generator replacement are estimated to be approximately $165 million, which will be accounted for as a capital investment unrelated to the restart. At September 30, 1999, $82 million has been spent on the steam generator replacement. The cost of electricity supplied to retail customers increased due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal-based purchased power is being substituted for the unavailable low cost nuclear generation. Actual replacement energy fuel costs that exceeded the costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. On March 30, 1999 the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement that resolves all matters related to the recovery of replacement energy fuel costs and all outage/restart issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a billing credit of $55 million, including interest, to Indiana retail customers' bills; the deferral of unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including a $52.3 million revenue portion of the $55 million billing credit; the deferral of up to $150 million of incremental operation and maintenance costs in 1999 for Cook Plant above the amount included in base rates; the amortization of the deferred fuel and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit was applied to retail customers' bills during the months of July, August and September 1999. In June 1999 the Company announced that a settlement agreement for two open Michigan power supply cost recovery reconciliation cases had been reached with the staff of the Michigan Public Service Commission (MPSC). The proposed settlement agreement would limit the Company's ability to increase base rates and freeze power supply costs for five years, allow for the amortization of deferred power supply cost for 1997, 1998 and 1999 over five years, allow for the deferral and amortization of non-fuel nuclear operation and maintenance expenses over five years and resolve all issues related to the Cook Plant extended restart outage. The pending Michigan settlement limits deferrals to $50 million of 1999 jurisdictional non-fuel nuclear operation and maintenance costs. Hearings have been held to give the one intervenor who opposed the approval of the settlement agreement the opportunity to voice its objections. The settlement agreement is pending before the MPSC. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as a current period operation and maintenance expense in 1999 and 2000. Through September 30, 1999, $280 million has been spent, of which $196 million was incurred in 1999. Pursuant to the Indiana settlement agreement $112.5 million of incremental operation and maintenance costs were deferred for the nine months ended September 30, 1999. The Indiana jurisdiction deferral is limited to up to $150 million of incremental restart costs incurred in 1999. The amortization of such costs through September 30, 1999 was $22.5 million. At September 30, 1999, the unamortized balance of incremental restart related operation and maintenance costs was $90 million and was included in regulatory assets. Also deferred as a regulatory asset at September 30, 1999 was $148 million of replacement energy fuel costs. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations, cash flows, and possibly financial condition through 2003. Management believes that the Cook units will be successfully returned to service by April and September 2000, 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. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased $30.6 million or 79% for the quarter and $63.1 million or 62% for the year-to-date period due primarily to an increase in the cost of the extended Cook Nuclear Plant restart outage. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $ (1.6) - $ (7.7) (1) Purchased Power Expense. . 1.0 1 (13.9) (6) Other Operation Expense. . 41.9 43 89.6 35 Maintenance Expense. . . . 4.4 11 (0.1) - Taxes Other Than Federal Income Taxes. . . . . . . (4.2) (25) (0.4) - Federal Income Taxes . . . (14.5) (70) (28.4) (54) Nonoperating Income. . . . 4.8 200 5.5 N.M. Interest Charges . . . . . 2.9 16 8.3 16 N.M. = Not Meaningful Operating revenues declined as a decrease in wholesale revenues was largely offset by an increase in retail revenues. The decrease in wholesale revenues resulted from a decline in wholesale power sales margins. Retail revenues rose due to increased sales of 7% in the quarter and 5% in the year-to-date period. The retail sales increase can be attributed to increased energy usage by residential and commercial customers due to colder winter weather and warmer summer temperatures. In the year-to-date period, the rise in retail revenues from increased sales was mostly offset by the effect of an Indiana settlement agreement that allowed amortization of unrecovered fuel cost revenues over five years. Under the terms of the settlement agreement, approved by the Indiana commission in March 1999, the fuel recovery rate was reduced and fixed through March 1, 2004. The decrease in purchased power expense in the year-to-date period was due to a reduction in the average price of purchased power as the Company was able to substitute lower cost purchases from affiliates for more expensive power bought from unaffiliated utilities. Other operation and maintenance expense increased primarily as a result of costs associated with the extended Cook Plant restart outage including nuclear engineering and contract employee costs. The decrease in taxes other than federal income taxes in the third quarter is due primarily to a favorable accrual adjustment for Indiana supplemental income tax to reflect a revised taxable income estimate. Federal income taxes attributable to operations decreased significantly in both periods as a result of a decrease in pre-tax operating income. The increase in nonoperating income is primarily due to losses on certain power marketing and trading transactions in 1998. These transactions, which are marked-to-market, represent non-regulated trading activities outside the AEP System Power Pool's traditional marketing area. Interest charges increased due to increased long-term and short-term borrowing to fund the expenditures for the Cook Plant restart effort. FINANCIAL CONDITION Total plant and property additions including capital leases for the year-to-date period were $106 million. During the first nine months of 1999 short-term debt outstanding increased by $82 million. The short-term debt limitation of the Company was increased from $300 million to $500 million with approval of the Securities and Exchange Commission. During the first nine months of 1999 the Company redeemed $75 million principal amount of first mortgage bonds with interest rates from 6.55% to 7.20% and issued $150 million of 6.875% senior unsecured notes due 2004. OTHER MATTERS Spent Nuclear Fuel (SNF) Litigation As discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition (MDA) in the 1998 Annual Report, as a result of the Department of Energy's (DOE) failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, the Company along with a number of unaffiliated utilities and states filed suit in the United States (U.S.) Court of Appeals for the District of Columbia Circuit requesting, among other things, that the court order DOE to meet its obligations under the law. The court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In June 1998, the Company filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits have been filed by other utilities. On April 6, 1999, the court granted DOE's motion to dismiss a lawsuit filed by another utility. On May 20, 1999, the other utility appealed this decision to the U.S. Court of Appeals for the Federal Circuit. I&M's case has been stayed pending final resolution of the other utility's appeal. Cook Plant Shutdown As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, both units of the Cook Plant were 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 NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. In 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The NRC senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The Company's plan to restart the Cook Plant units has Unit 2 scheduled to return to service in April 2000 and Unit 1 to return to service in September 2000. The restart plan was developed based upon a comprehensive systems readiness review of all operating systems at the Cook Plant. When maintenance and other activities required for restart are complete, the Company will seek concurrence from the NRC to return the Cook Plant to service. Management intends to replace the steam generator for Unit 1 before the unit is returned to service. Costs associated with the steam generator replacement are estimated to be approximately $165 million, which will be accounted for as a capital investment unrelated to the restart. At September 30, 1999, $82 million has been spent on the steam generator replacement. The cost of electricity supplied to retail customers increased due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal-based purchased power is being substituted for the unavailable low cost nuclear generation. Actual replacement energy fuel costs that exceeded the costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. On March 30, 1999 the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement that resolves all matters related to the recovery of replacement energy fuel costs and all outage/restart issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a billing credit of $55 million, including interest, to Indiana retail customers' bills; the deferral of unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including a $52.3 million revenue portion of the $55 million billing credit; the deferral of up to $150 million of incremental operation and maintenance costs in 1999 for Cook Plant above the amount included in base rates; the amortization of the deferred fuel and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit was applied to retail customers' bills during the months of July, August and September 1999. In June 1999 the Company announced that a settlement agreement for two open Michigan power supply cost recovery reconciliation cases had been reached with the staff of the Michigan Public Service Commission (MPSC). The proposed settlement agreement would limit the Company's ability to increase base rates and freeze power supply costs for five years, allow for the amortization of deferred power supply cost for 1997, 1998 and 1999 over five years, allow for the deferral and amortization of non-fuel nuclear operation and maintenance expenses over five years and resolve all issues related to the Cook Plant extended restart outage. The pending Michigan settlement limits deferrals to $50 million of 1999 jurisdictional non-fuel nuclear operation and maintenance costs. Hearings have been held to give the one intervenor who opposed the approval of the settlement agreement the opportunity to voice its objections. The settlement agreement is pending before the MPSC. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as a current period operation and maintenance expense in 1999 and 2000. Through September 30, 1999, $280 million has been spent, of which $196 million was incurred in 1999. Pursuant to the Indiana settlement agreement $112.5 million of incremental operation and maintenance costs were deferred for the nine months ended September 30, 1999. The Indiana jurisdiction deferral is limited to up to $150 million of incremental restart costs incurred in 1999. The amortization of such costs through September 30, 1999 was $22.5 million. At September 30, 1999, the unamortized balance of incremental restart related operation and maintenance costs was $90 million and was included in regulatory assets. Also deferred as a regulatory asset at September 30, 1999 was $148 million of replacement energy fuel costs. The costs of the extended outage and restart efforts will have a material adverse effect on future results of operations, cash flows, and possibly financial condition through 2003. Management believes that the Cook units will be successfully returned to service by April and September 2000, 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. COLI Litigation As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $66 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the U.S. District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $215 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless 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. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Tanners Creek Plant over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at this plant. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Tanners Creek Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and/or reflected in the future market prices of electricity if generation is deregulated. Market Risks The Company has certain market risks inherent in its business activities 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 has not changed materially since December 31, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at September 30, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness and has been meeting with key vendors in this connection. