-----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, HysDNXtmtraoF807Qbxmn9YMoxKuci3v+OtSh44ZuXVdX0VevIu2wikM6xqaH2I1 6+y9s+2bWbKLnnoeORQf9A== 0000004904-99-000193.txt : 19990817 0000004904-99-000193.hdr.sgml : 19990817 ACCESSION NUMBER: 0000004904-99-000193 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990816 FILER: COMPANY DATA: COMPANY CONFORMED NAME: OHIO POWER CO CENTRAL INDEX KEY: 0000073986 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 314271000 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-06543 FILM NUMBER: 99690598 BUSINESS ADDRESS: STREET 1: 301 CLEVELAND AVE S W CITY: COLUMBUS STATE: OH ZIP: 44702 BUSINESS PHONE: 6142231000 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 JUNE 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 July 31, 1999 was 193,389,348.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 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-18 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . A-19- A-38 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-9 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . C-10- C-18 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-9 Management's Narrative Analysis of Results of Operations . . D-10- D-11 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-10 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . E-11- E-21 Kentucky Power Company: Statements of Income and Statements of Retained Earnings . . F-1 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3 Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4 Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-7 Management's Narrative Analysis of Results of Operations . . F-8 - F-9
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 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-9 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . G-10- G-19 Part II. OTHER INFORMATION Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4 SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-6 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. Ammong 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 Six Months Ended June 30, June 30, 1999 1998 1999 1998 REVENUES: Domestic Regulated Electric Utilities. . $1,501 $1,561 $3,051 $3,070 Worldwide Non-regulated Electric and Gas Operations . . . . . . . . . . . . 142 (4) 286 8 TOTAL REVENUES . . . . . . . . . 1,643 1,557 3,337 3,078 EXPENSES: Fuel and Purchased Power . . . . . . . . 494 554 985 1,039 Maintenance and Other Operation. . . . . 469 437 896 848 Depreciation and Amortization. . . . . . 149 144 297 288 Taxes Other Than Federal Income Taxes. . 119 112 243 234 Worldwide Non-regulated Electric and Gas Operations . . . . . . . . . . . . 127 16 250 31 TOTAL EXPENSES . . . . . . . . . 1,358 1,263 2,671 2,440 OPERATING INCOME . . . . . . . . . . . . . 285 294 666 638 OTHER INCOME (LOSS), net . . . . . . . . . 2 13 (3) 9 INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES . . . . . . . 287 307 663 647 INTEREST AND PREFERRED DIVIDENDS . . . . . 135 109 267 215 INCOME BEFORE INCOME TAXES . . . . . . . . 152 198 396 432 INCOME TAXES . . . . . . . . . . . . . . . 64 80 157 163 NET INCOME . . . . . . . . . . . . . . . . $ 88 $ 118 $ 239 $ 269 AVERAGE NUMBER OF SHARES OUTSTANDING . . . 193 191 192 190 EARNINGS PER SHARE . . . . . . . . . . . . $0.46 $0.62 $1.24 $1.41 CASH DIVIDENDS PAID PER SHARE. . . . . . . $0.60 $0.60 $1.20 $1.20 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 NET INCOME . . . . . . . . . . . . . . . . $ 88 $ 118 $ 239 $ 269 OTHER COMPREHENSIVE INCOME: Foreign Currency Translation Adjustments. . . . . . . . . . . . . . 21 - 21 - COMPREHENSIVE INCOME . . . . . . . . . . . $ 109 $ 118 $ 260 $ 269
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1999 1998 (in millions) ASSETS CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . . . $ 242 $ 173 Accounts Receivable (net). . . . . . . . . . . . . . . . 908 879 Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 322 216 Materials and Supplies . . . . . . . . . . . . . . . . . 306 280 Accrued Utility Revenues . . . . . . . . . . . . . . . . 224 214 Energy Marketing and Trading Contracts . . . . . . . . . 877 372 Prepayments. . . . . . . . . . . . . . . . . . . . . . . 106 84 TOTAL CURRENT ASSETS . . . . . . . . . . . . . . 2,985 2,218 PROPERTY, PLANT AND EQUIPMENT: Electric: Production . . . . . . . . . . . . . . . . . . . . . . 9,884 9,615 Transmission . . . . . . . . . . . . . . . . . . . . . 3,772 3,692 Distribution . . . . . . . . . . . . . . . . . . . . . 5,320 5,125 Other (including gas and coal mining assets and nuclear fuel). . . . . . . . . . . . . . . . . . . 2,230 2,118 Construction Work in Progress. . . . . . . . . . . . . . 597 801 Total Property, Plant and Equipment. . . . . . . 21,803 21,351 Accumulated Depreciation and Amortization. . . . . . . . 8,879 8,549 NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . . 12,924 12,802 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . 1,952 1,847 OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . 2,726 2,616 TOTAL. . . . . . . . . . . . . . . . . . . . . $20,587 $19,483 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1999 1998 (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable . . . . . . . . . . . . . . . . . . . . $ 560 $ 607 Short-term Debt. . . . . . . . . . . . . . . . . . . . . 989 617 Long-term Debt Due Within One Year . . . . . . . . . . . 957 206 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 279 382 Interest Accrued . . . . . . . . . . . . . . . . . . . . 76 75 Obligations Under Capital Leases . . . . . . . . . . . . 86 82 Energy Marketing and Trading Contracts . . . . . . . . . 860 360 Other. . . . . . . . . . . . . . . . . . . . . . . . . . 491 472 TOTAL CURRENT LIABILITIES. . . . . . . . . . . . 4,298 2,801 LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . 6,117 6,800 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . 2,618 2,601 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 340 351 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . . 217 222 DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . . 457 263 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . 1,434 1,429 CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . . 173 174 CONTINGENCIES (Note 9) COMMON SHAREHOLDERS' EQUITY: Common Stock-Par Value $6.50: 1999 1998 Shares Authorized . . . .600,000,000 600,000,000 Shares Issued . . . . . .202,292,368 200,816,469 (8,999,992 shares were held in treasury) . . . . . . . 1,315 1,305 Paid-in Capital. . . . . . . . . . . . . . . . . . . . . 1,906 1,854 Accumulated Other Comprehensive Income: Foreign Currency Translation Adjustments . . . . . . . 20 (1) Retained Earnings. . . . . . . . . . . . . . . . . . . . 1,692 1,684 TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . . 4,933 4,842 TOTAL. . . . . . . . . . . . . . . . . . . . . $20,587 $19,483 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in millions) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 239 $ 269 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . . . . 348 309 Deferred Federal Income Taxes. . . . . . . . . . . . . . . . . 54 14 Deferred Investment Tax Credits. . . . . . . . . . . . . . . . (11) (12) Amortization of Deferred Property Taxes. . . . . . . . . . . . 80 78 Cook Restart Expense Deferral. . . . . . . . . . . . . . . . . (60) - Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . . . (60) (47) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . . . . (29) (200) Fuel, Materials and Supplies . . . . . . . . . . . . . . . . . (132) (31) Accrued Utility Revenues . . . . . . . . . . . . . . . . . . . (10) (8) Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . . (22) (14) Accounts Payable . . . . . . . . . . . . . . . . . . . . . . . (47) 159 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . . (103) (78) Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . . . 35 39 Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . . 4 92 Net Cash Flows From Operating Activities . . . . . . . . . 286 570 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . . . . (402) (364) Proceeds from Sale of Property and Other . . . . . . . . . . . . (10) (14) Net Cash Flows Used For Investing Activities . . . . . . . (412) (378) FINANCING ACTIVITIES: Issuance of Common Stock . . . . . . . . . . . . . . . . . . . . 62 42 Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . . 323 611 Change in Short-term Debt (net). . . . . . . . . . . . . . . . . 372 (49) Retirement of Long-term Debt . . . . . . . . . . . . . . . . . . (331) (483) Dividends Paid on Common Stock . . . . . . . . . . . . . . . . . (231) (229) Net Cash Flows From (Used For) Financing Activities. . . . 195 (108) Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . . 69 84 Cash and Cash Equivalents at Beginning of Period . . . . . . . . . 173 91 Cash and Cash Equivalents at End of Period . . . . . . . . . . . . $ 242 $ 175 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $256 million and $206 million and for income taxes was $79 million and $117 million in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $43 million and $85 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 Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in millions) BALANCE AT BEGINNING OF PERIOD . . . . . . $1,720 $1,642 $1,684 $1,605 NET INCOME . . . . . . . . . . . . . . . . 88 118 239 269 DEDUCTIONS: Cash Dividends Declared. . . . . . . . . 116 115 231 229 BALANCE AT END OF PERIOD . . . . . . . . . $1,692 $1,645 $1,692 $1,645 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING AND RELATED ACTIVITIES During the first six months of 1999, subsidiaries issued $250 million of senior unsecured notes: $150 million at 6.60% due in 2009 and $100 million at 6.75% 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 $372 million. In July 1999 an additional $150 million of senior unsecured notes at 6.875% due in 2004 were issued. Retirements of debt were: first mortgage bonds totaling $243 million with interest rates ranging from 6.55% to 8.43% and due dates ranging from 2003 to 2023, $50 million of pollution control revenue bonds at 7.40% due 2009 and a $25 million term loan with an interest rate of 6.42%. 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 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 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 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. On July 29, 1999, the FERC approved a draft order which rules on the Company's pending Open Access Transmission Tariff. This approved order has certain unfavorable pricing issues for which the Company has 30 days to seek rehearing. If the Commission's order is ultimately upheld the Company will have to make refunds including interest. As of June 30, 1999 the Company has not made any provisions for a refund which is preliminarily estimated to be approximately $20 million. 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 summarized consolidated financial information of Yorkshire: Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in millions) Income Statement Data: Operating Revenues $504.7 $503.9 $1,156.7 $1,167.1 Operating Income 38.5 92.5 152.0 182.2 Net Income (Loss) (4.4) (14.8) 30.2 (7.9) On August 12, 1999, the Office of Gas and Electricity Markets (the U.K. regulator of gas and electricity rates) published draft price proposals for the U.K.'s regional electric distribution businesses that would be effective for the five-year period beginning April 1, 2000. The draft price proposals would require average reductions of 16% to 21%. The proposed distribution rates for Yorkshire call for a 15% to 20% reduction in distribution revenues. Yorkshire is in the process of evaluating the draft price proposals. 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 the other segment. 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 six months ending June 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) June 30, 1999 Revenues from external customers $ 3,051 $ 335 $ 57 $(106) $ 3,337 Revenues from transactions with other operating segments - 28 78 (106) - Segment net income (loss) 251 (1) (11) - 239 Total assets 17,766 2,305 516 - 20,587 June 30, 1998 Revenues from external customers 3,070 9 (1) - 3,078 Revenues from transactions with other operating segments - - - - - Segment net income (loss) 290 (15) (6) - 269 Total assets 16,686 427 100 - 17,213
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 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 proposal whereby it will transfer the operation and control of AEP's bulk transmission facilities. 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 with the FERC asking 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 split 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. 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. The Public Utility Commission of Texas held hearings on the merger on August 9 and 10, 1999 and a final order is expected in the fourth quarter of 1999. On August 11, 1999 AEP and CSW announced that settlement agreements with several Texas wholesale customer groups had been reached. The agreements, which are subject to approval by the governing bodies of each of the wholesale customers, resolve certain issues raised in the merger proceeding and call for the wholesale customer groups to withdrawal their opposition to the merger in all regulatory approval proceedings. 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. 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 investigation. Completion of the Merger As of June 30, 1999, AEP had deferred $30 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 will be amortized over their recovery period, generally 5-years. 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 first 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 new 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 Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded 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 may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. Management has concluded that as of June 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 should enable the Company to determine its ability to recover stranded costs. When capped rates and the wires charge are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the 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 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 and other pertinent information, it is not possible at this time to determine if any plants are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books applicable to the Virginia generating business at June 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, 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 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 in the fourth quarter of 2000. Ohio On July 6, 1999, the Governor of the State of Ohio signed The Ohio Electric Restructuring Act of 1999. The Act provides for customer choice of electricity supplier and a residential rate reduction of 5% of the unbundled generation rate beginning on January 1, 2001. The Act 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 and other stranded transition costs. Retail electric services that will be competitive are defined in the Act as electric generation service, aggregation service, and power marketing and brokering. The PUCO has been granted broad oversight responsibility under the Act. The Act requires the PUCO to promulgate rules for competitive retail electric generation service. The Act further provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled rates paid by customers who do not switch generation suppliers and through a wires charges by customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs and other costs. Recovery of transition revenues can under certain circumstances extend beyond the five-year 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 Act also provides that the property tax assessment percentage on electric generation equipment be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will also 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 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. These changes should put the Company's generation operations on an equal level with other competitive businesses in Ohio regarding state taxation. 