-----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, PWxXVFl6M/f/fcbBryUkW9/LxYPcOjPCFnnPiz8uD3Hrc0BxO6ujiJ6cMm1l+n1R cyzrz47tIRkDfJivRiry+A== 0000004904-98-000147.txt : 19981118 0000004904-98-000147.hdr.sgml : 19981118 ACCESSION NUMBER: 0000004904-98-000147 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981116 FILER: COMPANY DATA: COMPANY CONFORMED NAME: APPALACHIAN POWER CO CENTRAL INDEX KEY: 0000006879 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 540124790 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-03457 FILM NUMBER: 98750051 BUSINESS ADDRESS: STREET 1: 40 FRANKLIN RD SW CITY: ROANOKE STATE: VA ZIP: 24011 BUSINESS PHONE: 7039852300 MAIL ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 10-Q 1 THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended SEPTEMBER 30, 1998 [ ] 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 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at October 31, 1998 was 191,348,743.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended September 30, 1998 INDEX
Page Part I. FINANCIAL INFORMATION American Electric Power Company, Inc. and Subsidiary Companies: Consolidated Statements of 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-12 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . A-13- A-25 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-19 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-8 Management's Narrative Analysis of Results of Operations . . D-9 - D-10 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-23 Kentucky Power Company: Statements of Income and Statements of Retained Earnings . . F-1 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3 Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4 Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-8 Management's Narrative Analysis of Results of Operations . . F-9 - F-10 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended September 30, 1998 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-8 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . G-9 - G-18 Part II. OTHER INFORMATION Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4 This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands, except per-share amounts) (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 OPERATING REVENUES . . . . . . . . . . . $4,638,133 $1,583,994 $9,546,566 $4,458,221 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 463,012 421,815 1,307,198 1,192,434 Purchased Power. . . . . . . . . . . . 2,982,625 100,961 5,015,690 156,917 Other Operation. . . . . . . . . . . . 365,563 302,307 968,011 904,892 Maintenance. . . . . . . . . . . . . . 130,710 123,781 376,158 347,894 Depreciation and Amortization. . . . . 145,315 144,342 433,584 447,843 Taxes Other Than Federal Income Taxes. 124,602 123,943 370,933 372,723 Federal Income Taxes . . . . . . . . . 114,727 91,755 280,291 267,195 TOTAL OPERATING EXPENSES . . . 4,326,554 1,308,904 8,751,865 3,689,898 OPERATING INCOME . . . . . . . . . . . . 311,579 275,090 794,701 768,323 NONOPERATING INCOME (LOSS) . . . . . . . (6,274) 32,835 (5,572) 43,030 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS. . . . . . . . . . 305,305 307,925 789,129 811,353 INTEREST CHARGES . . . . . . . . . . . . 107,153 103,378 316,938 300,851 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES. . . . . . . . . . . . 2,787 2,801 8,155 15,056 INCOME BEFORE EXTRAORDINARY ITEM . . . . 195,365 201,746 464,036 495,446 EXTRAORDINARY ITEM - U. K. WINDFALL TAX. - (110,565) - (110,565) NET INCOME . . . . . . . . . . . . . . . $ 195,365 $ 91,181 $ 464,036 $ 384,881 AVERAGE NUMBER OF SHARES OUTSTANDING . . 190,996 189,287 190,538 188,819 EARNINGS PER SHARE: Before Extraordinary Item . . . . . . . $1.02 $1.07 $2.44 $2.62 Extraordinary Item - U. K. Windfall Tax - (0.59) - (0.58) Net Income. . . . . . . . . . . . . . . $1.02 $0.48 $2.44 $2.04 CASH DIVIDENDS PAID PER SHARE. . . . . . $0.60 $0.60 $1.80 $1.80
See Notes to Consolidated Financial Statements. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $ 9,560,684 $ 9,493,158 Transmission . . . . . . . . . . . . . . . . . . . . 3,572,360 3,501,580 Distribution . . . . . . . . . . . . . . . . . . . . 4,749,050 4,654,234 General (including mining assets and nuclear fuel) . 1,603,876 1,604,671 Construction Work in Progress. . . . . . . . . . . . 460,591 342,842 Total Electric Utility Plant . . . . . . . . 19,946,561 19,596,485 Accumulated Depreciation and Amortization. . . . . . 8,290,285 7,963,636 NET ELECTRIC UTILITY PLANT . . . . . . . . . 11,656,276 11,632,849 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 1,852,341 1,356,504 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 147,894 91,481 Accounts Receivable. . . . . . . . . . . . . . . . . 852,460 674,278 Allowance for Uncollectible Accounts . . . . . . . . (10,796) (6,760) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 195,539 224,967 Materials and Supplies . . . . . . . . . . . . . . . 278,825 263,613 Accrued Utility Revenues . . . . . . . . . . . . . . 190,425 189,191 Energy Marketing and Trading Contracts . . . . . . . 185,354 2,306 Prepayments and Other. . . . . . . . . . . . . . . . 81,259 81,366 TOTAL CURRENT ASSETS . . . . . . . . . . . . 1,920,960 1,520,442 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 1,820,407 1,817,540 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 226,263 288,011 TOTAL. . . . . . . . . . . . . . . . . . . $17,476,247 $16,615,346