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The AEP System, along with other electric utilities in North America, has submitted information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reported summary information to the U.S. Department of Energy (DOE) regarding the Y2K readiness of electric utilities. The fourth and final NERC report, dated August 3, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - A Status Report and Work Plan, Second Quarter 1999, states that: "Mission-critical component testing indicates that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages caused by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. NERC has classified the AEP System as a "Y2K Ready" organization with respect to its electric systems. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities also participated in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The drill gave electric utilities in North America an opportunity to test how workers would respond in emergency situations, such as an outage at a major power plant or loss of the normal communications system. The drill did not reveal any major problems or issues for AEP. Through the Electric Power Research Institute, AEP is participating in an electric utility industry-wide effort that has been established to deal with Y2K problems affecting embedded systems. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The AEP System has completed the process of modifying, replacing, retiring and testing those mission critical and high priority digital-based systems with problems processing dates in the Year 2000. The Company has upgraded its meteorological reporting system used at the Donald C. Cook Nuclear Plant, a mission critical IT system, for Y2K readiness. It was originally anticipated that the upgrade was to have been completed by December 15, 1999. Costs to Address the Company's Year 2000 Issues - Through September 30, 1999, the Company has spent $7 million on the Y2K project and, estimates spending an additional $1 million to $3 million to achieve Y2K readiness. Most Y2K costs are for software modifications, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. The Company has benefited from the sharing of costs with its affiliates in the AEP System. The cost of becoming Y2K ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restored. In addition, although relationships with third parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others who impact the AEP System's operations but are not affiliated with the AEP System, fail for critical applications, Y2K-related issues could materially adversely affect the Company. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a Y2K contingency plan and submitted it to the East Central Area Reliability Council (ECAR) as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company has established detailed contingency plans for its business units to address alternatives if Y2K related failures occur, including an operating plan which is coordinated with other ECAR member utilities. These contingency plans will be refined by the end of 1999. The Company's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, in order to place key employees on duty at those locations during the Y2K transition. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . $94,939 $104,922 $271,911 $276,288 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . 18,258 21,478 60,233 61,963 Purchased Power. . . . . . . . . . . . . 32,177 31,548 82,524 79,878 Other Operation. . . . . . . . . . . . . 10,607 13,647 34,726 36,633 Maintenance. . . . . . . . . . . . . . . 5,522 7,335 15,360 23,759 Depreciation and Amortization. . . . . . 7,356 7,068 21,833 20,956 Taxes Other Than Federal Income Taxes. . 2,967 2,668 8,183 7,420 Federal Income Taxes . . . . . . . . . . 3,808 4,627 9,215 7,406 TOTAL OPERATING EXPENSES. . . . . 80,695 88,371 232,074 238,015 OPERATING INCOME . . . . . . . . . . . . . 14,244 16,551 39,837 38,273 NONOPERATING INCOME (LOSS) . . . . . . . . 111 (902) (44) (1,066) INCOME BEFORE INTEREST CHARGES . . . . . . 14,355 15,649 39,793 37,207 INTEREST CHARGES . . . . . . . . . . . . . 7,158 7,207 21,392 21,335 NET INCOME . . . . . . . . . . . . . . . . $ 7,197 $ 8,442 $ 18,401 $ 15,872 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . $67,770 $71,356 $71,452 $78,076 NET INCOME . . . . . . . . . . . . . . . . 7,197 8,442 18,401 15,872 CASH DIVIDENDS DECLARED. . . . . . . . . . 7,443 7,075 22,329 21,225 BALANCE AT END OF PERIOD . . . . . . . . . $67,524 $72,723 $67,524 $72,723 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)
September 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $ 267,680 $ 267,201 Transmission . . . . . . . . . . . . . . . . . . . . 342,366 326,989 Distribution . . . . . . . . . . . . . . . . . . . . 360,289 351,407 General. . . . . . . . . . . . . . . . . . . . . . . 66,934 68,038 Construction Work in Progress. . . . . . . . . . . . 28,194 30,076 Total Electric Utility Plant . . . . . . . . 1,065,463 1,043,711 Accumulated Depreciation and Amortization. . . . . . 334,057 315,546 NET ELECTRIC UTILITY PLANT . . . . . . . . . 731,406 728,165 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 17,048 12,078 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 1,065 1,935 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 17,702 23,295 Affiliated Companies . . . . . . . . . . . . . . . 8,945 8,797 Miscellaneous. . . . . . . . . . . . . . . . . . . 4,716 4,019 Allowance for Uncollectible Accounts . . . . . . . (769) (848) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 12,386 7,888 Materials and Supplies . . . . . . . . . . . . . . . 16,916 13,652 Accrued Utility Revenues . . . . . . . . . . . . . . 9,226 13,560 Energy Marketing and Trading Contracts . . . . . . . 22,536 4,726 Prepayments. . . . . . . . . . . . . . . . . . . . . 1,714 1,657 TOTAL CURRENT ASSETS . . . . . . . . . . . . 94,437 78,681 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 94,321 92,447 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 6,231 10,476 TOTAL. . . . . . . . . . . . . . . . . . . $ 943,443 $ 921,847 See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $50 Par Value: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares . . . . . . . . . . $ 50,450 $ 50,450 Paid-in Capital. . . . . . . . . . . . . . . . . . . 158,750 148,750 Retained Earnings. . . . . . . . . . . . . . . . . . 67,524 71,452 Total Common Shareholder's Equity. . . . . . 276,724 270,652 Long-term Debt . . . . . . . . . . . . . . . . . . . 260,838 308,838 TOTAL CAPITALIZATION . . . . . . . . . . . . 537,562 579,490 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 24,402 26,827 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 60,000 60,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 65,965 20,350 Accounts Payable - General . . . . . . . . . . . . . 10,671 12,917 Accounts Payable - Affiliated Companies. . . . . . . 11,448 11,814 Customer Deposits. . . . . . . . . . . . . . . . . . 4,068 4,038 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 6,894 7,256 Interest Accrued . . . . . . . . . . . . . . . . . . 7,913 6,241 Energy Marketing and Trading Contracts . . . . . . . 21,685 5,089 Other. . . . . . . . . . . . . . . . . . . . . . . . 13,268 13,612 TOTAL CURRENT LIABILITIES. . . . . . . . . . 201,912 141,317 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 160,954 158,706 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 13,298 14,200 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 5,315 1,307 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $943,443 $921,847 See Notes to Financial Statements.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 18,401 $ 15,872 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 21,838 20,966 Deferred Federal Income Taxes. . . . . . . . . . . . . . 2,361 1,173 Deferred Investment Tax Credits. . . . . . . . . . . . . (902) (915) Amortization of Deferred Property Taxes. . . . . . . . . 4,035 3,840 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 4,669 (4,514) Fuel, Materials and Supplies . . . . . . . . . . . . . . (7,762) 1,227 Accrued Utility Revenues . . . . . . . . . . . . . . . . 4,334 1,394 Accounts Payable . . . . . . . . . . . . . . . . . . . . (2,612) (3,757) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (362) (1,193) Payment of Disputed Taxes and Interest Related to COLI . . (567) (5,376) Other (net). . . . . . . . . . . . . . . . . . . . . . . . (1,138) 1,952 Net Cash Flows From Operating Activities . . . . . . 42,295 30,669 INVESTING ACTIVITIES - Construction Expenditures . . . . . . (28,144) (30,517) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . 10,000 10,000 Change in Short-term Debt (net). . . . . . . . . . . . . . 45,615 12,850 Retirement of Long-term Debt . . . . . . . . . . . . . . . (48,307) (2,203) Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (22,329) (21,225) Net Cash Flows Used For Financing Activities . . . . (15,021) (578) Net Decrease in Cash and Cash Equivalents. . . . . . . . . . (870) (426) Cash and Cash Equivalents at Beginning of Period . . . . . . 1,935 1,381 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,065 $ 955 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $19,420,000 and $18,950,000 and for income taxes was $7,271,000 and $5,812,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $1,889,000 and $4,448,000 in 1999 and 1998, respectively. See Notes to Financial Statements.
KENTUCKY POWER COMPANY NOTES TO FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In 1999 the following amounts of long-term debt were redeemed: a $25 million term loan note with a rate of 6.42% in April; $12.8 million principal amount of the 7.90% Series First Mortgage Bonds in May; and $10.5 million principal amount of the remaining 7.90% Series First Mortgage Bonds in August. In June 1999 the Company received a $10 million cash capital contribution from its parent which was credited to paid-in capital. During the first nine months of 1999, the Company increased short-term debt by $45.6 million. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions within the AEP Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes. Open contracts outside of AEP Power Pool's marketing area are marked-to-market in non-operating income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. RATE MATTERS The Federal Energy Regulatory Commission (FERC) issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission service tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 29, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers have sought rehearing of the Commission's Order. The Company made a provision in September 1999 for its share of the refund which it anticipates would result if the Commission's order is upheld including interest. 5. CONTINGENCIES Litigation As discussed in Note 3, of the Notes to Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1992-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $8 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1992-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the U.S. District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management believes, and has been advised by outside counsel, that it has a meritorious position and will vigorously pursue its lawsuit. In the event the resolutions of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Air Quality As discussed in Note 3 of the Notes to Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates, filed petitions seeking a review of the final rule in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $130 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless 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. Clean Air Act Threatened Litigation In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Big Sandy Plant. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. In the event the Company does not prevail in any litigation ultimately filed, 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/or reflected in the future market price of electricity if generation is deregulated. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 Net income decreased $1.2 million or 15% for the quarter and increased $2.5 million or 16% for the year-to-date period. The decrease in net income for the quarter is attributable to lower wholesale power sales margins and a refund provision for transmission revenues. The effect on net income of decreases in revenues in both periods were offset by reductions in operating expenses. The increase in year-to-date net income is due predominantly to such decreases. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $(10.0) (10) $(4.4) (2) Fuel Expense. . . . . . . . (3.2) (15) (1.7) (3) Purchased Power Expense . . 0.6 2 2.6 3 Other Operation Expense . . (3.0) (22) (1.9) (5) Maintenance Expense . . . . (1.8) (25) (8.4) (35) Federal Income Taxes. . . . (0.8) (18) 1.8 24 Nonoperating Income . . . . 