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 liabilities and assets certain revenues and expenses consistent with the regulatory process in accordance with SFAS 71. At June 30, 1999 the amount of regulatory assets recorded on the books applicable to the generating business is estimated to be $640 million before related tax effects. Whether the Company will have any additional stranded transition costs related to an economic impairment of its generating assets is dependent on several factors including the assumed future market price for electricity. The Company intends to seek recovery in its transition filing of all regulatory assets and any other stranded transition costs which may be identified. At this time management is unable to predict the outcome of the regulatory process or its impact on results of operations, cash flows or financial condition. Therefore, the Company will not be discontinuing application of SFAS 71 until the regulatory process is completed. Upon discontinuance of the application of SFAS 71 the Company will have to write off its generation-related regulatory assets and record any asset impairments in accordance with SFAS 121. Absent the determination in the regulatory process of transition revenues and other pertinent information, it is not possible at this time to determine if any plants are impaired in accordance with SFAS 121. Should the Company be granted recovery of its regulatory assets and/or any economic asset impairments it can record an offsetting regulatory asset. Should the PUCO not approve the Company's request for recovery of its generation-related regulatory assets and/or other stranded transition costs it would have an adverse impact on future results of operations and possibly financial condition. The Company does not expect to be able to determine the impact of the legislation on its financial statements until the regulatory process is complete. The PUCO is required to complete its regulatory process no later than October 31, 2000. 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 June 30, 1999 would reduce earnings by approximately $316 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 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. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the US 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. A number of utilities, including the operating companies of the AEP System, filed petitions seeking a review of the final rule in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. 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 an 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. On June 24, 1999, the Boards of Directors of the Company and Indiana Michigan Power Company both approved a plan to restart the Cook Plant. Unit 2 is scheduled to return to service in April 2000 and Unit 1 is to return to service in September 2000. This approval follows 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 June 30, 1999, $70 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 estimated costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. At June 30, 1999, the regulatory asset was $129 million. 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 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 the $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 recoveries 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 will be applied to 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 freeze rates and 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 outage. At a hearing on June 30, 1999, the MPSC granted a continuance to the one intervenor who opposed the approval of the settlement agreement. A hearing has been scheduled for August 13, 1999. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as current period operation and maintenance expense in 1999 and 2000. Through June 30, 1999, $192 million has been spent, of which $108 million was incurred in the first half of 1999. Pursuant to the Indiana settlement agreement $60 million of incremental operation and maintenance costs were deferred through June 30, 1999. The Indiana jurisdiction deferral is limited to $150 million of incremental restart costs incurred in 1999. The pending Michigan settlement limits deferrals to $50 million of non-fuel operation and maintenance 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 SECOND QUARTER 1999 vs. SECOND QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased $30 million or 25% in the second quarter and $30 million or 11% in the year-to-date period due primarily to an extended outage of the Company's nuclear plant and mild weather in the second quarter. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-To-Date (in millions) % (in millions) % Revenues: Domestic Regulated Electric Utilities. . . . . . . . . . . $(60) (4) $(19) (1) Worldwide Non-regulated Operations . . . . . . . . . . 146 N.M. 278 N.M. Fuel and Purchased Power Expense. (60) (11) (54) (5) Maintenance and Other Operation Expense. . . . . . . . 32 7 48 6 Worldwide Non-regulated Operations Expense . . . . . . . 111 N.M. 219 N.M. Other Income (Loss), net. . . . . (11) N.M. (12) N.M. Interest and Preferred Dividends. 26 24 52 24 Income Taxes. . . . . . . . . . . (16) (20) (6) (4) N.M. = Not Meaningful Revenues from domestic regulated electric utility operations decreased in both periods reflecting lower wholesale prices and a decrease in wholesale energy sales. A decrease in sales to residential customers reflecting mild weather also contributed to the decrease in revenues for the second quarter. The decline in wholesale sales reflects milder springtime temperatures and the termination of a contract to supply power to several municipal customers. Lower wholesale prices in 1999 reflect the effect of reduced demand on prices. Wholesale demand is affected by the weather and the availability of non-affiliated generating units. 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 decrease in fuel and purchased power expense was primarily attributable to a decrease in purchases of power and a reduction in prices reflecting the effects of mild weather on demand and prices. Maintenance and other operation expense increased due to the cost of work to prepare the Company's nuclear generating units for restart. The units have been on an extended Nuclear Regulatory Commission monitored outage (see Cook Nuclear Plant Shutdown below). Worldwide non-regulated expenses increased as a result of the expansion of business development activities and expenses from the December 1998 acquisitions of CitiPower and Louisiana Intrastate Gas. The decrease in other income (loss) is primarily due to the recognition of a provision for loss related to a Public Utilities Commission of Ohio (PUCO) order which requires the Company to reprice certain emission allowance transactions which are included in the electric fuel rate factor of customers' bills. The order requires the Company to adjust the actual amount paid for allowances purchased to the weighted average cost of allowances surrendered to the United States Environmental Protection Agency (Federal EPA) as a result of exceeding sulfur emission limitations in order to make wholesale sales. 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. FINANCIAL CONDITION Total plant and property additions including capital leases for the first six months were $446 million. During the first six months of 1999 subsidiaries issued $324 million principal amount of long-term obligations at interest rates ranging from 5.15% to 6.75%; retired $318 million principal amount of long-term debt with interest rates ranging from 6.42% to 8.43%; and increased short-term debt by $372 million from year-end balances. 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 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. Cook Nuclear Plant Shutdown As discussed in MDA in the 1998 Annual Report, both units of the Cook Nuclear Plant were shut down by Indiana Michigan Power Company (I&M) in September 1998 due to questions regarding the operability of certain safety systems, which 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. On June 24, 1999, the Boards of Directors of the Company and Indiana Michigan Power Company both approved a plan to restart the Cook Plant. Unit 2 is scheduled to return to service in April 2000 and Unit 1 is to return to service in September 2000. This approval follows 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 June 30, 1999, $70 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 estimated costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. At June 30, 1999, the regulatory asset was $129 million. 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 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 the $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 recoveries 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 will be applied to 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 freeze rates and 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 outage. At a hearing on June 30, 1999, the MPSC granted a continuance to the one intervenor who opposed the approval of the settlement agreement. A hearing has been scheduled for August 13, 1999. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as current period operation and maintenance expense in 1999 and 2000. Through June 30, 1999, $192 million has been spent, of which $108 million was incurred in the first half of 1999. Pursuant to the Indiana settlement agreement $60 million of incremental operation and maintenance costs were deferred through June 30, 1999. The Indiana jurisdiction deferral is limited to $150 million of incremental restart costs incurred in 1999. The pending Michigan settlement limits deferrals to $50 million of non-fuel operation and maintenance 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. 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), 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 proposal whereby it will transfer the operation and control of AEP's bulk transmission facilities. 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 with the FERC asking 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 split 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. 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. The Public Utility Commission of Texas held hearings on the merger on August 9 and 10, 1999 and a final order is expected in the fourth quarter of 1999. On August 11, 1999 AEP and CSW announced that settlement agreements with several Texas wholesale customer groups had been reached. The agreements, which are subject to approval by the governing bodies of each of the wholesale customers, resolve certain issues raised in the merger proceeding and call for the wholesale customer groups to withdrawal their opposition to the merger in all regulatory approval proceedings. Indiana The 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. 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 investigation. Completion of the Merger As of June 30, 1999, AEP had deferred $30 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 will be amortized over their recovery period, generally 5-years. 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 first quarter of 2000, the Company is unable to predict the outcome or the timing of the required regulatory proceedings. Restructuring Legislation Virginia In March 1999 a new 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 Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded 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 may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. Management has concluded that as of June 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 should enable the Company to determine its ability to recover stranded costs. When capped rates and the wires charge are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the 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 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 and other pertinent information, it is not possible at this time to determine if any plants are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books applicable to the Virginia generating business at June 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, 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 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 in the fourth quarter of 2000. Ohio On July 6, 1999, the Governor of the State of Ohio signed The Ohio Electric Restructuring Act of 1999. The Act provides for customer choice of electricity supplier and a residential rate reduction of 5% of the unbundled generation rate beginning on January 1, 2001. The Act 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 and other stranded transition costs. Retail electric services that will be competitive are defined in the Act as electric generation service, aggregation service, and power marketing and brokering. The PUCO has been granted broad oversight responsibility under the Act. The Act requires the PUCO to promulgate rules for competitive retail electric generation service. The Act further provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled rates paid by customers who do not switch generation suppliers and through a wires charges by customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs and other costs. Recovery of transition revenues can under certain circumstances extend beyond the five-year 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 Act also provides that the property tax assessment percentage on electric generation equipment be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will also 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 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. These changes should put the Company's generation operations on an equal level with other competitive businesses in Ohio regarding state taxation. 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 liabilities and assets certain revenues and expenses consistent with the regulatory process in accordance with SFAS 71. At June 30, 1999 the amount of regulatory assets recorded on the books applicable to the generating business is estimated to be $640 million before related tax effects. Whether the Company will have any additional stranded transition costs related to an economic impairment of its generating assets is dependent on several factors including the assumed future market price for electricity. The Company intends to seek recovery in its transition filing of all regulatory assets and any other stranded transition costs which may be identified. At this time management is unable to predict the outcome of the regulatory process or its impact on results of operations, cash flows or financial condition. Therefore, the Company will not be discontinuing application of SFAS 71 until the regulatory process is completed. Upon discontinuance of the application of SFAS 71 the Company will have to write off its generation-related regulatory assets and record any asset impairments in accordance with SFAS 121. Absent the determination in the regulatory process of transition revenues and other pertinent information, it is not possible at this time to determine if any plants are impaired in accordance with SFAS 121. Should the Company be granted recovery of its regulatory assets and/or any economic asset impairments it can record an offsetting regulatory asset. Should the PUCO not approve the Company's request for recovery of its generation-related regulatory assets and/or other stranded transition costs it would have an adverse impact on future results of operations and possibly financial condition. The Company does not expect to be able to determine the impact of the legislation on its financial statements until the regulatory process is complete. The PUCO is required to complete its regulatory process no later than October 31, 2000. United Kingdom Price Reduction Proposal On August 12, 1999, the Office of Gas and Electricity Markets (the U.K. regulator of gas and electricity rates) published draft price proposals for the U.K.'s regional electric distribution businesses that would be effective for the five-year period beginning April 1, 2000. The draft price proposals would require average reductions of 16% to 21%. The proposed distribution rates for Yorkshire call for a 15% to 20% reduction in distribution revenues. Yorkshire is in the process of evaluating the draft price proposals. 