See Notes to Consolidated Financial Statements. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock-Par Value $6.50: 1998 1997 Shares Authorized . . . .600,000,000 300,000,000 Shares Issued . . . . . .200,335,149 198,989,981 (8,999,992 shares were held in treasury) . . . . . $ 1,302,178 $ 1,293,435 Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,832,744 1,778,782 Retained Earnings. . . . . . . . . . . . . . . . . . 1,726,249 1,605,017 Total Common Shareholders' Equity. . . . . . 4,861,171 4,677,234 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption. . . . . . . . 46,257 46,724 Subject to Mandatory Redemption. . . . . . . . . . 127,605 127,605 Long-term Debt . . . . . . . . . . . . . . . . . . . 5,408,997 5,129,463 TOTAL CAPITALIZATION . . . . . . . . . . . . 10,444,030 9,981,026 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,373,685 1,246,537 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 90,793 294,454 Short-term Debt. . . . . . . . . . . . . . . . . . . 535,408 555,075 Accounts Payable . . . . . . . . . . . . . . . . . . 460,917 353,256 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 299,784 380,771 Interest Accrued . . . . . . . . . . . . . . . . . . 105,966 76,361 Obligations Under Capital Leases . . . . . . . . . . 103,984 101,089 Energy Marketing and Trading Contracts . . . . . . . 180,689 1,983 Other. . . . . . . . . . . . . . . . . . . . . . . . 503,122 322,687 TOTAL CURRENT LIABILITIES. . . . . . . . . . 2,280,663 2,085,676 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,552,084 2,560,921 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 359,005 376,250 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 224,362 231,320 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 242,418 133,616 CONTINGENCIES (Note 7) TOTAL. . . . . . . . . . . . . . . . . . . $17,476,247 $16,615,346
See Notes to Consolidated Financial Statements. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 464,036 $ 384,881 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 462,843 455,494 Deferred Federal Income Taxes. . . . . . . . . . . . . . 34,486 (35,566) Deferred Investment Tax Credits. . . . . . . . . . . . . (17,245) (17,510) Amortization of Deferred Property Taxes. . . . . . . . . 135,324 132,251 Amortization of Operating Expenses and Carrying Charges (net) . . . . . . . . . . . . . . . . 11,850 24,356 Extraordinary Loss - U.K. Windfall Tax . . . . . . . . . - 110,565 Deferred Costs Under Fuel Clause Mechanisms. . . . . . . (58,903) (22,393) Changes in Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (174,146) (42,336) Fuel, Materials and Supplies . . . . . . . . . . . . . . 14,216 10,353 Accrued Utility Revenues . . . . . . . . . . . . . . . . (1,234) 25,564 Accounts Payable . . . . . . . . . . . . . . . . . . . . 107,661 1,442 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (80,987) (153,434) Interest Accrued . . . . . . . . . . . . . . . . . . . . 29,605 36,919 Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 54,554 (1,933) Other Current Assets and Liabilities . . . . . . . . . . 124,541 79,056 Payment of Disputed Tax and Interest Related to COLI . . . (302,739) - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 41,533 (21,714) Net Cash Flows From Operating Activities . . . . . . 845,395 965,995 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (557,284) (496,155) Investment in Yorkshire Electricity Group plc. . . . . . . - (361,795) Other Investments. . . . . . . . . . . . . . . . . . . . . (9,968) (7,241) Proceeds from Sale of Property . . . . . . . . . . . . . . 8,596 9,733 Net Cash Flows Used For Investing Activities . . . . (558,656) (855,458) FINANCING ACTIVITIES: Issuance of Common Stock . . . . . . . . . . . . . . . . . 62,897 58,045 Issuance of Long-term Debt . . . . . . . . . . . . . . . . 617,656 776,441 Retirement of Cumulative Preferred Stock . . . . . . . . . (346) (433,234) Retirement of Long-term Debt . . . . . . . . . . . . . . . (548,062) (325,931) Change in Short-term Debt (net). . . . . . . . . . . . . . (19,667) 188,055 Dividends Paid on Common Stock . . . . . . . . . . . . . . (342,804) (339,685) Net Cash Flows Used For Financing Activities . . . . (230,326) (76,309) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 56,413 34,228 Cash and Cash Equivalents at Beginning of Period . . . . . . 91,481 57,539 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 147,894 $ 91,767 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $278,733,000 and $253,884,000 and for income taxes was $149,712,000 and $290,682,000 in 1998 and 1997, respectively. Noncash acquisitions under capital leases were $93,823,000 and $171,947,000 in 1998 and 1997, respectively.