1.0 112 1.0 96 The decreases in operating revenues for the third quarter and year-to-date periods were due primarily to a reduction in wholesale power sales margins and a revenue refund provision for wholesale transmission service. In the year-to-date period, the decline in wholesale power and transmission revenues were partially offset by a 3% increase in retail revenues as a result of colder winter weather. Fuel expense decreased in the third quarter due to a decline in generation reflecting a planned maintenance outage at Big Sandy Plant Unit 2 which began in mid-September 1999. In the year-to-date period, fuel expense decreased mainly due to the deferral of fuel cost for later recovery under a fuel cost recovery mechanism. Changes in the cost of fuel are deferred until reflected in fuel clause billings to customers. The increase in purchased power expense in the year-to-date period resulted from increased capacity charges from the American Electric Power System Power Pool (AEP Power Pool). Under the terms of the AEP Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. The Company pays net capacity charges to the AEP Power Pool because its peak demand is greater than its internal generating capacity. The increase in capacity charges can be attributed to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all AEP Power Pool members. Other operation expense decreased due to reduced accruals for incentive compensation and uncollectible accounts. The decrease in maintenance expense in the third quarter reflects the effect of staff reductions. The decline in maintenance expense in the year-to-date period is primarily attributable to decreased overhead distribution line and generating plant maintenance expenditures and the staff reductions savings. In the first quarter of 1998 the repair and restoration of distribution service after winter storm damage and a lengthy scheduled outage in the second quarter of 1998 for maintenance and repairs of the 260 mw Big Sandy Plant Unit 1 increased 1998 maintenance expense. Federal income tax attributable to operations decreased in the quarter due to a decline in pre-tax operating income partially offset by changes in certain book/tax timing differences accounted for on a flow-through basis for rate-making and financial reporting purposes. The increase in federal income taxes for the year-to-date period resulted from an increase in pre-tax operating income and changes in certain book/tax timing differences accounted for on a flow-through basis for rate-making and financial reporting purposes. Nonoperating income increased due to the effect of losses recorded in 1998 on certain power marketing and trading transactions. These transactions, which are marked-to-market, represent non-regulated trading activities outside the Company's traditional marketing area. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $544,451 $597,812 $1,561,259 $1,637,155 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 173,857 199,934 532,075 574,156 Purchased Power. . . . . . . . . . . . 68,836 60,497 125,808 128,487 Other Operation. . . . . . . . . . . . 81,113 96,254 249,003 260,097 Maintenance. . . . . . . . . . . . . . 27,434 34,900 81,425 98,651 Depreciation and Amortization. . . . . 37,509 36,236 111,691 108,097 Taxes Other Than Federal Income Taxes. 42,941 42,931 128,746 127,451 Federal Income Taxes . . . . . . . . . 39,903 38,222 107,369 102,444 TOTAL OPERATING EXPENSES . . . 471,593 508,974 1,336,117 1,399,383 OPERATING INCOME . . . . . . . . . . . . 72,858 88,838 225,142 237,772 NONOPERATING INCOME (LOSS) . . . . . . . 4,856 (2,665) 6,364 2,022 INCOME BEFORE INTEREST CHARGES . . . . . 77,714 86,173 231,506 239,794 INTEREST CHARGES . . . . . . . . . . . . 21,481 20,212 62,587 60,338 NET INCOME . . . . . . . . . . . . . . . 56,233 65,961 168,919 179,456 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 364 369 1,098 1,107 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 55,869 $ 65,592 $ 167,821 $ 178,349 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $584,045 $597,357 $587,500 $590,151 NET INCOME . . . . . . . . . . . . . . . 56,233 65,961 168,919 179,456 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 57,704 52,775 173,110 158,325 Cumulative Preferred Stock . . . . . 366 369 1,101 1,108 BALANCE AT END OF PERIOD . . . . . . . . $582,208 $610,174 $582,208 $610,174 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)
September 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,688,839 $2,646,597 Transmission . . . . . . . . . . . . . . . . . . . . 852,726 842,318 Distribution . . . . . . . . . . . . . . . . . . . . 975,947 949,224 General (including mining assets). . . . . . . . . . 728,744 689,815 Construction Work in Progress. . . . . . . . . . . . 118,395 129,887 Total Electric Utility Plant . . . . . . . . 5,364,651 5,257,841 Accumulated Depreciation and Amortization. . . . . . 2,600,110 2,461,376 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,764,541 2,796,465 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 240,305 218,311 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 136,765 89,652 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 303,690 215,665 Affiliated Companies . . . . . . . . . . . . . . . 91,718 63,922 Miscellaneous. . . . . . . . . . . . . . . . . . . 23,473 28,139 Allowance for Uncollectible Accounts . . . . . . . (3,175) (1,678) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 139,431 94,914 Materials and Supplies . . . . . . . . . . . . . . . 93,539 86,870 Accrued Utility Revenues . . . . . . . . . . . . . . 38,146 43,501 Energy Marketing and Trading Contracts . . . . . . . 89,217 19,790 Prepayments and Other Current Assets . . . . . . . . 34,474 34,523 TOTAL CURRENT ASSETS . . . . . . . . . . . . 947,278 675,298 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 627,432 551,776 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 45,219 102,830 TOTAL. . . . . . . . . . . . . . . . . . . $4,624,775 $4,344,680 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1999 1998 (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. . . . . . . . . . . . . . . . . . . 462,317 462,335 Retained Earnings. . . . . . . . . . . . . . . . . . 582,208 587,500 Total Common Shareholder's Equity. . . . . . 1,365,726 1,371,036 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 17,121 17,370 Subject to Mandatory Redemption. . . . . . . . . . 8,850 11,850 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,142,610 1,073,456 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,534,307 2,473,712 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 419,733 360,330 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 11,480 11,472 Short-term Debt. . . . . . . . . . . . . . . . . . . 97,605 123,005 Accounts Payable - General . . . . . . . . . . . . . 252,513 173,369 Accounts Payable - Associated Companies. . . . . . . 97,837 62,418 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 88,276 161,406 Interest Accrued . . . . . . . . . . . . . . . . . . 22,646 14,187 Obligations Under Capital Leases . . . . . . . . . . 33,068 28,310 Energy Marketing and Trading Contracts . . . . . . . 86,406 22,480 Other. . . . . . . . . . . . . . . . . . . . . . . . 109,317 97,916 TOTAL CURRENT LIABILITIES. . . . . . . . . . 799,148 694,563 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 700,803 711,913 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 36,817 39,296 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 133,967 64,866 CONTINGENCIES (Note 7) TOTAL. . . . . . . . . . . . . . . . . . . $4,624,775 $4,344,680 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 168,919 $ 179,456 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . 146,388 129,366 Deferred Federal Income Taxes. . . . . . . . . . . . . . 7,529 12,504 Amortization of Deferred Property Taxes. . . . . . . . . 59,567 58,664 Changes in Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (109,658) (128,584) Fuel, Materials and Supplies . . . . . . . . . . . . . . (51,186) 28,200 Accrued Utility Revenues . . . . . . . . . . . . . . . . 5,355 (6,314) Accounts Payable . . . . . . . . . . . . . . . . . . . . 114,563 145,687 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (73,130) (45,620) Other Current Assets and Current Liabilities . . . . . . 19,166 22,853 Payment of Disputed Tax and Interest Related to COLI . . . (6,272) (104,222) Other (net). . . . . . . . . . . . . . . . . . . . . . . . 26,829 68,381 Net Cash Flows From Operating Activities . . . . . . 308,070 360,371 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (126,524) (121,310) Proceeds from Sale of Property and Other . . . . . . . . . 2,003 4,348 Net Cash Flows Used For Investing Activities . . . . (124,521) (116,962) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . 222,308 137,566 Change in Short-term Debt (net). . . . . . . . . . . . . . (25,400) 20,108 Retirement of Cumulative Preferred Stock . . . . . . . . . (3,267) (52) Retirement of Long-term Debt . . . . . . . . . . . . . . . (155,866) (190,181) Dividends Paid on Common Stock . . . . . . . . . . . . . . (173,110) (158,325) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,101) (1,108) Net Cash Flows Used For Financing Activities . . . . (136,436) (191,992) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 47,113 51,417 Cash and Cash Equivalents at Beginning of Period . . . . . . 89,652 44,203 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 136,765 $ 95,620 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $52,526,000 and $52,523,000 and for income taxes was $48,052,000 and $55,898,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $23,955,000 and $24,740,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state-ments should be read in conjunction with the 1998 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 normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITY In May 1999 the Company issued $50 million of 5.15% Air Quality Series C pollution control revenue bonds due 2026. In June 1999 the Company issued $100 million of 6.75% senior unsecured notes due 2004 and in September 1999 the Company issued $75 million of 7% senior unsecured notes also due in 2004. During the first nine months of 1999, the Company reacquired the following first mortgage bonds: Principal Amount % Rate Due Date Reacquired (in thousands) 6.875 June 1, 2003 $40,000 6.55 October 1, 2003 7,865 7.85 June 1, 2023 40,000 7.10 November 1, 2023 2,000 In May 1999 the Company reacquired $50 million of 7.40% Ohio Air Quality Series B pollution control revenue bonds due 2009. During the first nine months of 1999 the Company decreased short-term debt by $25.4 million. The short-term debt limitation of the Company was increased from $400 million to $450 million with approval of the Securities and Exchange Commission. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions within the AEP System Power Pool's marketing area that are included in cost of service on a settlement basis for ratemaking purposes. Open contracts outside of the AEP Power Pool's marketing area are marked-to-market in nonoperating income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. OHIO RESTRUCTURING LEGISLATION The Ohio Electric Restructuring Act of 1999 became law on October 4, 1999. The law provides for customer choice of electricity supplier, a residential rate reduction of 5% and a freezing of the unbundled generation base rates and a freezing of fuel rates beginning on January 1, 2001. The law also provides for a five-year transition period to transition 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 regulatory assets including any unrecovered deferred fuel costs, stranded plant and mining costs and other transition costs. Retail electric services that will be competitive are defined in the law as electric generation service, aggregation service, and power marketing and brokering. Under the legislation the PUCO is granted broad oversight responsibility and is required by the law to promulgate rules for competitive retail electric generation service. The law also gives the PUCO authority to approve a transition plan for each electric utility company. The law provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled frozen generation rates paid through December 31, 2005 by customers who do not switch generation suppliers and through a wires charge for customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Recovery of transition costs can, under certain circumstances, extend beyond the five-year frozen rate transition period but cannot continue beyond December 31, 2010. The Company must file a transition plan with the PUCO by January 3, 2000 and the PUCO is required to issue a transition order no later than October 31, 2000. The law also provides that the property tax assessment percentage on electric generation property be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on kilowatt-hours sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year, deferred as a prepaid expense and amortized to expense during the tax year pursuant to the tax laws whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. The change in the tax law to impose an excise tax based on kilowatt-hours sold to Ohio customers commencing before the expiration of the gross receipts tax privilege period will result in a 12 month period when electric utilities are recording as an expense both the gross receipts tax and the excise tax. Management intends to seek recovery of the overlap of the gross receipts and excise taxes in the Ohio transition plan filing. As discussed in Note 2, "Effects of Regulation," of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company defers as regulatory assets and liabilities certain expenses and revenues consistent with the regulatory process in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." Management has concluded that as of September 30, 1999 the requirements