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. The Company's exposure to market risk from the trading of electricity and natural gas and related financial derivative instruments has not changed materially since December 31, 1998. 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. There have been no material changes to the Company's exposure to fluctuations in foreign currency exchange rates related to foreign ventures and investments since December 31, 1998. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at June 30, 1999 is not materially different than at December 31, 1998. Air Quality As discussed in MDA in the 1998 Annual Report, the US 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. A number of utilities, including the operating companies of the AEP System, filed petitions seeking a review of the final rule in the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. 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. 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. 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 plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities, including AEP, are working together to assess specific vendors' system problems and test plans. 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 following chart shows the Company's progress toward becoming ready for Y2K as of June 30, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation 2/24/1998 100% 5/31/1998 100% of the Y2K activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999 100% replacing or retiring 100% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 99%* systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. * The Company is upgrading a meteorological reporting system used at the Donald C. Cook Nuclear Plant, a mission critical IT system, for Y2K readiness and it is anticipated that the upgrade should be completed by December 15, 1999. The above chart does not reflect progress of midstream gas operations and CitiPower acquired in December 1998. The mission critical systems for the midstream gas operations are expected to be ready by August 31, 1999 and the mission critical systems for CitiPower are expected to be ready by October 1, 1999. Costs to Address the Company's Y2K Issues - Through June 30, 1999, the Company has spent $35 million on the Y2K project and estimates spending an additional $13 million to $21 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 compliant 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 regime which may expose it to customer claims, that may differ from claims under the US legal and regulatory regime, for service interruptions and/or power quality problems resulting from Y2K problems. 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 may 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 is establishing contingency plans for its business units to address alternatives if Y2K related failures occur. These contingency plans will be developed 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 Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $51,612 $54,282 $104,439 $108,334 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 20,169 21,264 40,427 43,765 Rent - Rockport Plant Unit 2 . . . . . 17,070 17,070 34,141 34,141 Other Operation. . . . . . . . . . . . 2,092 2,724 5,462 5,373 Maintenance. . . . . . . . . . . . . . 4,489 4,229 6,751 6,407 Depreciation . . . . . . . . . . . . . 5,483 5,412 10,923 10,824 Taxes Other Than Federal Income Taxes. 1,253 934 2,492 1,877 Federal Income Taxes . . . . . . . . . 54 755 881 1,717 TOTAL OPERATING EXPENSES . . . 50,610 52,388 101,077 104,104 OPERATING INCOME . . . . . . . . . . . . 1,002 1,894 3,362 4,230 NONOPERATING INCOME. . . . . . . . . . . 889 791 1,745 1,620 INCOME BEFORE INTEREST CHARGES . . . . . 1,891 2,685 5,107 5,850 INTEREST CHARGES . . . . . . . . . . . . 669 806 1,271 1,591 NET INCOME . . . . . . . . . . . . . . . $ 1,222 $ 1,879 $ 3,836 $ 4,259 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $4,311 $1,732 $2,770 $2,528 NET INCOME . . . . . . . . . . . . . . . 1,222 1,879 3,836 4,259 CASH DIVIDENDS DECLARED. . . . . . . . . 1,073 1,176 2,146 4,352 BALANCE AT END OF PERIOD . . . . . . . . $4,460 $2,435 $4,460 $2,435 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)
June 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production. . . . . . . . . . . . . . . . . . . . . . . . $627,798 $630,260 General . . . . . . . . . . . . . . . . . . . . . . . . . 1,933 2,009 Construction Work in Progress . . . . . . . . . . . . . . 7,017 4,191 Total Electric Utility Plant. . . . . . . . . . . 636,748 636,460 Accumulated Depreciation. . . . . . . . . . . . . . . . . 284,326 277,855 NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 352,422 358,605 CURRENT ASSETS: Cash and Cash Equivalents . . . . . . . . . . . . . . . . 1,561 232 Accounts Receivable . . . . . . . . . . . . . . . . . . . 21,958 22,894 Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 26,811 11,308 Materials and Supplies. . . . . . . . . . . . . . . . . . 3,877 3,900 Prepayments . . . . . . . . . . . . . . . . . . . . . . . 31 267 TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 54,238 38,601 REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 5,864 5,984 DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 2,522 702 TOTAL . . . . . . . . . . . . . . . . . . . . . $415,046 $403,892 See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) June 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 . . . . . . . . . . . . . . . . . . . . 4,460 2,770 Total Common Shareholder's Equity . . . . . . . . 34,695 39,005 Long-term Debt. . . . . . . . . . . . . . . . . . . . . . 44,796 44,792 TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 79,491 83,797 OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 752 896 CURRENT LIABILITIES: Short-term Debt - Notes Payable . . . . . . . . . . . . . 39,375 24,450 Accounts Payable: General . . . . . . . . . . . . . . . . . . . . . . . . 7,902 6,419 Affiliated Companies. . . . . . . . . . . . . . . . . . 11,190 6,177 Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 7,704 3,227 Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 4,963 4,963 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 2,852 6,023 TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 73,986 51,259 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 130,545 133,330 REGULATORY LIABILITIES: Deferred Investment Tax Credits . . . . . . . . . . . . . 64,885 66,562 Amounts Due to Customers for Federal Income Tax . . . . . 27,488 28,644 TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 92,373 95,206 DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 37,899 39,404 TOTAL . . . . . . . . . . . . . . . . . . . . . $415,046 $403,892 See Notes to Financial Statements.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 3,836 $ 4,259 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . . 10,923 10,824 Deferred Federal Income Taxes. . . . . . . . . . . . . . (2,661) 2,689 Deferred Investment Tax Credits. . . . . . . . . . . . . (1,677) (1,681) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2. . . . . . . . . (2,785) (2,785) Deferred Property Taxes. . . . . . . . . . . . . . . . . (1,666) (1,572) Changes in Certain Current Assets and Liabilities: Accounts Receivable. . . . . . . . . . . . . . . . . . . 936 (1,803) Fuel, Materials and Supplies . . . . . . . . . . . . . . (15,480) (5,700) Accounts Payable . . . . . . . . . . . . . . . . . . . . 6,496 8,208 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 4,477 1,330 Other (net). . . . . . . . . . . . . . . . . . . . . . . . (3,413) 517 Net Cash Flows From (Used For) Operating Activities. (1,014) 14,286 INVESTING ACTIVITIES - Construction Expenditures . . . . . . (4,436) (3,769) FINANCING ACTIVITIES: Return of Capital to Parent Company. . . . . . . . . . . . (6,000) (2,000) Retirement of Long-term Debt . . . . . . . . . . . . . . . - (25,000) Change in Short-term Debt (net). . . . . . . . . . . . . . 14,925 23,200 Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (2,146) (4,352) Net Cash Flows From (Used For) Financing Activities. 6,779 (8,152) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 1,329 2,365 Cash and Cash Equivalents at Beginning of Period . . . . . . 232 237 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,561 $ 2,602 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $1,070,000 and $1,634,000 and for income taxes was $1,268,000 and $(717,000) in 1999 and 1998, respectively. See Notes to Financial Statements.
AEP GENERATING COMPANY NOTES TO FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 1999 vs. SECOND 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. A monthly power bill for energy supplied is issued based on estimated expenses for the month and adjusted to actual amounts in the following month. Net income declined $0.7 million or 35% in the second quarter and $0.4 million or 10% in the year-to-date period as a result of capital returned to the Company's parent in 1998 and 1999. Also contributing to the decrease in net income for the quarter was a reduction to April 1999 billings to reflect an adjustment to actual of estimated power production expenses included in March 1999 billings. The adjustment to actual expenses reduced revenues and net income for the second quarter. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . . $(2.7) (5) $(3.9) (4) Fuel Expense . . . . . . . . (1.1) (5) (3.3) (8) Other Operation Expense. . . (0.6) (23) 0.1 2 Maintenance Expense. . . . . 0.3 6 0.3 5 Taxes Other Than Federal Income Taxes . . . . . . . 0.3 34 0.6 33 Federal Income Taxes . . . . (0.7) (93) (0.8) (49) Interest Charges . . . . . . (0.1) (17) (0.3) (20) The decrease in operating revenues during the second quarter and the year-to-date period reflects the recovery of lower operating expenses, primarily fuel, and a reduction in capital cost from the return of capital. Operating revenues for the second quarter were also reduced by the April 1999 billing adjustment. Fuel expense decreased reflecting a decrease in generation resulting from planned maintenance outages of both Rockport units. The decline in other operation expense in the second quarter is primarily due to a decrease in administrative and general expenses reflecting a reduction in allocated employee salary and benefit costs and a reduction in the FERC annual assessment. Maintenance expense increased due to the planned maintenance outages. 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 cessation 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 reversal of deferred taxes in excess of the statutory tax rate. The decline in interest charges in the second quarter was due to a reduction in the average outstanding balance of short-term debt. Interest charges decreased in the year-to-date period primarily due to a reduction in outstanding long-term debt reflecting a March 1998 redemption of $25 million of pollution control revenue bonds. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $373,766 $403,080 $ 801,468 $818,446 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 99,659 101,191 223,232 209,400 Purchased Power. . . . . . . . . . . . 61,048 87,235 111,639 156,497 Other Operation. . . . . . . . . . . . 60,162 62,442 122,911 117,309 Maintenance. . . . . . . . . . . . . . 38,361 31,476 66,872 66,828 Depreciation and Amortization. . . . . 37,224 35,788 73,775 71,193 Taxes Other Than Federal Income Taxes. 30,066 29,934 60,041 60,178 Federal Income Taxes . . . . . . . . . 4,147 8,822 28,292 26,600 TOTAL OPERATING EXPENSES . . . 330,667 356,888 686,762 708,005 OPERATING INCOME . . . . . . . . . . . . 43,099 46,192 114,706 110,441 NONOPERATING INCOME (LOSS) . . . . . . . 315 1,561 (773) 1,174 INCOME BEFORE INTEREST CHARGES . . . . . 43,414 47,753 113,933 111,615 INTEREST CHARGES . . . . . . . . . . . . 32,378 32,629 63,636 63,292 NET INCOME . . . . . . . . . . . . . . . 11,036 15,124 50,297 48,323 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 673 678 1,348 1,147 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 10,363 $ 14,446 $ 48,949 $ 47,176 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $187,699 $210,545 $179,461 $207,544 NET INCOME . . . . . . . . . . . . . . . 11,036 15,124 50,297 48,323 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 30,348 29,729 60,696 59,458 Cumulative Preferred Stock . . . . . 565 570 1,132 932 Capital Stock Expense. . . . . . . . . 108 108 216 215 BALANCE AT END OF PERIOD . . . . . . . . $167,714 $195,262 $167,714 $195,262 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)
June 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,006,859 $1,979,180 Transmission . . . . . . . . . . . . . . . . . . . . 1,132,344 1,118,726 Distribution . . . . . . . . . . . . . . . . . . . . 1,675,056 1,641,523 General. . . . . . . . . . . . . . . . . . . . . . . 239,257 228,464 Construction Work in Progress. . . . . . . . . . . . 107,941 119,466 Total Electric Utility Plant . . . . . . . . 5,161,457 5,087,359 Accumulated Depreciation and Amortization. . . . . . 2,035,779 1,984,856 NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,125,678 3,102,503 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 140,694 111,020 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 30,081 7,755 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 112,483 122,746 Affiliated Companies . . . . . . . . . . . . . . . 24,797 35,802 Miscellaneous. . . . . . . . . . . . . . . . . . . 11,508 8,572 Allowance for Uncollectible Accounts . . . . . . . (2,883) (2,234) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 64,175 49,826 Materials and Supplies . . . . . . . . . . . . . . . 63,726 60,440 Accrued Utility Revenues . . . . . . . . . . . . . . 38,719 45,985 Energy Marketing and Trading Contracts . . . . . . . 190,857 22,436 Prepayments. . . . . . . . . . . . . . . . . . . . . 7,194 8,151 TOTAL CURRENT ASSETS . . . . . . . . . . . . 540,657 359,479 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 421,647 433,516 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 38,256 40,520 TOTAL. . . . . . . . . . . . . . . . . . . $4,266,932 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 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. . . . . . . . . . . . . . . . . . . 663,889 663,633 Retained Earnings. . . . . . . . . . . . . . . . . . 167,714 179,461 Total Common Shareholder's Equity. . . . . . 1,092,061 1,103,552 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 19,116 19,359 Subject to Mandatory Redemption. . . . . . . . . . 22,310 22,310 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,449,232 1,472,451 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,582,719 2,617,672 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 131,027 120,281 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 176,005 80,004 Short-term Debt. . . . . . . . . . . . . . . . . . . 115,150 76,400 Accounts Payable . . . . . . . . . . . . . . . . . . 85,718 110,882 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 35,791 35,719 Customer Deposits. . . . . . . . . . . . . . . . . . 13,257 14,123 Interest Accrued . . . . . . . . . . . . . . . . . . 20,017 19,990 Revenue Refunds Accrued. . . . . . . . . . . . . . . 22,237 95,267 Energy Marketing and Trading Contracts . . . . . . . 191,801 24,076 Other. . . . . . . . . . . . . . . . . . . . . . . . 81,663 78,808 TOTAL CURRENT LIABILITIES. . . . . . . . . . 