See Notes to Consolidated Financial Statements. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $1,645,466 $1,615,039 $1,605,017 $1,547,746 NET INCOME . . . . . . . . . . . . . . . 195,365 91,181 464,036 384,881 DEDUCTIONS: Cash Dividends Declared. . . . . . . . 114,583 113,515 342,804 339,685 Other. . . . . . . . . . . . . . . . . (1) - - 237 BALANCE AT END OF PERIOD . . . . . . . . $1,726,249 $1,592,705 $1,726,249 $1,592,705
See Notes to Consolidated Financial Statements. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state-ments should be read in conjunction with the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. FINANCING AND RELATED ACTIVITIES During the first nine months of 1998, subsidiaries issued $452 million of senior unsecured notes: two series totaling $112 million at 6.51% and 6.55% due in 2008 and three series totaling $340 million at 7.20%, 7.30% and 7-3/8% due in 2038; $125 million of 7.60% junior subordinated deferrable interest debentures due in 2038; and increased their outstanding balance under a revolving credit agreement by $15 million. The proceeds from the above financings were used during 1998 to retire: $472 million of first mortgage bonds with interest rates ranging from 6-3/4% to 9.15% due from 1998 to 2023; $25 million of variable rate installment purchase contracts due in 2025; a $16.7 million term loan with an interest rate of 6.85% at maturity; and $10 million of a variable rate term loan due in 1999. As a result of the redemption of the 6-3/4% series first mortgage bonds due in 1998, the restriction on the use of retained earnings for the payment of common stock dividends was reduced to $6 million. 3. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. 4. INVESTMENT IN YORKSHIRE The Company has a 50% ownership interest in Yorkshire Power Group Limited which is accounted for using the equity method. The Company's share of Yorkshire earnings are included in nonoperating income. The following amounts which are not included in AEP's consolidated financial statements represent summarized consolidated financial information of Yorkshire Power Group Limited for the quarter and nine months ended September 30, 1998: Quarter Year-to-Date (in millions) Income Statement Data: Operating Revenues $510.2 $1,677.3 Operating Income 82.6 264.8 Net Income 21.5 13.6 5. ENERGY MARKETING AND TRADING During 1998, the Company substantially increased the volume of its electricity and gas marketing and trading. The purpose of the marketing and trading business is to utilize the Company's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income, thereby enhancing both customer and shareholder value. The electricity and gas marketing and trading business involves the marketing of energy under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Company's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Company had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company has also purchased and sold electricity and gas options, futures and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity and gas outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. The unrealized mark-to-market gains and losses from such trading activity are reported as assets and liabilities, respectively. At September 30, 1998, the Company has open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity and gas with a notional value of approximately $755 million and to purchase electricity and gas with a notional value of approximately $585 million. Dependent on future electricity and gas market conditions these activities could produce material income or losses in future periods. 6. PROPOSED MERGER AND ACQUISITION As discussed in the Management's Discussion and Analysis of Results of Operations and Financial Condition in the 1997 annual report and the Joint Proxy Statement/Prospectus dated April 16, 1998, the Company and Central and South West Corporation (CSW) have agreed to merge. At the May 1998 annual meeting, AEP shareholders approved the issuance of AEP common shares to effect the merger and approved an increase in the authorized shares of AEP Common Stock from 300,000,000 to 600,000,000. CSW stockholders approved the merger at their May 1998 annual meeting. The companies have filed for necessary approvals to merge with the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission, the Nuclear Regulatory Commission (NRC) and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. Filings with the Federal Communications Commission and the Department of Justice are expected to be made before the end of 1998. The Company's target consummation date for the merger is the second quarter of 1999. In August 1998 the Arkansas Public Service Commission approved the merger, subject to a number of conditions including the approval of a regulatory plan for sharing net merger savings. On November 3, 1998 the Company, CSW and CSW's Arkansas operating subsidiary, Southwestern Electric Power Company, filed a settlement agreement for approval with the Arkansas Public Service Commission outlining a regulatory plan, agreed