to apply SFAS 71 continue to be met since the Company's rates for generation will continue to be cost-based regulated until the establishment of unbundled frozen generation rates and a wires charge as provided in the law. The establishment of unbundled frozen generation rates and the wires charge should enable the Company to determine its ability to recover transition costs including regulatory assets and other stranded costs, a requirement to discontinue application of SFAS 71. When unbundled generation rates and the wires charge are established, the application of SFAS 71 will be discontinued for the Ohio retail jurisdiction portion of the generation business. At that time the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the unbundled frozen generation rates and distribution wires charges approved by the PUCO under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of generation assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of an unbundled frozen generation rate, the wires charge and other pertinent information, it is not possible at this time to determine if any of the Company's generating assets are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books at September 30, 1999 applicable to the Ohio retail jurisdictional generating business is $327 million before related tax effects. Due to the planned closing of affiliated mines including the Meigs mine, and other anticipated events, generation-related regulatory assets as of December 31, 2000 allocable to the Ohio retail jurisdiction are estimated to exceed $500 million, before federal income tax effects. Recovery of these regulatory assets will be sought as a part of the Company's Ohio transition plan filing. An estimated 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 such time as the unbundled frozen generation rates and the wires charge are determined through the regulatory process. Management will seek full recovery of generation-related regulatory assets, any stranded costs and other transition costs in its transition plan filing. The PUCO is required to complete its regulatory process and issue a transition order establishing the transition rates and wires charges by no later than October 31, 2000. Should the PUCO fail to approve transition rates and wires charges that are sufficient to recover the Company's generation-related regulatory assets, any other stranded costs and transition costs, it could have a material adverse effect on results of operations, cash flows and financial condition. 5. MUSKINGUM AND WINDSOR MINE CLOSING In July 1999 the Company announced that the scheduled closing of the affiliated Windsor coal mine was being accelerated from December 31, 2000 to April 30, 2000. The liability for closing the Windsor mine is estimated to be $48.4 million. In October 1999 the Company closed the Muskingum coal mine. As discussed in Note 3, "Rate Matters" of the Notes to Consolidated Financial Statements in the 1998 Annual Report, management believes the Ohio jurisdictional portion of the cost of the mine shutdowns can be deferred for future recovery through the Ohio fuel clause mechanism under terms of the Ohio fuel clause predetermined price agreement. At September 30, 1999 the Company has deferred $158 million under the terms of the Ohio fuel clause predetermined price agreement. Management intends to continue to recover from non-Ohio jurisdictional ratepayers the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the Muskingum and Windsor mines. Unless the cost of the remaining coal production and deferred mine shutdowns are recovered through the remaining Ohio fuel clause rates and Ohio restructuring transition rates and/or a wires charge, results of operations and cash flows would be adversely affected. 6. RATE MATTERS The Federal Energy Regulatory Commission (FERC) issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own transmission service tariffs in making off-system and third-party sales. As part of the orders, the FERC issued a pro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non-discriminatory transmission service. The FERC orders also allow a utility to seek recovery of certain prudently-incurred stranded costs that result from unbundled transmission service. On July 9, 1996, the AEP System companies filed an Open Access Transmission Tariff conforming with the FERC's pro-forma transmission tariff, subject to the resolution of certain pricing issues. The 1996 tariff incorporated transmission rates which were the result of a settlement of a pending rate case, but which were being collected subject to refund from certain customers who opposed the settlement and continued to litigate the reasonableness of AEP's transmission rates. On July 29, 1999, the FERC issued an order in the litigated rate case which would reduce AEP's rates for the affected customers below the settlement rate. AEP and certain of the affected customers have sought rehearing of the Commission's Order. The Company made a provision in September 1999 for its share of the refund which it anticipates would result if the Commission's order is upheld including interest. 7. CONTINGENCIES Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $117 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $570 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through PUCO approved unbundled generation transition rates, wires charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Muskingum River, Mitchell, Philip Sporn and Cardinal plants over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at these same plants. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Philip Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River Plant, Gavin Plant and Cardinal Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through PUCO approved unbundled generation transition rates, wires charges and the future market price for electricity. Other The Company continues to be involved in certain other matters discussed in the 1998 Annual Report. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1999 vs. THIRD QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased $9.7 million or 15% for the quarter and $10.5 million or 6% for the year-to-date period primarily due to a decline in energy sales to wholesale customers and a decline in wholesale margins. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . $(53.4) (9) $(75.9) (5) Fuel Expense. . . . . . . (26.1) (13) (42.1) (7) Purchased Power . . . . . 8.3 14 (2.7) (2) Other Operation Expense . (15.1) (16) (11.1) (4) Maintenance Expense . . . (7.5) (21) (17.2) (17) Nonoperating Income . . . 7.5 N.M. 4.3 215 N.M. = Not Meaningful Operating revenues decreased significantly in both the third quarter and year-to-date periods due predominantly to declines in wholesale sales and margins and a revenue refund provision for wholesale transmission service. Operating revenues from wholesale sales declined significantly as a result of decreased sales to the American Electric Power System Power Pool (AEP Power Pool) and unaffiliated entities reflecting the effect of mild weather on demand. Wholesale margins declined due to the effects of mild weather especially during August. The decreases in fuel expense for the third quarter and year-to-date periods were mainly due to a decrease in generation, reflecting the decline in demand and an increase in the deferral of fuel cost to be recovered in future periods under the Ohio fuel clause mechanism. Purchased power expense increased in the third quarter primarily due to increased purchases from unaffiliated companies at premium prices during periods of extremely high demand in July 1999. Other operation expense decreased in both periods primarily due to reduced accruals for incentive compensation, cost savings from staffing reductions and an increase in gains on emission allowance sales. The decreases in maintenance expense in both periods were mainly due to decreased boiler plant maintenance reflecting a reduction in planned maintenance work on the Company's generating units and costs savings from staff reductions at the Company's generating plants. The increase in nonoperating income is primarily due to the effect of losses in 1998 on certain non-regulated power marketing and trading transactions outside the AEP Power Pool's traditional marketing area. FINANCIAL CONDITION Total plant and property additions including capital leases for the first nine months of 1999 were $150 million. During the first nine months of 1999, the Company reacquired $90 million principal amount of first mortgage bonds with interest rates ranging from 6.55% to 7.85% and issued two series of senior unsecured notes of $100 million and $75 million with rates of 6.75% and 7%, respectively, both due in 2004. The Company retired $50 million of 7.40% pollution control revenue bonds and issued $50 million of pollution control revenue bonds at 5.15% due 2026. During the first nine months of 1999 the Company reduced short-term debt by $25.4 million. The short-term debt limitation of the Company was increased from $400 million to $450 million with approval of the Securities and Exchange Commission. OTHER MATTERS Ohio Restructuring Legislation The Ohio Electric Restructuring Act of 1999 became law on October 4, 1999. The law provides for customer choice of electricity supplier, a residential rate reduction of 5% and a freezing of the unbundled generation base rates and a freezing of fuel rates beginning on January 1, 2001. The law also provides for a five-year transition period to transition 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 regulatory assets including any unrecovered deferred fuel costs, stranded plant and mining costs and other transition costs. Retail electric services that will be competitive are defined in the law as electric generation service, aggregation service, and power marketing and brokering. Under the legislation the PUCO is granted broad oversight responsibility and is required by the law to promulgate rules for competitive retail electric generation service. The law also gives the PUCO authority to approve a transition plan for each electric utility company. The law provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled frozen generation rates paid through December 31, 2005 by customers who do not switch generation suppliers and through a wires charge for customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs, consumer education costs and other costs. Recovery of transition costs can, under certain circumstances, extend beyond the five-year frozen rate transition period but cannot continue beyond December 31, 2010. The Company must file a transition plan with the PUCO by January 3, 2000 and the PUCO is required to issue a transition order no later than October 31, 2000. The law also provides that the property tax assessment percentage on electric generation property be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will become subject to the Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last year for which electric utilities will pay the excise tax based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric distribution companies will be subject to an excise tax based on kilowatt-hours sold to Ohio customers. The gross receipts tax is paid at the beginning of the tax year, deferred as a prepaid expense and amortized to expense during the tax year pursuant to the tax laws whereby the payment of the tax results in the privilege to conduct business in the year following the payment of the tax. The change in the tax law to impose an excise tax based on kilowatt-hours sold to Ohio customers commencing before the expiration of the gross receipts tax privilege period will result in a 12 month period when electric utilities are recording as an expense both the gross receipts tax and the excise tax. Management intends to seek recovery of the overlap of the gross receipts and excise taxes in the Ohio transition plan filing. As discussed in Note 2, "Effects of Regulation," of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company defers as regulatory assets and liabilities certain expenses and revenues consistent with the regulatory process in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." Management has concluded that as of September 30, 1999 the requirements to apply SFAS 71 continue to be met since the Company's rates for generation will continue to be cost-based regulated until the establishment of unbundled frozen generation rates and a wires charge as provided in the law. The establishment of unbundled frozen generation rates and the wires charge should enable the Company to determine its ability to recover transition costs including regulatory assets and other stranded costs, a requirement to discontinue application of SFAS 71. When unbundled generation rates and the wires charge are established, the application of SFAS 71 will be discontinued for the Ohio retail jurisdiction portion of the generation business. At that time the Company will have to write-off its Ohio jurisdictional generation-related regulatory assets to the extent that they cannot be recovered under the unbundled frozen generation rates and distribution wires charges approved by the PUCO under the provisions of the restructuring law and record any asset impairments in accordance with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of." An