741,639 535,269 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 653,003 643,711 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 59,887 62,231 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 98,657 67,874 CONTINGENCIES (Note 6) TOTAL. . . . . . . . . . . . . . . . . . . $4,266,932 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 50,297 $ 48,323 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . . 74,302 71,825 Deferred Federal Income Taxes. . . . . . . . . . . . . . . 13,895 2,151 Deferred Investment Tax Credits. . . . . . . . . . . . . . (2,344) (2,366) Deferred Power Supply Costs (net). . . . . . . . . . . . . 23,208 15,474 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . . 18,981 (1,367) Fuel, Materials and Supplies . . . . . . . . . . . . . . . (17,635) (14,079) Accrued Utility Revenues . . . . . . . . . . . . . . . . . 7,266 14,726 Accounts Payable . . . . . . . . . . . . . . . . . . . . . (25,164) (20,170) Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . (73,030) 37,862 Other (net). . . . . . . . . . . . . . . . . . . . . . . . . (9,128) 5,342 Net Cash Flows From Operating Activities . . . . . . . 60,648 157,721 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . . (86,808) (89,608) Proceeds from Sale of Property . . . . . . . . . . . . . . . 200 880 Net Cash Flows Used For Investing Activities . . . . . (86,608) (88,728) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . . - 25,000 Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 148,751 193,431 Change in Short-term Debt (net). . . . . . . . . . . . . . . 38,750 (89,300) Retirement of Cumulative Preferred Stock . . . . . . . . . . (149) (190) Retirement of Long-term Debt . . . . . . . . . . . . . . . . (77,236) (138,471) Dividends Paid on Common Stock . . . . . . . . . . . . . . . (60,696) (59,458) Dividends Paid on Cumulative Preferred Stock . . . . . . . . (1,134) (1,142) Net Cash Flows From (Used For) Financing Activities. . 48,286 (70,130) Net Increase (Decrease) in Cash and Cash Equivalents . . . . . 22,326 (1,137) Cash and Cash Equivalents at Beginning of Period . . . . . . . 7,755 6,947 Cash and Cash Equivalents at End of Period . . . . . . . . . . $ 30,081 $ 5,810 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $61,693,000 and $62,272,000 and for income taxes was $18,062,000 and $30,981,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $8,845,000 and $11,893,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In May 1999 the Company issued $150 million of 6.60% senior unsecured notes due 2009. During the first six months of 1999, the Company reacquired the following first mortgage bonds for $77 million. 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 3. 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 upon the Governor's signature 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 that an effective competitive market exists, on January 1, 2004. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded 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 may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. Management has concluded that as of June 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 should enable the Company to determine its ability to recover stranded costs. When capped rates and the wires charge are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the 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 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 and other pertinent information, it is not possible at this time to determine if any of the Company's plants are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books applicable to the Virginia generating business at June 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, 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 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 in the fourth quarter of 2000. 4. RATE MATTERS As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company had requested a rehearing of a June 1998 Federal Energy Regulatory Commission (FERC) order which granted an annual rate increase of $3.4 million in response to a request for an $8.7 million annual rate increase. The FERC had authorized the Company to implement the $8.7 million annual rate increase subject to refund in 1992. In April 1999, the FERC denied the rehearing request. The Company completed the FERC ordered refund to customers of $46.8 million including interest in July 1999. A liability for the refunds and interest had previously been recorded by the Company. The FERC issued orders 888 and 889 in April 1996 which required each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own 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. On July 29, 1999, the FERC approved a draft order which rules on the AEP System's pending Open Access Transmission Tariff. This approved order has certain unfavorable pricing issues for which the AEP System has 30 days to seek rehearing. If the Commission's order is ultimately upheld the Company as a member of the AEP System will have to make refunds including interest. As of June 30, 1999 the Company has not made any provisions for its share of a potential refund which is preliminarily estimated to be approximately $6 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 open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes in the Company's non-Virginia jurisdictions. The Virginia jurisdiction net mark-to-market pre-tax gain of $2.3 million for the six months ended June 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. 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 June 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. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 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. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 1999 vs. SECOND QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased $4.1 million or 27% in the second quarter due to a decline in residential and wholesale sales. The increase in net income of $2 million or 4% in the year-to-date period is due to increased retail sales reflecting colder winter weather. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . . $(29.3) (7) $(17.0) (2) Fuel Expense . . . . . . . . (1.5) (2) 13.8 7 Purchased Power Expense. . . (26.2) (30) (44.9) (29) Other Operation Expense. . . (2.3) (4) 5.6 5 Maintenance Expense. . . . . 6.9 22 0.0 - Federal Income Taxes . . . . (4.7) (53) 1.7 6 Operating revenues decreased for both the second quarter and year-to-date period due predominantly to a decline in wholesale sales. The reduction in wholesale sales in the year-to-date period was partly offset by an increase in more profitable retail sales in the first quarter. Also contributing to the second quarter decline was a decrease in residential sales of 8% reflecting milder spring weather. The reduction in wholesale sales is largely attributable to the termination of a contract with several municipal customers and mild weather in the second quarter. The increase in fuel expense in the year-to-date period was due to an increase in generation to meet the increase in retail demand during the first quarter. A reduction in the net cost of fuel consumed reflecting lower prices for coal burned partly offset the effect of the increased generation. Purchased power expense decreased in both periods reflecting a decline in purchases from unaffiliated entities and the American Electric Power System Power Pool and a lower average price. The decrease in the average price reflects the reduced demand for wholesale energy. The need to purchase power decreased due to the decline in wholesale sales and the increase in generation in the year-to-date period. A reduction in employee benefit costs as a result of accrual adjustments for worker's compensation accounted for the decrease in other operation expense in the second quarter. For the year-to-date period, other operation expense increased due to employee incentive compensation plan accrual adjustments. Maintenance expense increased in the second quarter as a result of outages at Amos and Kanawha River plants for boiler repairs. The decrease in federal income tax expense attributable to operations in the second quarter was primarily due to a decrease in pre-tax operating income. FINANCIAL CONDITION Total plant and property additions including capital leases for the first six months of 1999 were $96 million. During the first six 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 $77 million principal amount of first mortgage bonds with interest rates from 7.8% to 8.43%. Short-term debt increased by $39 million from year-end balances. 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 upon the Governor's signature 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 that an effective competitive market exists, on January 1, 2004. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded 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 may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. Management has concluded that as of June 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 should enable the Company to determine its ability to recover stranded costs. When capped rates and the wires charge are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the 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 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 and other pertinent information, it is not possible at this time to determine if any of the Company's plants are impaired in accordance with SFAS 121. The amount of regulatory assets recorded on the books applicable to the Virginia generating business at June 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, 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 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 in the fourth quarter of 2000. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities 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 June 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. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The Company, 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. 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 plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. 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 following chart shows the Company's progress toward becoming ready for the Y2K as of June 30, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999 100% replacing or retiring 100% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 100% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. Costs to Address the Company's Year 2000 Issues - Through June 30, 1999, the Company has spent $11 million on the Y2K project and, estimates spending an additional $4 million to $6 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 cost of becoming Y2K compliant 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 may 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 as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company is establishing contingency plans for its business units to address alternatives if Y2K related failures occur. These contingency plans will be developed 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 Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $301,419 $298,263 $580,486 $564,662 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 49,144 46,860 95,000 93,840 Purchased Power. . . . . . . . . . . . 59,255 58,782 114,446 106,619 Other Operation. . . . . . . . . . . . 46,514 46,783 92,483 91,365 Maintenance. . . . . . . . . . . . . . 18,374 14,889 32,320 29,196 Depreciation . . . . . . . . . . . . . 23,522 22,844 46,706 45,694 Taxes Other Than Federal Income Taxes. 30,051 27,690 61,129 57,626 Federal Income Taxes . . . . . . . . . 20,086 23,264 37,882 37,942 TOTAL OPERATING EXPENSES . . . 246,946 241,112 479,966 462,282 OPERATING INCOME . . . . . . . . . . . . 54,473 57,151 100,520 102,380 NONOPERATING INCOME (LOSS) . . . . . . . (478) 1,256 (117) 1,228 INCOME BEFORE INTEREST CHARGES . . . . . 53,995 58,407 100,403 103,608 INTEREST CHARGES . . . . . . . . . . . . 19,436 19,665 38,426 39,221 NET INCOME . . . . . . . . . . . . . . . 34,559 38,742 61,977 64,387 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 532 532 1,065 1,065 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,027 $ 38,210 $ 60,912 $ 63,322 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $191,327 $142,623 $186,441 $138,172 NET INCOME . . . . . . . . . . . . . . . 34,559 38,742 61,977 64,387 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 21,999 20,661 43,998 41,322 Cumulative Preferred Stock . . . . . 438 438 875 875 Capital Stock Expense. . . . . . . . . 95 95 191 191 BALANCE AT END OF PERIOD . . . . . . . . $203,354 $160,171 $203,354 $160,171 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)
June 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,535,336 $1,526,869 Transmission . . . . . . . . . . . . . . . . . . . . 346,714 339,934 Distribution . . . . . . . . . . . . . . . . . . . . 971,086 938,283 General. . . . . . . . . . . . . . . . . . . . . . . 134,273 130,002 Construction Work in Progress. . . . . . . . . . . . 103,598 118,477 Total Electric Utility Plant . . . . . . . . 3,091,007 3,053,565 Accumulated Depreciation . . . . . . . . . . . . . . 1,171,875 1,134,348 NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,919,132 1,919,217 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 95,506 73,088 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 7,850 7,206 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 81,118 89,522 Affiliated Companies . . . . . . . . . . . . . . . 33,808 17,966 Miscellaneous. . . . . . . . . . . . . . . . . . . 5,847 11,989 Allowance for Uncollectible Accounts . . . . . . . (3,093) (2,598) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 19,753 22,140 Materials and Supplies . . . . . . . . . . . . . . . 37,836 33,263 Accrued Utility Revenues . . . . . . . . . . . . . . 53,625 40,127 Energy Marketing and Trading Contracts . . . . . . . 111,655 12,670 Prepayments. . . . . . . . . . . . . . . . . . . . . 37,801 29,084 TOTAL CURRENT ASSETS . . . . . . . . . . . . 386,200 261,369 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 339,480 353,369 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 38,129 74,647 TOTAL. . . . . . . . . . . . . . . . . . . $2,778,447 $2,681,690 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 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. . . . . . . . . . . . . . . . . . . 572,682 572,492 Retained Earnings. . . . . . . . . . . . . . . . . . 203,354 186,441 Total Common Shareholder's Equity. . . . . . 817,062 799,959 Cumulative Preferred Stock - Subject to Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000 Long-term Debt . . . . . . . . . . . . . . . . . . . 946,058 959,786 TOTAL CAPITALIZATION . . . . . . . . . . . . 1,788,120 1,784,745 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 44,697 42,176 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 14,000 - Short-term Debt. . . . . . . . . . . . . . . . . . . 70,400 52,500 Accounts Payable - General . . . . . . . . . . . . . 30,259 34,631 Accounts Payable - Affiliated Companies. . . . . . . 34,819 37,132 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 109,453 141,831 Interest Accrued . . . . . . . . . . . . . . . . . . 14,387 14,355 Energy Marketing and Trading Contracts . . . . . . . 112,206 13,682 Other. . . . . . . . . . . . . . . . . . . . . . . . 27,114 37,197 TOTAL CURRENT LIABILITIES. . . . . . . . . . 412,638 331,328 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 438,152 442,100 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 46,973 48,710 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 47,867 32,631 CONTINGENCIES (Note 6) TOTAL. . . . . . . . . . . . . . . . . . . $2,778,447 $2,681,690 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 61,977 $ 64,387 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . . 46,837 45,808 Deferred Federal Income Taxes. . . . . . . . . . . . . . 2,697 3,959 Deferred Investment Tax Credits. . . . . . . . . . . . . (1,737) (1,775) Deferred Collection of Fuel Costs (net). . . . . . . . . 4,252 (5,753) Amortization of Deferred Property Taxes. . . . . . . . . 