impairment loss would be recorded to the extent that the cost of generation assets cannot be recovered through the transition recovery mechanisms provided by the law and future market prices. Absent the determination in the regulatory process of an unbundled frozen generation rate, the wires charge and other pertinent information, it is not possible at this time to determine if any of the Company's generating assets are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books at September 30, 1999 applicable to the Ohio retail jurisdictional generating business is $327 million before related tax effects. Due to the planned closing of affiliated mines including the Meigs mine, and other anticipated events, generation-related regulatory assets as of December 31, 2000 allocable to the Ohio retail jurisdiction are estimated to exceed $500 million, before federal income tax effects. Recovery of these regulatory assets will be sought as a part of the Company's Ohio transition plan filing. An estimated 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 such time as the unbundled frozen generation rates and the wires charge are determined through the regulatory process. Management will seek full recovery of generation-related regulatory assets, any stranded costs and other transition costs in its transition plan filing. The PUCO is required to complete its regulatory process and issue a transition order establishing the transition rates and wires charges by no later than October 31, 2000. Should the PUCO fail to approve transition rates and wires charges that are sufficient to recover the Company's generation-related regulatory assets, any other stranded costs and transition costs, it could have a material adverse effect on results of operations, cash flows and financial condition. Muskingum and Windsor Mine Closings In July 1999 the Company announced that the scheduled closing of the affiliated Windsor coal mine was being accelerated from December 31, 2000 to April 30, 2000. The liability for closing the Windsor mine is estimated to be $48.4 million. In October 1999 the Company closed the Muskingum coal mine. As discussed in Note 3, "Rate Matters" of the Notes to Consolidated Financial Statements in the 1998 Annual Report, management believes the Ohio jurisdictional portion of the cost of the mine shutdowns can be deferred for future recovery through the Ohio fuel clause mechanism under terms of the Ohio fuel clause predetermined price agreement. At September 30, 1999 the Company has deferred $158 million under the terms of the Ohio fuel clause predetermined price agreement. Management intends to continue to recover from non-Ohio jurisdictional ratepayers the non-Ohio jurisdictional portion of the investment in and the liabilities and closing costs of the Muskingum and Windsor mines. Unless the cost of the remaining coal production and deferred mine shutdowns are recovered through the remaining Ohio fuel clause rates and Ohio restructuring transition rates and/or a wires charge, results of operations and cash flows would be adversely affected. COLI Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through September 30, 1999 would reduce earnings by approximately $117 million (including interest). The Company has made no provision for any possible earnings impact from this matter. The Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1998 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company is seeking refunds through litigation of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. A US Tax Court judge recently decided in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI interest deductions should be disallowed. Notwithstanding the decision in Winn-Dixie, management 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. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the U.S. Environmental Protection Agency (Federal EPA) issued final rules which require reductions in nitrogen oxides (NOx) emissions in 22 eastern states, including the states in which the generating plants of the Company and its AEP System affiliates are located. A number of utilities, including the Company and its AEP System affiliates, filed petitions seeking a review of the final rules in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). The matter is currently being litigated. On April 30, 1999, Federal EPA took final action with respect to petitions filed by eight northeastern states pursuant to Section 126 of the Clean Air Act. Federal EPA approved portions of the states' petitions that would impose NOx reduction requirements on AEP System generating units which are approximately equivalent to the reductions contemplated by the NOx emission reduction final rules. The AEP System companies with generating plants, as well as other utility companies, filed a petition in the Appeals Court seeking review of Federal EPA's approval of portions of the northeastern states' petitions. In the second quarter of 1999, three additional northeastern states filed Section 126 petitions with Federal EPA similar to those originally filed by the eight northeastern states. Preliminary estimates indicate that NOx compliance could result in required capital expenditures of approximately $570 million for the Company. Compliance costs cannot be estimated with certainty. The actual costs incurred to comply could be significantly different from this preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers through PUCO approved unbundled generation transition rates, wires charges and the future market price of electricity, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Federal EPA Complaint and Notice of Violation On November 3, 1999 the Department of Justice, at the request of Federal EPA, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges the Company made modifications to generating units at its Muskingum River, Mitchell, Philip Sporn and Cardinal plants over the course of the past 25 years to extend unit operating lives or to increase unit generating capacity without a preconstruction permit in violation of the Clean Air Act. Federal EPA also issued a Notice of Violation to the Company alleging violations of the New Source Review and New Source Performance Standard provisions of the Clean Air Act at these same plants. A number of unaffiliated utilities also received Notices of Violation, complaints or administrative orders. Federal EPA's Notice of Violation and the government's complaint are based on an investigation by Federal EPA to assess compliance with the New Source Review and New Source Performance Standard provisions of the Clean Air Act. Under these provisions of the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements under the New Source Review program 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. In the fall of 1999 the State of New York, various environmental groups and the State of Connecticut each separately threatened to sue the Company under the Clean Air Act to compel compliance with the New Source Review and New Source Performance Standard provisions, alleging that modifications occurred at certain units at the Company's Philip Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River Plant, Gavin Plant and Cardinal Plant. The State of New York also threatened to sue five unaffiliated utilities. In addition, the State of New York indicated that it may seek to recover, under state law, compensation for alleged environmental damage caused by excess emissions of sulfur dioxide and nitrogen oxides. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and were exempted from the New Source Review and New Source Performance Standard requirements, and intends to vigorously pursue its defense of this matter. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). Civil penalties, if ultimately imposed by the court, and the cost of any required new pollution control equipment, if the court accepts all of Federal EPA's contentions, could be substantial. In the event the Company does not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through PUCO approved unbundled generation transition rates, wires charges and the future market price for electricity. Market Risk The Company has certain market risks inherent in its business activities 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 has not changed materially since December 31, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at September 30, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness and has been meeting with key vendors in this connection. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The AEP System, along with other electric utilities in North America, has submitted information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reported summary information to the U.S. Department of Energy (DOE) regarding the Y2K readiness of electric utilities. The fourth and final NERC report, dated August 3, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - A Status Report and Work Plan, Second Quarter 1999, states that: "Mission-critical component testing indicates that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages caused by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. NERC has classified the AEP System as a "Y2K Ready" organization with respect to its electric systems. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities also participated in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The drill gave electric utilities in North America an opportunity to test how workers would respond in emergency situations, such as an outage at a major power plant or loss of the normal communications system. The drill did not reveal any major problems or issues for AEP. Through the Electric Power Research Institute, AEP is participating in an electric utility industry-wide effort that has been established to deal with Y2K problems affecting embedded systems. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The AEP System has completed the process of modifying, replacing, retiring and testing those mission critical and high priority digital-based systems with problems processing dates in the Year 2000. Costs to Address the Company's Year 2000 Issues - Through September 30, 1999, the Company has spent $12 million on the Y2K project and, estimates spending an additional $2 million to $5 million to achieve Y2K readiness. Most Y2K costs are for software modifications, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. The Company has benefited from the sharing of Y2K remediation costs with its affiliates in the AEP System. The cost of becoming Y2K ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restored. In addition, although relationships with third parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others who impact the AEP System's operations but are not affiliated with the AEP System, fail for critical applications, Y2K-related issues could materially adversely affect the Company. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a Y2K contingency plan and submitted it to the East Central Area Reliability Council (ECAR) as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company has established detailed contingency plans for its business units to address alternatives if Y2K related failures occur, including an operating plan which is coordinated with other ECAR member utilities. These contingency plans will be refined by the end of 1999. The Company's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, in order to place key employees on duty at those locations during the Y2K transition. PART II. OTHER INFORMATION Item 5. Other Information. American Electric Power Company, Inc. ("AEP") and Appalachian Power Company ("APCo") Reference is made to pages 17 and 18 of the Annual Report on Form 10-K for the year ended December 31, 1998 ("1998 10-K") and page II-1 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, for a discussion of APCo's proposed transmission facilities. Based on an extension of the procedural schedule for the evidentiary hearing in Virginia, management has revised its completion estimate. The earliest date that a Wyoming-Jacksons Ferry line could be in service would be summer 2004. The earliest in-service date for the longer Wyoming-Cloverdale line would be the end of 2004. AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern Power Company ("CSPCo"), Indiana Michigan Power Company ("I&M"), Kentucky Power Company ("KEPCo") and Ohio Power Company ("OPCo") On October 20, 1999, the U.S. District Court for the Southern District of West Virginia issued an injunction and order, in a case involving unaffiliated parties, prohibiting the issuance by the West Virginia Division of Environmental Protection of surface mining permits which authorize the placement of excess soil in intermittent or perennial streams. On October 29, 1999, the District Court stayed the effect of its order pending appeal of this case to the U.S. Fourth Circuit Court of Appeals. Although management is unable to predict the effect of this decision on AEP System operations, the decision could have, among other things, a substantial adverse impact on the supply of coal from West Virginia to APCo's generating plants. Reference is made to page 29 of the 1998 10-K and page II-3 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 1999 for a discussion of ambient air quality standards attainment. On October 29, 1999, the U.S. Court of Appeals for the District of Columbia Circuit issued panel and en banc decisions in this matter. The panel granted rehearing regarding that portion of its underlying decision relating to implementation of a secondary air quality standard for ozone. The panel modified its order without briefing or oral argument. The panel rejected the U.S. Environmental Protection Agency's ("Federal EPA") request for rehearing on the balance of its decision. The full court (two judges abstaining) rejected Federal EPA's request for rehearing en banc by a plurality. Federal EPA has 90 days within which to petition the U.S. Supreme Court to hear an appeal. II-1 Reference is made to page 33 of the 1998 10-K, pages II-1 and II-2 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, and pages II-3 and II-4 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, for a discussion of an investigation by Federal EPA under Section 114 of the Clean Air Act focused on assessing compliance with the New Source Review and New Source Performance Standard provisions. In October 1999, Federal EPA, Region V, issued a request seeking documents and information regarding capital and maintenance expenditures at Conesville Plant and, in addition, Federal EPA, Region III, issued such a request for Amos, Kanawha River, Kammer and Clinch River plants. Federal EPA, Region III, has made site visits to the four plants identified in its request. In November 1999, Federal EPA, Region V, issued an additional request for Conesville, Picway, Muskingum River and Cardinal plants. For a discussion of a complaint filed by the U.S. Department of Justice and a Notice of Violation issued by Federal EPA, see AEP's Management's Discussion and Analysis of Results of Operations and Financial Condition. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo and OPCo Exhibit 10(a) - AEP System Excess Benefit Plan, Amended and Restated as of August 1, 1999. Exhibit 10(b) - AEP System Supplemental Savings Plan, Amended and Restated as of November 1, 1999. 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: Company Reporting Date of Report Item Reported AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo September 15, 1999 Item 5. Other Events II-2 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: November 12, 1999 II-3 EXHIBIT INDEX Page American Electric Power System Supplement Savings Plan Amended and Restated as of November 1, 1999. . . . . . . EX-1 American Electric Power System Excess Benefit Plan Amended and Restated as of August 1, 1999 . . . . . . . . EX-10 II-4 AMERICAN ELECTRIC POWER SYSTEM SUPPLEMENTAL SAVINGS PLAN AMENDED AND RESTATED AS OF NOVEMBER 1, 1999 ARTICLE I Purposes and Effective Date 1.1 The American Electric Power System Supplemental Savings Plan is established to provide to eligible employees a tax-deferred savings opportunity otherwise not available to them under the terms of the American Electric Power System Employees Savings Plan because of contribution restrictions imposed by the Internal Revenue Code. 1.2 The effective date of the American Electric Power System Supplemental Savings Plan is January 1, 1994 and the effective date of the Amended and Restated American Electric Power System Supplemental Savings Plan is November 1, 1999. ARTICLE II DEFINITIONS 2.1 "Account" means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Contributions allocated to a Participant's Account and to record any related Investment Income on the Fund or Funds selected by the Participant. 2.2 "Applicable Federal Rate" means 120% of the applicable federal long-term rate, with monthly compounding (as prescribed under Section 1274(d) of the Code), published for the December immediately prior to the Plan year. 2.3 "Code" means the Internal Revenue Code of 1986, as amended from time to time. 2.4 "Committee" means the Employee Benefit Trusts Committee as established by the Board of Directors of American Electric Power Service Corporation. 2.5 "Compensation" means a Participant's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e)(3) of the Code and contributions to this Plan, and excluding bonuses (such as but not limited to project bonuses and sign-on bonuses), performance pay awards, severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of base salary or base wage. EX-1 2.6 "Company" means the American Electric Power Service Corporation and its subsidiaries and affiliates. 2.7 "Company Contributions" means the matching contributions made by the Company pursuant to section 3.2. 2.8 "Contributions" means, as the context may require, Participant Contributions and Company contributions. 2.9 "Corporation" means the American Electric Power Company, Inc., a New York corporation. 2.10 "Eligible Employee" means an employee of the Company whose compensation is in excess of the limits imposed by section 401(a)(17) of the Code. 2.11 "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. 2.12 "Fund" means the investment options made available to participants in the Savings Plan and includes the Interest Bearing Account. 2.13 "Investment Income" means with respect to Participant Contributions and Company Contributions the earnings, gains and losses derived from the investment of such Contributions in a Fund or Funds. 2.14 "Interest Bearing Account" means an investment option to be made available to Participants in this Plan in which the Contributions invested in this option are credited with interest at the Applicable Federal Rate. 2.15 "Participant" means an Eligible Employee who has executed a Salary Reduction Agreement. 2.16 "Participant Contributions" means contributions made by the Participant pursuant to an executed Salary Reduction Agreement subject to the Participant Contribution limits contained in section 3.1. 2.17 "Plan" means the American Electric Power System Supplemental Savings Plan. 2.18 "Plan Year" means the calendar year commencing each January 1 and ending each December 31. 2.19 "Salary Reduction Agreement" means an agreement between the Company and the Participant in which the Participant elects to reduce his or her Compensation for the Plan Year and the Company agrees to treat the amount of the salary reduction as a Participant Contribution to this Plan. EX-2 2.20 "Savings Plan" means the American Electric Power System Employees Savings Plan, a plan qualified under section 401(a) of the Code, as in effect from time to time. ARTICLE III CONTRIBUTIONS 3.1 A Participant may elect to make Participant Contributions by executing a Salary Reduction Agreement. All Participant Contributions (i) shall be made by payroll deductions at the end of each payroll period, (ii) shall be based upon the Compensation the Participant received during such payroll period, and (iii) shall commence as soon as practicable after the Participant completes and delivers to the Committee a Salary Reduction Agreement. Participant Contributions are to be made in multiples of one (1) whole percentage of Compensation, not to exceed 17 percent of Compensation for any payroll period or Plan Year. The maximum Participant Contribution for any Plan Year shall not exceed the difference between (a) the Participant's Compensation for the Plan Year times 17 percent and (b) the aggregate amount of the Participant's Before-Tax and After-Tax contributions to the Savings Plan. 3.2 Subject to the limitation contained in section 3.3, the Company shall be deemed to contribute to the Plan on behalf of each Participant an amount equal to 50% of the amount, not in excess of 6% of a Participant's Compensation, contributed to the Plan by the Participant. 3.3 The amount of Company Contributions deemed to be contributed to the Plan on behalf of a Participant in combination with contributions made by the Company to the Savings Plan on behalf of the Participant, shall, in the aggregate be equal to the lesser of (a) 50% of the Participant Contributions made by the Participant to this Plan and the Savings Plan, or (b) 3% of the Participant's Compensation. If the aggregate contributions exceed the lesser limitation, Company Contributions credited to the Participant's Account shall be reduced until the aggregate Company Contributions made under both the Savings Plan and this Plan do not exceed the limitation. 3.4 An Eligible Employee who becomes a Participant after the start of a Plan Year due to an increase in the Eligible Employee's Compensation or the Eligible Employee is first employed after the start of the Plan Year, the limitations described in sections 3.1 and 3.2 above shall apply to the Compensation earned and Contributions made on and after the date the Eligible Employee becomes a Participant. EX-3 ARTICLE IV INVESTMENT OF CONTRIBUTIONS 4.1 Participant Contributions and Company Contributions shall be invested in the Funds selected by the Participant. The Participant may change the selected Funds by notifying the Company or the recordkeeper retained by the Company. Any change in the Funds selected by the Participant shall be implemented as soon as practicable. 4.2 A Participant may elect to transfer all or a portion of the Contributions from any Fund or Funds to any other Fund or Funds by giving notice to the Company or the recordkeeper retained by the Company. Transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented as soon as possible. 4.3 The Funds shall be valued daily at their fair market value and each Participant's Account shall be valued daily at its fair market value. The fair market value calculation for a Participant's Account shall be made after all Contributions, withdrawals, distributions, Investment Income and transfers for the day are recorded. 4.4 The Plan is an unfunded non-qualified deferred compensation plan and therefore the Contributions credited to a Participant's Account and the investment of those Contributions in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company. ARTICLE V ELECTION, DISTRIBUTIONS AND BENEFICIARIES 5.1 In order for an election to make Participant Contributions to be effective for any given Plan Year, the Participant must deliver a signed Salary Reduction Agreement to the Committee no later than December 31 of the year preceding the Plan Year as to which the election is to take effect, or if an employee becomes an Eligible Employee after the start of the Plan Year the election must be made within 30 days after the employee becomes an Eligible Employee. The Salary Reduction Agreement shall remain in force as to the Plan Year for which it is delivered and for each subsequent Plan Year until it is revoked by a new Salary Reduction Agreement. Notwithstanding any other provision of the Plan to the contrary, no election shall be effective to defer under the Plan any Compensation which is earned by the Participant on or before the date upon which the signed Salary Reduction Agreement is delivered to the Committee. The Salary Reduction Agreement and any revocation thereof shall contain such information as may be reasonably required by the Committee and shall be executed at the time and in the manner prescribed by the Committee. EX-4 5.2 Upon a Participant's termination of employment for any reason other than death, all amounts which are credited to the Participant's Account shall be distributed to the Participant in the form of (1) a single lump-sum payment when the Participant's employment is terminated or at the end of the post-termination deferral period selected by the Participant, or (2) in approximately equal annual or semi-annual installment payments over not less than two or more than ten years commencing when the Participant's employment is terminated or at the end of the post-termination deferral period selected by the Participant. A post-termination deferral shall be for a period of at least one year but not more then five years from the date the Participant's employment is terminate. The Participant's distribution election shall be made when the Participant first elects to participate in the Plan. The Participant may amend or revoke the distribution election at any time prior to the Participant's termination of employment, but any such amendment or revocation must be made at least twelve months prior to the initial distribution. If the Participant does not elect a post-termination deferral, the distribution of a lump-sum payment or the first installment payment shall be made within 120 days after the Participant's termination of employment. If the Participant elected a post-termination deferral, the lump-sum payment or the first installment payment shall be made within 120 days after the end of the deferral period. If the Participant elects a post-termination deferral or elects installment payments, the Participant shall be eligible to invest the remaining balance in the Participant's Account as provided in section 4.2. 