34,406 32,514 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (801) 1,709 Fuel, Materials and Supplies . . . . . . . . . . . . . . (2,186) (33) Accrued Utility Revenues . . . . . . . . . . . . . . . . (13,498) (13,677) Prepayments. . . . . . . . . . . . . . . . . . . . . . . (8,717) (7,909) Accounts Payable . . . . . . . . . . . . . . . . . . . . (6,685) 544 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (32,378) (51,022) Other (net). . . . . . . . . . . . . . . . . . . . . . . . (10,806) 8,491 Net Cash Flows From Operating Activities . . . . . . 73,361 77,243 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (46,005) (57,626) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 261 2,287 Net Cash Flows Used For Investing Activities . . . . (45,744) (55,339) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 111,075 Change in Short-term Debt (net). . . . . . . . . . . . . . 17,900 (14,075) Retirement of Long-term Debt . . . . . . . . . . . . . . . - (81,750) Dividends Paid on Common Stock . . . . . . . . . . . . . . (43,998) (41,322) Dividends Paid on Cumulative Preferred Stock . . . . . . . (875) (437) Net Cash Flows Used For Financing Activities . . . . (26,973) (26,509) Net Increase (Decrease) in Cash and Cash Equivalents . . . . 644 (4,605) Cash and Cash Equivalents at Beginning of Period . . . . . . 7,206 12,626 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 7,850 $ 8,021 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $36,491,000 and $37,667,000 and for income taxes was $14,207,000 and $20,886,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $4,043,000 and $6,060,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES 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 that are included in cost of service on a settlement basis for ratemaking purposes. 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 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. On July 29, 1999, the FERC approved a draft order which rules on the AEP System's pending Open Access Transmission Tariff. This approved order has certain unfavorable pricing issues for which the AEP System has 30 days to seek rehearing. If the Commission's order is ultimately upheld the Company as a member of the AEP System will have to make refunds including interest. As of June 30, 1999 the Company has not made any provisions for its share of a potential refund which is preliminarily estimated to be approximately $3 million. 5. OHIO RESTRUCTURING LEGISLATION On July 6, 1999, the Governor of the State of Ohio signed The Ohio Electric Restructuring Act of 1999. The Act provides for customer choice of electricity supplier and a residential rate reduction of 5% of the unbundled generation rate beginning on January 1, 2001. The Act 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 and other stranded transition costs. Retail electric services that will be competitive are defined in the Act as electric generation service, aggregation service, and power marketing and brokering. The PUCO has been granted broad oversight responsibility under the Act. The Act requires the PUCO to promulgate rules for competitive retail electric generation service. The Act further provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled rates paid by customers who do not switch generation suppliers and through a wires charges by customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs and other costs. Recovery of transition revenues can under certain circumstances extend beyond the five-year 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 Act also provides that the property tax assessment percentage on electric generation equipment be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will also 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 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. These changes should put the Company's generation operations on an equal level with other competitive businesses in Ohio regarding state taxation. 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 liabilities and assets certain revenues and expenses consistent with the regulatory process in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." At June 30, 1999, the amount of regulatory assets recorded on the books applicable to the generating business is estimated to be $275 million before related tax effects. Whether the Company will have any additional stranded transition costs related to an economic impairment of its generating assets is dependent on several factors including the assumed future market price for electricity. The Company intends to seek recovery in its transition filing of all regulatory assets and any other stranded transition costs which may be identified. At this time management is unable to predict the outcome of the regulatory process or its impact on results of operations, cash flows or financial condition. Therefore, the Company will not be discontinuing application of SFAS 71 until the regulatory process is completed. Upon discontinuance of the application of SFAS 71 the Company will have to write off its generation-related regulatory assets 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." Absent the determination in the regulatory process of transition revenues and other pertinent information, it is not possible at this time to determine if any of the Company's plants are impaired in accordance with SFAS 121. Should the Company be granted recovery of its regulatory assets and/or any economic asset impairments it can record an offsetting regulatory asset. Should the PUCO not approve the Company's request for recovery of its generation-related regulatory assets and/or other stranded transition costs it would have an adverse impact on future results of operations and possibly financial condition. The Company does not expect to be able to determine the impact of the legislation on its financial statements until the regulatory process is complete. The PUCO is required to complete its regulatory process no later than October 31, 2000. 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 June 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. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 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. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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 or reflected in the future market price of electricity, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 1999 vs. SECOND QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 Net income decreased $4.2 million or 11% in the second quarter and $2.4 million or 4% in the year-to-date period primarily due to increased operating expenses. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $ 3.2 1 $15.8 3 Fuel Expense. . . . . . . . 2.3 5 1.2 1 Purchased Power Expense . . 0.5 1 7.8 7 Maintenance Expense . . . . 3.5 23 3.1 11 Taxes Other Than Federal Income Taxes . . . . . . . 2.4 9 3.5 6 Federal Income Taxes. . . . (3.2) (14) (0.1) - Operating revenues increased in both the second quarter and the year-to-date period due predominantly to increased retail sales. Retail revenues and sales increased 4% and 3%, respectively, in the second quarter and 5% in the year-to-date period due to customer growth and the effect of colder winter weather on residential and commercial usage in the year-to-date period. Fuel expense increased in the second quarter due to the operation of the fuel clause adjustment mechanism as prior period deferrals of underrecovered fuel costs were amortized to expense in the current period concurrent with rate recovery. The increase in purchased power expense in the year-to-date period is primarily due to increased capacity charges from the American Electric Power (AEP) 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 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. Maintenance expense increased primarily due to scheduled power plant maintenance outages of the Zimmer Plant and one unit of the Conesville Plant in 1999. The increase in taxes other than federal income taxes was primarily due to higher property tax rates in 1999 and the effect of a favorable property tax accrual adjustment recorded in May 1998. Federal income taxes attributable to operations decreased in the second quarter primarily as a result of a decrease in pre-tax operating income. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . $336,553 $348,271 $ 670,666 $676,739 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 42,123 37,875 83,923 82,754 Purchased Power. . . . . . . . . . . . 67,510 86,504 129,825 144,663 Other Operation. . . . . . . . . . . . 115,258 82,850 206,833 159,283 Maintenance. . . . . . . . . . . . . . 24,621 33,259 55,823 60,337 Depreciation and Amortization. . . . . 37,495 36,234 74,480 72,027 Taxes Other Than Federal Income Taxes. 17,256 16,105 36,285 32,497 Federal Income Taxes . . . . . . . . . 5,324 13,250 17,693 31,616 TOTAL OPERATING EXPENSES . . . 309,587 306,077 604,862 583,177 OPERATING INCOME . . . . . . . . . . . . 26,966 42,194 65,804 93,562 NONOPERATING INCOME. . . . . . . . . . . 1,556 3,585 3,291 2,595 INCOME BEFORE INTEREST CHARGES . . . . . 28,522 45,779 69,095 96,157 INTEREST CHARGES . . . . . . . . . . . . 18,777 17,243 39,280 33,877 NET INCOME . . . . . . . . . . . . . . . 9,745 28,536 29,815 62,280 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,215 1,202 2,429 2,419 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 8,530 $ 27,334 $ 27,386 $ 59,861 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $243,346 $281,975 $253,154 $278,814 NET INCOME . . . . . . . . . . . . . . . 9,745 28,536 29,815 62,280 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 28,664 29,366 57,328 58,732 Cumulative Preferred Stock . . . . . 1,182 1,183 2,364 2,367 Capital Stock Expense. . . . . . . . . 33 19 65 52 BALANCE AT END OF PERIOD . . . . . . . . $223,212 $279,943 $223,212 $279,943 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)
June 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,583,294 $2,565,041 Transmission . . . . . . . . . . . . . . . . . . . . 919,595 913,495 Distribution . . . . . . . . . . . . . . . . . . . . 785,634 768,888 General (including nuclear fuel) . . . . . . . . . . 232,486 228,013 Construction Work in Progress. . . . . . . . . . . . 167,441 156,411 Total Electric Utility Plant . . . . . . . . 4,688,450 4,631,848 Accumulated Depreciation and Amortization. . . . . . 2,143,088 2,081,355 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,545,362 2,550,493 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . 688,793 648,307 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 214,515 197,368 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 20,839 12,465 Accounts Receivable (net). . . . . . . . . . . . . . 141,220 130,746 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 36,466 20,857 Materials and Supplies . . . . . . . . . . . . . . . 85,941 78,009 Accrued Utility Revenues . . . . . . . . . . . . . . 31,354 37,277 Energy Marketing and Trading Contracts . . . . . . . 121,939 14,105 Prepayments. . . . . . . . . . . . . . . . . . . . . 5,880 4,848 TOTAL CURRENT ASSETS . . . . . . . . . . . . 443,639 298,307 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 525,631 421,475 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 31,064 32,573 TOTAL. . . . . . . . . . . . . . . . . . . $4,449,004 $4,148,523 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 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. . . . . . . . . . . . . . . . . . . 732,672 732,605 Retained Earnings. . . . . . . . . . . . . . . . . . 223,212 253,154 Total Common Shareholder's Equity. . . . . . 1,012,468 1,042,343 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 9,266 9,273 Subject to Mandatory Redemption. . . . . . . . . . 68,445 68,445 Long-term Debt . . . . . . . . . . . . . . . . . . . 982,604 1,140,789 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,072,783 2,260,850 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning. . . . . . . . . . . . . . . 480,938 445,934 Other. . . . . . . . . . . . . . . . . . . . . . . . 247,389 240,320 TOTAL OTHER NONCURRENT LIABILITIES . . . . . 728,327 686,254 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 133,000 35,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 269,180 108,700 Accounts Payable - General . . . . . . . . . . . . . 54,488 53,187 Accounts Payable - Affiliated Companies. . . . . . . 29,114 37,647 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 11,299 35,161 Interest Accrued . . . . . . . . . . . . . . . . . . 14,355 15,279 Revenue Refunds Accrued. . . . . . . . . . . . . . . 55,000 - Obligations Under Capital Leases . . . . . . . . . . 10,744 9,667 Energy Marketing and Trading Contracts . . . . . . . 122,541 15,228 Dividends Declared . . . . . . . . . . . . . . . . . 29,846 1,183 Other. . . . . . . . . . . . . . . . . . . . . . . . 76,093 70,882 TOTAL CURRENT LIABILITIES. . . . . . . . . . 805,660 381,934 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 573,752 559,288 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 125,983 129,779 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 86,859 88,712 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 55,640 41,706 COMMITMENTS AND CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $4,449,004 $4,148,523 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 29,815 $ 62,280 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 76,431 74,126 Amortization of Incremental Nuclear Refueling Outage Expenses (net). . . . . . . . . . . . 4,695 8,518 Unrecovered Fuel and Purchased Power . . . . . . . . . . (63,922) (34,369) Deferred Nuclear Outage Costs (net). . . . . . . . . . . (60,000) - Deferred Federal Income Taxes. . . . . . . . . . . . . . 23,448 7,839 Deferred Investment Tax Credits. . . . . . . . . . . . . (3,796) (3,818) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (10,474) (61,320) Fuel, Materials and Supplies . . . . . . . . . . . . . . (23,541) (10,343) Accrued Utility Revenues . . . . . . . . . . . . . . . . 5,923 (11,384) Accounts Payable . . . . . . . . . . . . . . . . . . . . (7,232) 57,979 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (23,862) (12,041) Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 55,000 - Dividends Declared . . . . . . . . . . . . . . . . . . . 28,663 - Other (net). . . . . . . . . . . . . . . . . . . . . . . . (25,103) (8,581) Net Cash Flows From Operating Activities . . . . . . 6,045 68,886 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (63,316) (61,203) Proceeds from Sale of Property . . . . . . . . . . . . . . 1,198 1,391 Net Cash Flows Used for Investing Activities . . . . (62,118) (59,812) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 122,222 Retirement of Long-term Debt . . . . . . . . . . . . . . . (65,000) (35,000) Change in Short-term Debt (net). . . . . . . . . . . . . . 160,480 (8,800) Retirement of Cumulative Preferred Stock . . . . . . . . . (5) (39) Dividends Paid on Common Stock . . . . . . . . . . . . . . (28,664) (58,732) Dividends Paid on Cumulative Preferred Stock . . . . . . . (2,364) (2,368) Net Cash Flows From Financing Activities . . . . . . 64,447 17,283 Net Increase in Cash and Cash Equivalents. . . . . . . . . . 8,374 26,357 Cash and Cash Equivalents at Beginning of Period . . . . . . 12,465 5,860 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 20,839 $ 32,217 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $38,775,000 and $32,651,000 and for income taxes was $19,217,000 and $15,054,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $6,901,000 and $18,801,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES During the first six months of 1999, the Company reacquired the following first mortgage bonds for $65 million: 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 In July 1999 the Company issued $150 million of 6-7/8% senior unsecured notes due 2004. 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 six months of 1999, the Company issued $160 million of short-term debt. 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 that are included in cost of service on a settlement basis for ratemaking purposes. 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 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. On July 29, 1999, the FERC approved a draft order which rules on the AEP System's pending Open Access Transmission Tariff. This approved order has certain unfavorable pricing issues for which the AEP System has 30 days to seek rehearing. If the Commission's order is ultimately upheld the Company as a member of the AEP System will have to make refunds including interest. As of June 30, 1999 the Company has not made any provisions for its share of a potential refund which is preliminarily estimated to be approximately $4 million. 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 June 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. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 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. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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 a material adverse effect on future results of operations, cash flows and possibly financial condition. 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. On June 24, 1999, the Boards of Directors of American Electric Power Company, Inc. and the Company both approved a plan to restart the Cook Plant. Unit 2 is scheduled to return to service in April 2000 and Unit 1 is to return to service in September 2000. This approval follows 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 June 30, 1999, $70 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. At June 30, 1999, the regulatory asset was $129 million. 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 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 the $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 recoveries 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 will be applied to 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 freeze rates and 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 outage. At a hearing on June 30, 1999, the MPSC granted a continuance to the one intervenor who opposed the approval of the settlement agreement. A hearing has been scheduled for August 13, 1999. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as current period operation and maintenance expense in 1999 and 2000. Through June 30, 1999, $192 million has been spent, of which $108 million was incurred in the first half of 1999. Pursuant to the Indiana settlement agreement $60 million of incremental operation and maintenance costs were deferred through June 30, 1999. The Indiana jurisdiction deferral is limited to up to $150 million of incremental restart costs incurred in 1999. The pending Michigan settlement limits deferrals to $50 million of non-fuel operation and maintenance 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 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 SECOND QUARTER 1999 vs. SECOND QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased $18.8 million or 66% in the second quarter and $32.5 million or 52% for the year-to-date period due primarily to increased operation expense related to an extended outage of the Cook Nuclear Plant which was shut down in September 1997. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . $(11.7) (3) $ (6.1) (1) Fuel Expense. . . . . . . 4.2 11 1.2 1 Purchased Power Expense . (19.0) (22) (14.8) (10) Other Operation Expense . 32.4 39 47.6 30 Maintenance Expense . . . (8.6) (26) (4.5) (7) Taxes Other Than Federal Income Taxes . . 1.2 7 3.8 12 Federal Income Taxes. . . (7.9) (60) (13.9) (44) Interest Charges. . . . . 1.5 9 5.4 16 Operating revenues decreased in both the second quarter and the year-to-date period due primarily to a decrease in retail revenues reflecting the effect of an Indiana settlement agreement on fuel recovery billings in the Company's Indiana retail jurisdiction. 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 unrecovered Cook replacement power and restart costs were deferred for future amortization. Fuel expense increased in the second quarter due to an increase in generation reflecting increased availability of the Company's coal fired generating units in 1999. The decrease in purchased power expense resulted from decreased purchases reflecting the increased generating plant availability. Other operation expense increased due to increased nuclear engineering and contract employee costs during the extended Cook shutdown and restart efforts. The deferral in 1999 of maintenance costs during the extended shutdown of the Cook Plant under the terms of the Indiana settlement agreement accounted for the decrease in maintenance expense. Increases in real and personal property, gross receipts and single business taxes accounted for the increases in taxes other than federal income taxes. Federal income taxes attributable to operations decreased in both periods as a result of a decrease in pre-tax operating income. Interest expense increased in the second quarter due to an increase in short-term borrowing to fund the expenditures for the Cook Plant restart effort. In the year-to-date period interest expense increased due to increased long-term debt interest expense reflecting higher outstanding balances, the accrual of interest for revenue refunds ordered by the Indiana commission as part of the settlement agreement and the increase in short-term borrowings. FINANCIAL CONDITION Total plant and property additions including capital leases for the year-to-date period were $71 million. During the first six months of 1999 the Company redeemed $65 million principal amount of first mortgage bonds with interest rates from 6.55% to 6.80%. Short-term debt outstanding increased by $160 million from year-end balances. In July 1999 the Company issued $150 million of 6-7/8% senior unsecured notes due 2004. The short-term debt limitation of the Company was increased from $300 million to $500 million with the approval of the Securities and Exchange Commission. 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 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 Nuclear Plant Shutdown As discussed in MDA 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. On June 24, 1999, the Boards of Directors of American Electric Power Company, Inc. and the Company both approved a plan to restart the Cook Plant. Unit 2 is scheduled to return to service in April 2000 and Unit 1 is to return to service in September 2000. This approval follows 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 June 30, 1999, $70 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 estimated costs reflected in billings have been recorded as a regulatory asset under the Indiana and Michigan retail jurisdictional fuel cost recovery mechanisms. At June 30, 1999, the regulatory asset was $129 million. 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 credit of $55 million, including interest, to Indiana retail customers' bills; the deferral of any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $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 recoveries 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 will be applied to 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 freeze rates and 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 outage. At a hearing on June 30, 1999, the MPSC granted a continuance to the one intervenor who opposed the approval of the settlement agreement. A hearing has been scheduled for August 13, 1999. Expenditures for the restart of the Cook units are estimated to total approximately $574 million and will be accounted for primarily as current period operation and maintenance expense in 1999 and 2000. Through June 30, 1999, $192 million has been spent, of which $108 million was incurred in the first half of 1999. Pursuant to the Indiana settlement agreement $60 million of incremental operation and maintenance costs were deferred through June 30, 1999. The Indiana jurisdiction deferral is limited to up to $150 million of incremental restart costs incurred in 1999. The pending Michigan settlement limits deferrals to $50 million of non-fuel operation and maintenance costs. The costs of the extended outage and restart efforts will have a material adverse effect on 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 results of operations, cash flows and financial condition. Air Quality As discussed in MDA 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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 a material adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities 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 AEP 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 June 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. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The Company, 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 US 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. 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 plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. 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 following chart shows the Company's progress toward becoming ready for the Y2K as of June 30, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation 2/24/1998 100% 5/31/1998 100% of the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999 100% replacing or retiring 100% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 99%* systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. *The Company is upgrading a meteorological reporting system used at the Cook Plant, a mission critical IT system, for Y2K readiness and it is anticipated that the upgrade should be completed by December 15, 1999. Costs to Address the Company's Year 2000 Issues - Through June 30, 1999, the Company has spent $6 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 cost of becoming Y2K compliant 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 may 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 as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company is establishing contingency plans for its business units to address alternatives if Y2K related failures occur. These contingency plans will be developed 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 Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . $86,231 $84,021 $176,972 $171,366 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . 22,284 18,184 41,975 40,485 Purchased Power. . . . . . . . . . . . . 25,920 27,119 50,347 48,330 Other Operation. . . . . . . . . . . . . 11,768 11,992 24,119 22,986 Maintenance. . . . . . . . . . . . . . . 5,047 7,258 9,838 16,424 Depreciation and Amortization. . . . . . 7,287 6,978 14,477 13,888 Taxes Other Than Federal Income Taxes. . 2,682 2,260 5,216 4,752 Federal Income Taxes . . . . . . . . . . 1,010 599 5,407 2,779 TOTAL OPERATING EXPENSES. . . . . 75,998 74,390 151,379 149,644 OPERATING INCOME . . . . . . . . . . . . . 10,233 9,631 25,593 21,722 NONOPERATING LOSS. . . . . . . . . . . . . (41) (93) (155) (164) INCOME BEFORE INTEREST CHARGES . . . . . . 10,192 9,538 25,438 21,558 INTEREST CHARGES . . . . . . . . . . . . . 7,197 7,125 14,234 14,128 NET INCOME . . . . . . . . . . . . . . . . $ 2,995 $ 2,413 $ 11,204 $ 7,430 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . $72,218 $76,018 $71,452 $78,076 NET INCOME . . . . . . . . . . . . . . . . 2,995 2,413 11,204 7,430 CASH DIVIDENDS DECLARED. . . . . . . . . . 7,443 7,075 14,886 14,150 BALANCE AT END OF PERIOD . . . . . . . . . $67,770 $71,356 $67,770 $71,356 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)
June 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $ 267,658 $ 267,201 Transmission . . . . . . . . . . . . . . . . . . . . 340,617 326,989 Distribution . . . . . . . . . . . . . . . . . . . . 358,349 351,407 General. . . . . . . . . . . . . . . . . . . . . . . 66,452 68,038 Construction Work in Progress. . . . . . . . . . . . 22,083 30,076 Total Electric Utility Plant . . . . . . . . 1,055,159 1,043,711 Accumulated Depreciation and Amortization. . . . . . 326,751 315,546 NET ELECTRIC UTILITY PLANT . . . . . . . . . 728,408 728,165 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 18,376 12,078 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 2,436 1,935 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 18,560 23,295 Affiliated Companies . . . . . . . . . . . . . . . 14,087 8,797 Miscellaneous. . . . . . . . . . . . . . . . . . . 3,268 4,019 Allowance for Uncollectible Accounts . . . . . . . (1,094) (848) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 9,358 7,888 Materials and Supplies . . . . . . . . . . . . . . . 16,570 13,652 Accrued Utility Revenues . . . . . . . . . . . . . . 13,052 13,560 Energy Marketing and Trading Contracts . . . . . . . 45,027 4,726 Prepayments. . . . . . . . . . . . . . . . . . . . . 1,954 1,657 TOTAL CURRENT ASSETS . . . . . . . . . . . . 123,218 78,681 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 92,327 92,447 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 8,560 10,476 TOTAL. . . . . . . . . . . . . . . . . . . $ 970,889 $ 921,847 See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
June 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. . . . . . . . . . . . . . . . . . 67,770 71,452 Total Common Shareholder's Equity. . . . . . 276,970 270,652 Long-term Debt . . . . . . . . . . . . . . . . . . . 271,228 308,838 TOTAL CAPITALIZATION . . . . . . . . . . . . 548,198 579,490 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 24,745 26,827 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 60,000 60,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 56,350 20,350 Accounts Payable - General . . . . . . . . . . . . . 9,363 12,917 Accounts Payable - Affiliated Companies. . . . . . . 14,166 11,814 Customer Deposits. . . . . . . . . . . . . . . . . . 4,006 4,038 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 9,244 7,256 Interest Accrued . . . . . . . . . . . . . . . . . . 5,522 6,241 Energy Marketing and Trading Contracts . . . . . . . 45,245 5,089 Other. . . . . . . . . . . . . . . . . . . . . . . . 13,476 13,612 TOTAL CURRENT LIABILITIES. . . . . . . . . . 217,372 141,317 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 159,541 158,706 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 13,599 14,200 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 7,434 1,307 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $970,889 $921,847 See Notes to Financial Statements.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 11,204 $ 7,430 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 14,480 13,894 Deferred Federal Income Taxes. . . . . . . . . . . . . . 912 368 Deferred Investment Tax Credits. . . . . . . . . . . . . (601) (610) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 442 (2,792) Fuel, Materials and Supplies . . . . . . . . . . . . . . (4,388) (1,234) Accrued Utility Revenues . . . . . . . . . . . . . . . . 508 2,409 Accounts Payable . . . . . . . . . . . . . . . . . . . . (1,202) (2,281) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 1,988 (902) Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,258 811 Net Cash Flows From Operating Activities . . . . . . 24,601 17,093 INVESTING ACTIVITIES - Construction Expenditures . . . . . . (17,402) (17,705) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . 10,000 10,000 Change in Short-term Debt (net). . . . . . . . . . . . . . 36,000 6,600 Retirement of Long-term Debt . . . . . . . . . . . . . . . (37,812) (2,203) Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (14,886) (14,150) Net Cash Flows From (Used For) Financing Activities. (6,698) 247 Net Increase (Decrease) in Cash and Cash Equivalents . . . . 501 (365) Cash and Cash Equivalents at Beginning of Period . . . . . . 1,935 1,381 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 2,436 $ 1,016 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $14,748,000 and $13,982,000 and for income taxes was $3,631,000 and $4,538,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $1,150,000 and $2,960,000 in 1999 and 1998, respectively. See Notes to Financial Statements.