5.3 Upon a Participant's death prior to termination of employment or prior to the complete distribution of the Participant's Account, all amounts credited to the Participant's Account shall be distributed to (a) the Participant's named beneficiary, or (b) if the named beneficiary predeceases the Participant or if the Participant did not name a beneficiary to the Participant's estate. Distributions to the named beneficiary shall be in the form of (1) a single lump-sum payment or (2) in approximately equal annual or semi-annual installment payments over not less than two nor more then ten years as elected by the beneficiary. The beneficiary's distribution election must be made within 90 days of the Participant's date of death. If an election is not made, the beneficiary shall receive a lump-sum payment. The distribution of a lump-sum payment or the first installment payment to a beneficiary shall be made within 90 days after the beneficiary makes or fails to make a distribution election. In the event the beneficiary elects installment payments, the beneficiary shall be eligible to invest the remaining balance in the Account as provided in section 4.2 as if the beneficiary is a Participant. In the event a beneficiary receiving installment payments shall die prior to a complete distribution of the Account, the remaining balance in the Account shall be paid to the beneficiary's estate with 120 days after the Committee is notified of beneficiary's death. The distribution of a lump-sum payment to the Participant's estate shall be made within 120 days after the Participant's date of death. EX-5 5.4 Each Participant shall have the right to designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account. Any designation, or change or rescission thereof, shall be made in writing by completing and furnishing to the Committee the appropriate beneficiary form prescribed by the Committee. The last designation of beneficiary received by the Committee prior to the death of the Participant shall control. ARTICLE VI TAXES AND TAX TREATMENT 6.1 Each Participant agrees that as a condition of participation in the Plan, the Company may withhold federal, state and local income taxes, Social Security taxes and Medicare Taxes from any distribution hereunder to the extent that such taxes are then payable. 6.2 The adoption and maintenance of the Plan is conditioned upon (1) the applicability of section 451(a) of the Code to the Participant's recognition of gross income as a result of participation herein, (2) the fact that the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received, (3) the applicability of section 404(a)(5) of the Code to the deductibility of the amounts distributed to the Participants hereunder, (4) the fact that the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed and (5) the inapplicability of the provisions of Titles 2, 3, and 4 of ERISA. If the Internal Revenue Service, Department of Labor or any court of competent jurisdiction determines or finds as a fact or legal conclusion that any of the above conditions is untrue and issues an assessment, determination, opinion or report to such effect, or if in the opinion of counsel to the Company any one of the above assumptions is incorrect, then the Company shall have the option to terminate this Plan as provided in section 8.1. ARTICLE VII Administration 7.1 The Committee shall (i) administer and interpret the terms and conditions of the Plan, (ii) establish reasonable procedures with which Participants must comply to exercise any right established hereunder, and (iii) be permitted to delegate its responsibilities or duties hereunder to any person or entity. The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan are subject to, and governed by, such acts of administration, interpretation, procedure and delegation. EX-6 7.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan. 7.3 The Company shall maintain, or cause to be maintained, records showing the individual credit balances of each Participant's Account. Each Participant shall be furnished with quarterly statements setting forth the value of the total credits to the Participant's Account. ARTICLE VIII Amendment or Termination 8.1 The Company intends to continue the Plan indefinitely but reserves the right to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of Contributions under the Plan; provided that no such modification, termination, discontinuance or suspension shall affect or otherwise deprive a Participant or beneficiary of any distributions to which they may be entitled under the Plan. ARTICLE IX Miscellaneous 9.1 Nothing in the Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company. 9.2 In the event the Committee shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed legal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company. 9.3 The Plan shall be construed and administered according to the laws of the State of Ohio. ARTICLE X Change In Control 10.1 Notwithstanding any provisions of the Plan to the contrary, if a Change in Control, as defined in Section 10.2, of the Corporation occurs, all benefits accrued as of the date of the Change in Control shall be fully vested and non-forfeitable. EX-7 10.2 A "Change in Control" of the Corporation shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Corporation, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors (other than a director nominated by a person (x) who has entered into an agreement with the Corporation to effect a transaction described in Section 10.2(i), (iii) or (iv) or (y) who publicly announces an intention to take or to consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (iii) the consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or an agreement for the sale or disposition by the Corporation (in one transaction or a series of transactions) of all or substantially all of the Corporation's assets. Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the consummation of the transactions contemplated in the Agreement and Plan of Merger by and among the Corporation, Augusta Acquisition Corporation and Central and South West Corporation dated as of December 21, 1997, nor thereafter as a result of any event in (i) or (iii) above, if Directors who were members of the Board prior to such event continue to constitute a majority of the Board after such event. For purposes of this Section 10.2, "Board" shall mean the Board of Directors of the Corporation, and "Director" shall mean an individual who is a member of the Board. EX-8 ARTICLE XI Claims Procedure 11.1 If a Participant makes a written request alleging a right to receive benefits under the Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, the Committee shall treat it as a claim for benefits. All claims for benefits under the Plan shall be sent to the Committee and must be received within 30 days after the Participant's termination of employment. If the Committee determines that any Participant who has claimed a right to receive benefits, or different benefits, under the Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefor in terms calculated to be understood by the claimant. The notice will be sent within 90 days of the claim unless the Committee determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the claim and the reason any such addition material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The claimant may within 90 days thereafter submit in writing to the Committee a notice that the claimant contests the denial of the claim by the Committee and desires a further review. The Committee shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of the Committee. The Committee will render its final decision with specific reasons therefore in writing and will transmit it to the claimant within 60 days of the written request for review, unless the Committee deterines additional time, not exceeding 60 days, is needed, and so notifies the claimant. If the Committee fails to respond to a claim filed in accordance with the foregoing within 60 days or any such extended period, the Committee shall be deemed to have denied the claim. EX-9 AMERICAN ELECTRIC POWER SYSTEM EXCESS BENEFIT PLAN AMENDED AND RESTATED AS OF AUGUST 1, 1999 ARTICLE I Purposes and Effective Date 1.1 The American Electric Power System Excess Benefit Plan is established to provide Supplemental Retirement Benefits for eligible employees whose retirement benefits from the American Electric Power System Retirement Plan are restricted due to limitations imposed by provisions of the Internal Revenue Code or who are entitled to Supplemental Retirement Benefits under the terms of an employment agreement between the eligible employee and an employer. 1.2 The effective date of the Excess Benefit Plan is January 1, 1990 and the effective date of this amended and restated Plan is July 1, 1999. ARTICLE II Definitions 2.1 "Accredited Service" means the period of time taken into account under the terms of the Retirement Plan for the purpose of computing a Retirement Plan benefit. 2.2 "Base Compensation" means a Participant's regular base salary or wage including any salary or wage reductions made pursuant to sections 125 and 402(e)(3) of the Code and contributions to the American Electric Power System Supplemental Savings Plan; and excluding bonuses (such as but not limited to project bonuses and sign-on bonuses), performance pay awards, severance pay, relocation payments, or any other form of additional compensation that is not considered to be part of base salary or base wage. 2.3 "Code" means the Internal Revenue Code of 1986, as amended from time to time. 2.4 "Committee" means the Employee Benefit Trusts Committee. 2.5 "Company" means the American Electric Power Service Corporation and its subsidiaries and affiliates who adopt the Excess Benefit Plan. 2.6 "Corporation" means the American Electric Power Company, Inc., a New York corporation, and its affiliates and subsidiaries. EX-10 2.7 "Employment Contract" means a contract between the Company and a Participant that provides the Participant with a non-qualified retirement benefit. 2.8 "ERISA" means the Employee Retirement Income Security Act of 1974 as amended from time to time. 2.9 "Excess Benefit Plan" means the American Electric Power System Excess Benefit Plan, as amended or restated from time to time. 2.10 "Incentive Compensation" means incentive compensation earned by a Participant under the terms of the Senior Officer Incentive Compensation Plan, the Management Incentive Compensation Plan, or incentive compensation to be included pursuant to the terms of an Employment Contract. An Incentive Compensation award, the payment of which is deferred according to the terms of the plan or by the election of the Participant, shall be deemed earned at the end of the Plan Year for the Incentive Compensation Plan. 2.11 "Lump Sum Benefit" means the present value of the difference between the Participant's Supplemental Retirement Benefit calculated using the Retirement Plan early retirement reduction factors from age 65 to age 55 and, if necessary, actuarially reduced from age 55 to the date the Supplemental Retirement Benefit is paid and the Participant's Supplemental Retirement Benefit actuarially reduced from age 65 to the date the Supplemental Retirement Benefit is paid; or, when applicable for computing the pre-retirement surviving spouse annuity, the present value of the difference between 50% of the Participant's Supplemental Retirement Benefit calculated using the Retirement Plan early retirement reduction factors from age 65 to age 55 and, if necessary, actuarially reduced from age 55 to the Participant's date of death and (b) 50% of the Participant's Supplemental Retirement Benefit actuarially reduced from age 65 to the date the Participant's date of death. 2.12 "Maximum Benefit" means the maximum early, normal, disability or deferred vested retirement benefit permitted by the Code to be paid to a Participant from the Retirement Plan upon the Participant's early, normal, disability or deferred retirement or the pre-retirement surviving spouse annuity permitted by the Code to be paid to the Surviving Spouse upon the death of the Participant. EX-11 2.13 "Participant" means any exempt salaried employee of the Company who is a participant in the Retirement Plan, and (i) whose base salary or base compensation exceeds the limitation of section 401(a)(17) of the Code, or (ii) who is entitled to a Supplemental Retirement Benefit under the terms of an Employment Contract. If in any Plan Year after a salaried employee becomes a Participant, the Participant's Base Compensation is lower than the compensation limits imposed by section 401(a)(17) of the Code due to an increase in the 401(a)(17) limits, the Participant shall nevertheless continue as a Participant in the Excess Benefit Plan until the Participant terminates employment or the Excess Benefit Plan is terminated. 2.14 "Plan Year" means the calendar year commencing each January 1 and ending each December 31. 2.15 "Retirement Plan" means the American Electric Power System Retirement Plan, as amended from time to time. 2.16 "Supplemental Retirement Benefit" means the difference between the Participant's Unrestricted Benefit and the Participant's Maximum Benefit. 2.17 "Surviving Spouse" means the spouse of a Participant who is legally married to the Participant and whose marriage to the Participant occurred at least one year prior to the earlier of the Participant's termination of employment or death. 