KENTUCKY POWER COMPANY NOTES TO FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In April 1999 the Company redeemed a $25 million term loan note with a rate of 6.42% and in May 1999 the Company redeemed the principal amount of $12,797,000 of the 7.90% Series First Mortgage Bonds. 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 six months of 1999, the Company issued $36 million of short-term debt. 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 that are included in cost of service on a settlement basis for ratemaking purposes. 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 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. On July 29, 1999, the FERC approved a draft order which rules on the AEP System's pending Open Access Transmission Tariff. This approved order has certain unfavorable pricing issues for which the AEP System has 30 days to seek rehearing. If the Commission's order is ultimately upheld the Company as a member of the AEP System will have to make refunds including interest. As of June 30, 1999 the Company has not made any provisions for its share of a potential refund which is preliminarily estimated to be approximately $1 million. 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 June 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. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1992-1997 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. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The NOx SIP Call rule requires submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP Call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP Call. The imposition of these NOx reduction requirements on AEP System generating units would be approximately equivalent to the reductions contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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 a material adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 1999 vs. SECOND QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 Net income increased $0.6 million or 24% for the quarter and $3.8 million or 51% for the year-to-date period. The increases in net income were mainly attributable to increased operating revenues and a decline in maintenance costs. Income statement line items which changed significantly were: Increase(Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . . . $ 2.2 3 $ 5.6 3 Fuel Expense . . . . . . . . . 4.1 23 1.5 4 Purchased Power Expense. . . . (1.2) (4) 2.0 4 Other Operation Expense. . . . (0.2) (2) 1.1 5 Maintenance Expense. . . . . . (2.2) (30) (6.6) (40) Taxes Other Than Federal Income Taxes . . . . . . . . 0.4 19 0.5 10 Federal Income Taxes . . . . . 0.4 69 2.6 95 Operating revenues increased in the second quarter due to increased wholesale sales primarily to the American Electric Power System Power Pool (AEP Power Pool) while retail sales declined slightly. Wholesale sales rose as a result of increased availability of the Company's generation plant. In the second quarter of 1998 one of the two units at the Company's Big Sandy Plant was on an extended maintenance outage. The increase in operating revenues in the year-to-date period was due to increased retail sales reflecting colder winter weather. Fuel expense increased in the second quarter and the year-to-date period primarily due to increased generation and a rise in the average cost of fuel consumed. The increase in generation reflects the absence of an extended maintenance outage in 1999. The rise in fuel costs was due to an increase in the price of coal burned to produce electricity and included in fuel expense concurrent with recovery through fuel clause revenues. Changes in the cost of fuel are deferred until reflected in fuel clause billings to customers. The decrease in purchased power expense in the second quarter resulted from reduced purchases of power from unaffiliated entities and lower average purchase prices. The reductions resulted from a decreased need for purchased energy since the availability of Big Sandy Plant increased and a decline in demand by unaffiliated wholesale customers mainly due to mild weather. Purchased power expense increased in the year-to-date period primarily due to increased capacity charges from 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 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 increased in the year-to-date period due to accrual adjustments for employee pensions and benefits recorded in the first quarter of 1999 and 1998. The 1999 adjustment was unfavorable while the 1998 adjustment was favorable. The decline in maintenance expense is primarily attributable to decreased overhead distribution line and generating plant maintenance expenditures. In the first quarter of 1998 the repair and restoration of customers' 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 maintenance expense. Taxes other than federal income taxes increased in both periods primarily due to increased state income tax expense reflecting a rise in taxable income. The increase in federal income tax expense attributable to operations in both periods was primarily due to an increase in pre-tax operating income. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . $498,587 $523,671 $1,016,808 $1,039,343 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . 169,055 180,947 358,218 374,222 Purchased Power. . . . . . . . . . . . . 35,699 48,400 56,972 67,990 Other Operation. . . . . . . . . . . . . 82,829 82,942 167,890 163,843 Maintenance. . . . . . . . . . . . . . . 28,501 33,158 53,991 63,751 Depreciation and Amortization. . . . . . 37,397 35,998 74,182 71,861 Taxes Other Than Federal Income Taxes. . 41,952 41,862 85,805 84,520 Federal Income Taxes . . . . . . . . . . 29,826 30,499 67,466 64,222 TOTAL OPERATING EXPENSES . . . . 425,259 453,806 864,524 890,409 OPERATING INCOME . . . . . . . . . . . . . 73,328 69,865 152,284 148,934 NONOPERATING INCOME (LOSS) . . . . . . . . (492) 3,449 1,508 4,687 INCOME BEFORE INTEREST CHARGES . . . . . . 72,836 73,314 153,792 153,621 INTEREST CHARGES . . . . . . . . . . . . . 20,971 20,255 41,106 40,126 NET INCOME . . . . . . . . . . . . . . . . 51,865 53,059 112,686 113,495 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . 367 368 734 738 EARNINGS APPLICABLE TO COMMON STOCK. . . . $ 51,498 $ 52,691 $ 111,952 $ 112,757 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . $590,251 $597,442 $587,500 $590,151 NET INCOME . . . . . . . . . . . . . . . . 51,865 53,059 112,686 113,495 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . 57,703 52,775 115,406 105,550 Cumulative Preferred Stock . . . . . . 368 369 735 739 BALANCE AT END OF PERIOD . . . . . . . . . $584,045 $597,357 $584,045 $597,357 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)
June 30, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . . . . $2,676,712 $2,646,597 Transmission . . . . . . . . . . . . . . . . . . . . . . . 851,679 842,318 Distribution . . . . . . . . . . . . . . . . . . . . . . . 969,875 949,224 General (including mining assets). . . . . . . . . . . . . 718,745 689,815 Construction Work in Progress. . . . . . . . . . . . . . . 100,865 129,887 Total Electric Utility Plant . . . . . . . . . . . 5,317,876 5,257,841 Accumulated Depreciation and Amortization. . . . . . . . . 2,547,315 2,461,376 NET ELECTRIC UTILITY PLANT . . . . . . . . . . . . 2,770,561 2,796,465 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 246,654 218,311 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . . . . 101,648 89,652 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . . . . 288,445 215,665 Affiliated Companies . . . . . . . . . . . . . . . . . . 82,055 63,922 Miscellaneous. . . . . . . . . . . . . . . . . . . . . . 22,528 28,139 Allowance for Uncollectible Accounts . . . . . . . . . . (2,583) (1,678) Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 143,844 94,914 Materials and Supplies . . . . . . . . . . . . . . . . . . 92,977 86,870 Accrued Utility Revenues . . . . . . . . . . . . . . . . . 48,911 43,501 Energy Marketing and Trading Contracts . . . . . . . . . . 175,702 19,790 Prepayments. . . . . . . . . . . . . . . . . . . . . . . . 41,404 34,523 TOTAL CURRENT ASSETS . . . . . . . . . . . . . . . 994,931 675,298 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . . 572,025 551,776 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . . 82,570 102,830 TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,666,741 $4,344,680 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 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. . . . . . . . . . . . . . . . . . . . . . 462,366 462,335 Retained Earnings. . . . . . . . . . . . . . . . . . . . . 584,045 587,500 Total Common Shareholder's Equity. . . . . . . . . 1,367,612 1,371,036 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . . . . 17,211 17,370 Subject to Mandatory Redemption. . . . . . . . . . . . . 11,850 11,850 Long-term Debt . . . . . . . . . . . . . . . . . . . . . . 1,072,702 1,073,456 TOTAL CAPITALIZATION . . . . . . . . . . . . . . . 2,469,375 2,473,712 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . . 367,663 360,330 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . . . . 11,283 11,472 Short-term Debt. . . . . . . . . . . . . . . . . . . . . . 194,090 123,005 Accounts Payable . . . . . . . . . . . . . . . . . . . . . 261,265 235,787 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . 162,576 161,406 Interest Accrued . . . . . . . . . . . . . . . . . . . . . 13,367 14,187 Obligations Under Capital Leases . . . . . . . . . . . . . 29,234 28,310 Energy Marketing and Trading Contracts . . . . . . . . . . 176,569 22,480 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 92,750 97,916 TOTAL CURRENT LIABILITIES. . . . . . . . . . . . . 941,134 694,563 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . 702,342 711,913 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . 37,637 39,296 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . . 148,590 64,866 CONTINGENCIES (Note 7) TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,666,741 $4,344,680 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 112,686 $ 113,495 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . . . 93,008 87,091 Deferred Federal Income Taxes. . . . . . . . . . . . . . . . 1,603 2,480 Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . . (23,695) (22,968) Amortization of Deferred Property Taxes. . . . . . . . . . . 39,464 38,294 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . . . (84,397) (134,357) Fuel, Materials and Supplies . . . . . . . . . . . . . . . . (55,037) 3,906 Accrued Utility Revenues . . . . . . . . . . . . . . . . . . (5,410) (2,807) Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . (6,881) (6,055) Accounts Payable . . . . . . . . . . . . . . . . . . . . . . 25,478 114,553 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . 1,170 (19,733) Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . 44,808 81,078 Net Cash Flows From Operating Activities . . . . . . . . 142,797 254,977 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . . . (83,279) (71,323) Proceeds from Sale of Property and Other . . . . . . . . . . . 670 3,600 Net Cash Flows Used For Investing Activities . . . . . . (82,609) (67,723) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . 148,215 137,566 Change in Short-term Debt (net). . . . . . . . . . . . . . . . 71,085 31,400 Retirement of Cumulative Preferred Stock . . . . . . . . . . . (128) (47) Retirement of Long-term Debt . . . . . . . . . . . . . . . . . (151,223) (185,809) Dividends Paid on Common Stock . . . . . . . . . . . . . . . . (115,406) (105,550) Dividends Paid on Cumulative Preferred Stock . . . . . . . . . (735) (739) Net Cash Flows Used For Financing Activities . . . . . . (48,192) (123,179) Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . 11,996 64,075 Cash and Cash Equivalents at Beginning of Period . . . . . . . . 89,652 44,203 Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 101,648 $ 108,278 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $40,816,000 and $41,125,000 and for income taxes was $24,645,000 and $43,019,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $11,849,000 and $18,913,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 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 adjustments (consisting of only normal recurring accruals) 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% Ohio Air Quality Series C pollution control revenue bonds due 2026 and in June 1999 the Company issued $100 million of 6.75% senior unsecured notes due 2004. During the first six months of 1999, the Company reacquired the following first mortgage bonds for $88 million. 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 In May 1999 the Company reacquired $50 million of 7.40% Ohio Air Quality Series B pollution control revenue bonds due 2009. 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 that are included in cost of service on a settlement basis for ratemaking purposes. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. OHIO RESTRUCTURING LEGISLATION On July 6, 1999, the Governor of the State of Ohio signed The Ohio Electric Restructuring Act of 1999. The Act provides for customer choice of electricity supplier and a residential rate reduction of 5% of the unbundled generation rate beginning on January 1, 2001. The Act 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 and other stranded transition costs. Retail electric services that will be competitive are defined in the Act as electric generation service, aggregation service, and power marketing and brokering. The PUCO has been granted broad oversight responsibility under the Act. The Act requires the PUCO to promulgate rules for competitive retail electric generation service. The Act further provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled rates paid by customers who do not switch generation suppliers and through a wires charges by customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs and other costs. Recovery of transition revenues can under certain circumstances extend beyond the five-year 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 Act also provides that the property tax assessment percentage on electric generation equipment be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will also 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 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. These changes should put the Company's generation operations on an equal level with other competitive businesses in Ohio regarding state taxation. 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 liabilities and assets certain revenues and expenses consistent with the regulatory process in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." At June 30, 1999 the amount of regulatory assets recorded on the books applicable to the generating business is estimated to be $363 million before related tax effects. Whether the Company will have any additional stranded transition costs related to an economic impairment of its generating assets is dependent on several factors including the assumed future market price for electricity. The Company intends to seek recovery in its transition filing of all regulatory assets and any other stranded transition costs which may be identified. At this time management is unable to predict the outcome of the regulatory process or its impact on results of operations, cash flows or financial condition. Therefore, the Company will not be discontinuing application of SFAS 71 until the regulatory process is completed. Upon discontinuance of the application of SFAS 71 the Company will have to write off its Ohio generation-related regulatory assets 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." Absent the determination in the regulatory process of transition revenues and other pertinent information, it is not possible at this time to determine if any of the Company's plants are impaired in accordance with SFAS 121. Should the Company be granted recovery of its regulatory assets and/or any economic asset impairments it can record an offsetting regulatory asset. Should the PUCO not approve the Company's request for recovery of its generation-related regulatory assets and/or other stranded transition costs it would have an adverse impact on future results of operations and possibly financial condition. The Company does not expect to be able to determine the impact of the legislation on its financial statements until the regulatory process is complete. The PUCO is required to complete its regulatory process no later than October 31, 2000. 5. 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 mine is estimated to be $48.4 million including reclamation costs. 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 shutdown can be deferred for future recovery 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 Windsor mine. Unless the cost of the remaining coal production and mine shutdown are recovered, 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 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. On July 29, 1999, the FERC approved a draft order which rules on the AEP System's pending Open Access Transmission Tariff. This approved order has certain unfavorable pricing issues for which the AEP System has 30 days to seek rehearing. If the Commission's order is ultimately upheld the Company as a member of the AEP System will have to make refunds including interest. As of June 30, 1999 the Company has not made any provisions for its share of a potential refund which is preliminarily estimated to be approximately $5 million. 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 June 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. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 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. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The rules require submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP call. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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 or reflected in the future market price of electricity, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in the 1998 Annual Report. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 1999 vs. SECOND QUARTER 1998 AND YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998 RESULTS OF OPERATIONS Net income decreased $1.2 million or 2% in the second quarter and $0.8 million or 1% in the year-to-date period. The decline in both periods is mainly due to a reduction in operating revenues and nonoperating income. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $(25.1) (5) $(22.5) (2) Fuel Expense . . . . . . . (11.9) (7) (16.0) (4) Purchased Power Expense. . (12.7) (26) (11.0) (16) Maintenance Expense. . . . (4.7) (14) (9.8) (15) Nonoperating Income. . . . (3.9) (114) (3.2) (68) Operating revenues decreased for both periods due to a decline in wholesale energy sales to unaffiliated utilities and the American Electric Power System Power Pool reflecting the effect of milder spring weather on demand. The decrease in fuel expense in both periods was mainly due to a decrease in generation resulting from the decreased demand for energy. Purchased power expense decreased in the second quarter primarily due to the decline in demand for electricity. In the year-to-date period a lower average price for purchases from unaffiliated companies accounted for the decrease in purchased power expense. The decrease in the average price reflected the reduced demand for energy. The decline in maintenance expense was primarily due to a reduction in scheduled generating plant maintenance in 1999. Nonoperating income decreased due to the recognition of a provision for loss related to a Public Utilities Commission of Ohio (PUCO) order which requires the Company to reprice certain emission allowance transactions which are included in the electric fuel rate factor of customers' bills. The order requires the Company to adjust the actual amount paid for allowances purchased to the weighted average cost of allowances surrendered to the United States Environmental Protection Agency (Federal EPA) as a result of exceeding sulfur emission limitations in order to make wholesale sales. FINANCIAL CONDITION Total plant and property additions including capital leases for the first six months of 1999 were $95 million. During the first six months of 1999, the Company retired $138 million principal amount of long-term debt with interest rates ranging from 6.55% to 7.85%, issued $100 million of senior unsecured notes at a rate of 6.75% due 2004, issued $50 million of pollution control revenues bonds at a rate of 5.15% due 2026 and increased short-term debt by $71 million from year-end balances. The short-term debt limitation of the Company was increased from $400 million to $450 million with the approval of the Securities and Exchange Commission. OTHER MATTERS Ohio Restructuring Legislation On July 6, 1999, the Governor of the State of Ohio signed The Ohio Electric Restructuring Act of 1999. The Act provides for customer choice of electricity supplier and a residential rate reduction of 5% of the unbundled generation rate beginning on January 1, 2001. The Act 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 and other stranded transition costs. Retail electric services that will be competitive are defined in the Act as electric generation service, aggregation service, and power marketing and brokering. The PUCO has been granted broad oversight responsibility under the Act. The Act requires the PUCO to promulgate rules for competitive retail electric generation service. The Act further provides Ohio electric utilities with an opportunity to recover PUCO approved allowable transition costs through unbundled rates paid by customers who do not switch generation suppliers and through a wires charges by customers who switch generation suppliers. Transition costs can include regulatory assets, impairments of generating assets and other stranded costs, employee severance and retraining costs and other costs. Recovery of transition revenues can under certain circumstances extend beyond the five-year 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 Act also provides that the property tax assessment percentage on electric generation equipment be lowered from 100% to 25% of value effective January 1, 2001. Electric utilities will also 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 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. These changes should put the Company's generation operations on an equal level with other competitive businesses in Ohio regarding state taxation. 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 liabilities and assets certain revenues and expenses consistent with the regulatory process in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation." At June 30, 1999 the amount of regulatory assets recorded on the books applicable to the generating business is estimated to be $363 million before related tax effects. Whether the Company will have any additional stranded transition costs related to an economic impairment of its generating assets is dependent on several factors including the assumed future market price for electricity. The Company intends to seek recovery in its transition filing of all regulatory assets and any other stranded transition costs which may be identified. At this time management is unable to predict the outcome of the regulatory process or its impact on results of operations, cash flows or financial condition. Therefore, the Company will not be discontinuing application of SFAS 71 until the regulatory process is completed. Upon discontinuance of the application of SFAS 71 the Company will have to write off its Ohio generation-related regulatory assets 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." Absent the determination in the regulatory process of transition revenues and other pertinent information, it is not possible at this time to determine if any of the Company's plants are impaired in accordance with SFAS 121. Should the Company be granted recovery of its generation-related regulatory assets and/or any economic asset impairments it can record an offsetting regulatory asset. Should the PUCO not approve the Company's request for recovery of its regulatory assets and/or other stranded transition costs it would have an adverse impact on future results of operations and possibly financial condition. The Company does not expect to be able to determine the impact of the legislation on its financial statements until the regulatory process is complete. The PUCO is required to complete its regulatory process no later than October 31, 2000. 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 mine is estimated to be $48.4 million including reclamation costs. 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 shutdown can be deferred for future recovery under 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 Windsor mine. Unless the cost of the remaining coal production and mine shutdown are recovered, results of operations and cash flows would be adversely affected. Air Quality As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, 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. The final rules were to be implemented through state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. The rules require submission of revised SIPs by September 30, 1999. 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). On May 25, 1999, the Appeals Court ordered an indefinite stay of the September 30, 1999 deadline for submission of SIP revisions pending a further order of the court while arguments regarding the SIP call rule are considered. 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 triggering emission reductions that are substantially the same as those that would otherwise have been required by the NOx SIP call. On May 28, and June 1, 1999, the Utility Air Regulatory Group and the Midwest Ozone Group, respectively, each 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 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 and 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 or reflected in the future market price of electricity, they will have a material adverse effect on future results of operations, cash flows and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities 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 June 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. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The Company, 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. 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 plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. 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 following chart shows the Company's progress toward becoming ready for the Y2K as of June 30, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999 100% replacing or retiring 100% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 100% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. Costs to Address the Company's Year 2000 Issues - Through June 30, 1999, the Company has spent $11 million on the Y2K project and, estimates spending an additional $4 million to $6 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. Although significant, the cost of becoming Y2K compliant 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 may 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 as part of NERC's review of regional and individual electric utility contingency plans in 1999. In addition, the Company is establishing contingency plans for its business units to address alternatives if Y2K related failures occur. These contingency plans will be developed 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 4. Submission of Matters to a Vote of Security Holders. American Electric Power Company, Inc. ("AEP") The annual meeting of shareholders was held in Charleston, West Virginia on April 28, 1999. The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following two matters, as indicated below: 1. Election of 10 directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director received the votes of shareholders as follows: Number of Shares Number of Nominee Voted For Votes With- held John P. DesBarres 152,429,069 1,587,655 E. Linn Draper, Jr. 152,409,489 1,607,235 Robert M. Duncan 152,228,331 1,788,393 Robert W. Fri 152,374,521 1,642,203 Lester A. Hudson, Jr. 152,399,000 1,617,724 Leonard J. Kujawa 152,337,815 1,678,909 Donald G. Smith 152,425,646 1,571,078 Linda Gillespie Stuntz 152,373,335 1,643,389 Kathryn D. Sullivan 152,227,130 1,789,594 Morris Tanenbaum 152,274,788 1,741,936 Ronald Marsico 55,033 2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as independent auditors of AEP for the year 1999. The proposal was approved by a vote of the shareholders as follows: Votes FOR 152,631,080 Votes AGAINST 430,714 Votes ABSTAINED 954,930 Broker NON-VOTES* 0 *A non-vote occurs when a nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. Appalachian Power Company ("APCo") The annual meeting of stockholders was held on April 27, 1999 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each of the following six persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. James J. Markowsky Henry W. Fayne Armando A. Pena William J. Lhota Joseph H. Vipperman No other business was transacted at the meeting. Indiana Michigan Power Company ("I&M") The annual meeting of stockholders was held on April 27, 1999 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 1,400,000 votes were cast FOR each of the following thirteen persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: Karl G. Boyd James J. Markowsky C. R. Boyle, III Armando A. Pena G. A. Clark David B. Synowiec E. Linn Draper, Jr. Joseph H. Vipperman Henry W. Fayne William E. Walters James Kobyra Earl H. Wittkamper William J. Lhota No other business was transacted at the meeting. Ohio Power Company ("OPCo") The annual meeting of shareholders was held on May 4, 1999 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,473 votes were cast FOR each of the following six persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. James J. Markowsky Henry W. Fayne Armando A. Pena William J. Lhota Joseph H. Vipperman No other business was transacted at the meeting. Item 5. Other Information. AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern Power Company ("CSPCo"), I&M, Kentucky Power Company ("KEPCo") and OPCo Reference is made to page 29 of the Annual Report on Form 10-K for the year ended December 31, 1998 ("1998 10-K") for a discussion of ambient air quality standards attainment. On May 14, 1999, the U.S. Court of Appeals for the District of Columbia Circuit issued its decision vacating the ambient air quality standard for particulate matter less than 10 microns in diameter and remanding the 8-hour air quality standards for ozone and fine particulate matter (less than 2.5 microns in diameter). The ruling, in effect, suspends the ozone and fine particulate matter standards pending the corrective steps mandated by the court. The U.S. Environmental Protection Agency ("Federal EPA") filed a motion for rehearing with the court on June 28, 1999. Reference is made to pages 32 and 33 of the 1998 10-K for a discussion of Federal EPA's proposed regional haze rule. On July 1, 1999, Federal EPA issued a final rule which requires each state to develop and implement measures to control emissions from sources within the state which are reasonably anticipated to contribute to regional haze within a Class I area (essentially national parks or wilderness areas). Deadlines for the states to implement such measures vary between 2002 and 2008 depending on the particulate matter attainment status for the areas within each state. The rule requires each state to identify sources constructed between 1962 and 1977 which may be eligible for application of Best Available Retrofit Technology. AEP is unable to predict when or to what extent controls may be required for AEP System generating units to comply with this rule or the extent of costs which may be incurred. Reference is made to page 33 of the 1998 10-K and pages II-1 and II-2 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, for a discussion of requests issued to AEP under Section 114 of the Clean Air Act focused on assessing compliance with the New Source Review and New Source Performance Standard provisions. In July 1999, Federal EPA, Region V, issued an additional request seeking documents and information regarding capital and maintenance expenditures at Tanners Creek Plant and, in August 1999, made a site visit to Cardinal Plant. Federal EPA staff has advised AEP that it is their preliminary view that there has been widespread noncompliance at coal fired generating units within the utility industry (including at several AEP plants) over the past 20 years with regard to New Source Review requirements. AEP management does not agree with this view. An adverse determination by Federal EPA could result in substantial additional capital costs and significant penalties for any affected company. AEP is unable to predict what, if any, further action may be taken by Federal EPA in respect of this matter or the effect that any action taken by Federal EPA may have on the financial condition or the results of operation of AEP. AEP and OPCo Reference is made to page 32 of the 1998 10-K for a discussion of the SO2 limitation applicable to the Kammer Plant. On July 22, 1999, the West Virginia Division of Environmental Protection, Office of Air Quality, conducted a public meeting to consider revised SO2 emission limits for the Kammer Plant and other emission sources within Marshall County. The emission limit proposed for Kammer is 2.7 pounds of SO2 per million Btu. The limit, if approved, would conform to the current federally approved emission limit for Kammer contained in the West Virginia State Implementation Plan. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 12 - Statement re: Computation of Ratios. AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 27 - Financial Data Schedule. (b) Reports on Form 8-K: Company Reporting Date of Report Item Reported AEP and I&M June 24, 1999 Item 5. Other Events AEGCo, APCo, CSPCo, KEPCo and OPCo No reports on Form 8-K were filed during the quarter ended June 30, 1999. 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: August 12, 1999 EX-12 2 EXHIBIT 12 OHIO 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 6/30/99 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . $ 63,805 $ 61,836 $ 52,147 $ 45,540 $ 33,663 $ 28,767 Interest on Other Long-term Debt. . . . . . . . 21,453 23,193 27,045 29,620 38,520 43,435 Interest on Short-term Debt . . . . . . . . . . 992 2,658 4,006 4,519 5,821 7,711 Miscellaneous Interest Charges. . . . . . . . . 5,140 7,126 3,705 4,464 4,617 4,645 Estimated Interest Element in Lease Rentals . . 13,900 50,700 53,200 52,900 59,300 59,300 Total Fixed Charges. . . . . . . . . . . . $105,290 $145,513 $140,103 $137,043 $141,921 $143,858 Earnings: Net Income. . . . . . . . . . . . . . . . . . . $162,626 $189,447 $217,655 $208,689 $209,925 $209,116 Plus Federal Income Taxes . . . . . . . . . . . 74,822 93,699 117,243 121,559 112,087 115,649 Plus State Income Taxes . . . . . . . . . . . . 3,375 1,618 2,252 2,655 2,742 2,889 Plus Fixed Charges (as above) . . . . . . . . . 105,290 145,513 140,103 137,043 141,921 143,858 Total Earnings . . . . . . . . . . . . . . $346,113 $430,277 $477,253 $469,946 $466,675 $471,512 Ratio of Earnings to Fixed Charges. . . . . . . . 3.28 2.95 3.40 3.42 3.28 3.27
EX-27 3 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000073986 OHIO POWER COMPANY 1,000 6-MOS DEC-31-1998 JUN-30-1999 PER-BOOK 2,770,561 246,654 994,931 82,570 572,025 4,666,741 321,201 462,366 584,045 1,367,612 11,850 17,211 1,072,702 0 0 194,090 11,283 0 107,424 29,235 1,855,334 4,666,741 1,016,808 68,955 795,569 864,524 152,284 1,508 153,792 41,106 112,686 734 111,952 115,406 13,849 142,797 0 0 All common stock owned by parent company; no EPS required.
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