2.18 "Unrestricted Benefit" means the early, normal, disability or deferred vested retirement benefit payable to a Participant upon a Participant's early, normal, disability or deferred vested retirement or the pre-retirement surviving annuity payable to the Surviving Spouse upon the death of the Participant under the terms of the Retirement Plan assuming (i) the Code restrictions on benefits that can be provided by the Retirement Plan are not applicable and (ii) the compensation upon which the benefit is based is the Participant's Base Compensation and Incentive Compensation, or the non-qualified retirement benefit provided for in an Employment Agreement. ARTICLE III Benefits 3.1 Upon a Participant's normal retirement, in accordance with the terms of the Retirement Plan, the Participant shall be entitled to a Supplemental Retirement Benefit reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. EX-12 3.2 Upon a Participant's early retirement, in accordance with the terms of the Retirement Plan, the Participant shall be entitled to a Supplemental Retirement Benefit, adjusted by the early retirement factors contained in the Retirement Plan, reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. 3.3 Upon a Participant's termination of employment prior to qualifying for early retirement under the terms of the Retirement Plan, the Participant shall be entitled to a Supplemental Retirement Benefit that is adjusted in accordance with the reductions specified in the Retirement Plan for deferred vested Retirement Plan participants reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. 3.4 A Participant whose employment is terminated prior to age 55 due to a restructuring, consolidation or downsizing of the Company and who, at the time of termination, has (i) completed 25 or more years of Accredited Service under the terms of the Retirement Plan or (ii) has attained age 50 and has completed 10 or more years of Accredited Service under the terms of the Retirement Plan shall be entitled to an early retirement Supplemental Retirement Benefit as described in section 3.3 above and a Lump Sum Benefit, the sum of which shall be reduced by any qualified or non-qualified retirement benefits the Participant is entitled to receive from any prior employer as identified in an Employment Contract. ARTICLE IV Spousal Death Benefits 4.1 Upon the death of a Participant prior to the Participant's early or normal retirement as provided under the terms of the Retirement Plan, the Surviving Spouse shall be entitled to a Supplemental Retirement Benefit reduced by any qualified or non-qualified retirement benefits the Surviving Spouse is entitled to receive from the Participant's prior employer or employers as identified in an Employment Contract. 4.2 Upon the death of the Participant after the Participant's early or normal retirement under the terms of the Retirement Plan, the Surviving Spouse shall be entitled to a Supplemental Retirement Benefit equal to the survivor annuity option elected by the Participant at the time of the Participant's retirement, as provided in section 5.1, reduced by any qualified or non-qualified retirement benefits the Surviving Spouse is entitled to receive from the Participant's prior employer or employers as identified in an Employment Contract EX-13 4.3 Upon the death of a Participant described in section 3.4 prior to the Participant's election to commence benefits, the Surviving Spouse shall be entitled to a Supplemental Retirement Benefit that would be paid to the Surviving Spouse of a Participant described in section 3.3 and shall be entitled to a Lump Sum Benefit the sum of which is to be reduced by any qualified or non-qualified retirement benefits the Surviving Spouse is entitled to receive from the Participant's prior employer or employers as identified in an Employment Contract. ARTICLE V Payment of Supplemental Retirement Benefits 5.1 The Participant's election under the Retirement Plan of a single life annuity, a 50% joint and survivor annuity, or an optional form of payment (with the valid consent of the Participant's spouse where required under the terms of the Retirement Plan) shall be deemed to be the election made by the Participant for the Supplemental Retirement Benefit payable under the Excess Benefit Plan. 5.2 The payment of a Supplemental Retirement Benefit shall commence at the same time benefit payments from the Retirement Plan commence. 5.3 A Participant described in section 3.4, may elect to commence payments of the Participant's Supplemental Retirement Benefit as of the first day of any month following the Participant's termination of employment, provided that the Participant also elects to receive retirement benefits from the Retirement Plan as of the same date. Supplemental Retirement Benefits that commence prior to age 55 shall be reduced actuarially from age 55 to the Participant's age at the time the Supplemental Retirement Benefit payments commence. The Lump Sum Benefit payable to the Participant shall be calculated and paid as of the date the Participant elects to receive payment of the Supplemental Retirement Benefits. ARTICLE VI Administration 6.1 The Committee shall administer the Excess Benefit Plan. The Committee shall have the authority to interpret the Excess Benefit Plan and to prescribe, amend and rescind rules and regulations relating to the administration of the Excess Benefit plan, and all such interpretations, rules and regulations shall be conclusive and binding on all Participants. 6.2 The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Excess Benefit Plan. EX-14 ARTICLE VII Amendment or Termination 7.1 The Company intends the Excess Benefit Plan to be permanent but reserves the right to amend or terminate the Excess Benefit Plan when, in the sole opinion of the Company, such amendment or termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Board of Directors of the Company. 7.2 No amendment or termination of the Excess Benefit Plan shall directly or indirectly deprive any current or former Participant or Surviving Spouse of all or any portion of any Supplemental Retirement Benefit which commenced prior to the effective date of such amendment or termination or which would be payable if the Participant terminated employment for any reason, including death, on such effective date. ARTICLE VIII Miscellaneous 8.1 Nothing in this Excess Benefit Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time, nor confer upon a Participant any right to continue in the employ of the Company. 8.2 In the event the Committee shall find that a Participant or Surviving Spouse is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the Surviving Spouse be paid to the duly appointed legal representative of the Participant or Surviving Spouse, and any such payment so made shall be a complete discharge of the liabilities of the Excess Benefit Plan. 8.3 Except as otherwise expressly provided herein, all terms, conditions and actuarial assumptions of the Retirement Plan applicable to benefits payable under the terms of the Retirement Plan shall also be applicable to the Supplemental Retirement Benefits paid under the terms of the Excess Benefit Plan. 8.4 The Supplemental Retirement Benefits paid under the Excess Benefit Plan shall not be funded, but shall constitute liabilities of the Company to be paid out of general corporate assets. Nothing contained in the Excess Benefit Plan shall constitute a guaranty by the Company or any other entity or person that the assets of the Company will be sufficient to pay any benefit hereunder. 8.5 The Excess Benefit Plan shall be construed and administered according to the laws of the State of Ohio. EX-15 ARTICLE IX Change In Control 9.1 Notwithstanding any provisions of the Excess Benefit Plan to the contrary, if a Change in Control, as defined in Section 9.2, of the Corporation occurs, all Supplemental Retirement Benefits accrued as of the date of the Change in Control shall be fully vested and non-forfeitable. 9.2 A "Change in Control" of the Corporation shall be deemed to have occurred if (i) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25 percent of the then outstanding voting stock of the Corporation, (ii) during any period of two consecutive years, individuals who at the beginning of such period constitute the Board, together with any new Directors (other than a director nominated by a person (x) who has entered into an agreement with the Corporation to effect a transaction described in Section 9.2(i), (iii) or (iv) or (y) who publicly announces an intention to take or to consider taking actions (including, but not limited to, an actual or threatened proxy contest) which if consummated would constitute a Change In Control) whose election or nomination for election was approved by a vote of at least two-thirds of the Directors then still in office who were either Directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the Board; or (iii) the consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50 percent of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iv) the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or an agreement for the sale or disposition by the Corporation (in one transaction or a series of transactions) of all or substantially all of the Corporation's assets. EX-16 Notwithstanding the foregoing, a Change in Control shall not be deemed to occur as a result of the consummation of the transactions contemplated in the Agreement and Plan of Merger by and among the Corporation, Augusta Acquisition Corporation and Central and South West Corporation dated as of December 21, 1997, nor thereafter as a result of any event in (i) or (iii) above, if Directors who were members of the Board prior to such event continue to constitute majority of the Board after such event. For purposes of this Section 9.2, "Board" shall mean the Board of Directors of the Corporation, and "Director" shall mean an individual who is a member of the Board. ARTICLE X Claims Procedure 10.1 If a Participant makes a written request alleging a right to receive benefits under the Excess Benefit Plan or alleging a right to receive an adjustment in benefits being paid under the Excess Benefit Plan, the Committee shall treat it as a claim for benefits. All claims for benefits under the Excess Benefit Plan shall be sent to the Committee and must be received within 30 days after the Participant's termination of employment. If the Committee determines that any Participant who has claimed a right to receive benefits, or different benefits, under the Excess Benefit Plan is not entitled to receive all or any part of the benefits claimed, it will inform the claimant in writing of its determination and the reasons therefor in terms calculated to be understood by the claimant. The notice will be sent within 90 days of the claim unless the Committee determines additional time, not exceeding 90 days, is needed. The notice shall make specific reference to the pertinent Excess Benefit Plan provisions on which the denial is based, and describe any additional material or information, if any, necessary for the claimant to perfect the claim and the reason any such addition material or information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim. The claimant may within 90 days thereafter submit in writing to the Committee a notice that the claimant contests the denial of the claim by the Committee and desires a further review. The Committee shall within 60 days thereafter review the claim and authorize the claimant to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of the Committee. The Committee will render its final decision with specific reasons therefore in writing and will transmit it to the claimant wthin 60 days of the written request for review, unless the Committee determines additional time, not exceeding 60 days, is needed, and so notifies the claimant. If the Committee fails to respond to a claim filed in accordance with the foregoing within 60 days or any such extended period, the Committee shall be deemed to have denied the claim. EX-17 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 1994 1995 1996 1997 1998 9/30/99 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . $ 75,815 $ 80,777 $ 82,082 $ 81,009 $ 72,057 $ 67,621 Interest on Other Long-term Debt. . . . . . . . 16,415 16,404 18,025 28,163 40,642 47,455 Interest on Short-term Debt . . . . . . . . . . 3,366 5,119 3,639 4,569 4,245 5,121 Miscellaneous Interest Charges. . . . . . . . . 3,913 5,323 7,327 6,857 11,470 9,245 Estimated Interest Element in Lease Rentals . . 7,700 7,000 6,600 6,000 5,900 5,900 Total Fixed Charges. . . . . . . . . . . . $107,209 $114,623 $117,673 $126,598 $134,314 $135,342 Earnings: Net Income. . . . . . . . . . . . . . . . . . . $102,345 $115,900 $133,689 $120,514 $ 93,330 $ 97,519 Plus Federal Income Taxes . . . . . . . . . . . 39,599 53,355 65,801 54,835 43,941 50,668 Plus State Income Taxes . . . . . . . . . . . . 5,910 7,273 10,180 8,109 6,845 7,077 Plus Fixed Charges (as above) . . . . . . . . . 107,209 114,623 117,673 126,598 134,314 135,342 Total Earnings . . . . . . . . . . . . . . $255,063 $291,151 $327,343 $310,056 $278,430 $290,606 Ratio of Earnings to Fixed Charges. . . . . . . . 2.37 2.54 2.78 2.44 2.07 2.14
EX-27 3 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000006879 APPALACHIAN POWER COMPANY 1,000 9-MOS DEC-31-1998 SEP-30-1999 PER-BOOK 3,137,002 132,612 438,380 27,805 417,551 4,153,350 260,458 689,099 172,360 1,121,917 22,310 18,575 1,439,573 0 0 119,380 176,005 0 53,375 12,864 1,189,351 4,153,350 1,242,903 56,201 1,005,687 1,061,888 181,015 1,152 182,167 96,209 85,958 2,015 83,943 91,044 50,150 120,752 0 0 All common stock owned by parent company; no EPS required.
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