to with the Commission staff, which provides for a sharing of net merger savings through a reduction of rates for Arkansas retail customers. In October 1998 the Oklahoma Corporation Commission (OCC) approved plans by AEP and CSW to submit an amended filing seeking approval of the proposed merger. The amended application is being made as a result of an Oklahoma administrative law judge's recommendation that the merger filing be dismissed without prejudice for lack of information regarding the potential impact of the merger on the retail electric market in Oklahoma. Submission of the amended application will reset Oklahoma's 90-day statutory time period for OCC action on the merger phase of the application. The filing of the amended application should not affect the timing of the merger closing. In July 1998 the FERC issued an order which confirmed that the 250 megawatt firm contract path with the Ameren System is available. The contract path is required for AEP and CSW to meet the requirements of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. On November 10, 1998, the FERC issued an order establishing hearing procedures for the merger. A scheduling conference will be held in November 1998. The order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection and instructed the companies to refile an updated market power study. The outcome of the FERC scheduling conference could extend the targeted completion date of the merger. A settlement agreement between AEP, CSW and certain key parties to the Texas merger proceeding has been reached. The staff of the Public Utility Commission of Texas was not a signatory to the settlement agreement, which resolves all issues for the signing parties. The settlement provides for, among other things, the approval of rate reductions to share net merger savings and settle existing rate reviews. The application by CSW's operating subsidiary, Central Power and Light Company, to the NRC requesting permission to transfer control of the license for the South Texas Project nuclear generating station to AEP was approved by the NRC. AEP has a 50% interest in Yorkshire Electricity Group, plc and CSW has a 100% interest in Seeboard, plc, two United Kingdom (U.K.) regional electricity companies (RECs). The proposed merger of CSW into AEP would result in common ownership of these U.K. entities. As a result, the common ownership of two U.K. RECs could be referred by the U.K. Secretary of State for Trade and Industry to the U.K. Mergers and Monopolies Commission for investigation. The merger, which is to be accounted for as a pooling of interests, is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions, including the condition that it must be a pooling, and some of these conditions may not be waived by the parties. The Company is unable to predict the outcome or the timing of the required regulatory proceedings. In September 1998 the Company and Equitable Resources, Inc. signed a definitive agreement for the Company to purchase Equitable's natural gas midstream assets and operations for approximately $320 million. The purchase includes an intrastate pipeline system, five natural gas processing plants, one natural gas storage facility and an energy trading business. The transaction is expected to close in the fourth quarter of 1998 and be accounted for as a purchase. 7. CONTINGENCIES Taxes As discussed in Note 10, "Federal Income Taxes", of the Notes to Consolidated Financial Statements in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through September 30, 1998 would reduce earnings by approximately $310 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Cook Nuclear Plant Shutdown As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition, both units of the Cook Nuclear Plant were shut down by Indiana Michigan Power Company (I&M) in September 1997 due to questions regarding the operability of certain safety systems, which arose during a NRC architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring I&M to address the issues identified in the letter. I&M is working with the NRC to resolve the one remaining issue in the letter. On April 17, 1998, the NRC notified I&M that it had convened a Restart Panel for Cook Plant. On July 30, 1998, I&M received a letter from the NRC providing the NRC's list of required restart activities. I&M is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the items that need to be addressed in order to restart the units. When maintenance and other activities required for restart are complete, I&M will seek concurrence from the NRC to return the Cook Plant to service. I&M's current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition. The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter. On July 24, 1998, I&M received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In a letter dated October 13, 1998, the NRC issued to I&M a Notice of Violation and a proposed $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. I&M paid the penalty. The cost of electricity supplied to I&M's retail customers rose due to the outage of the two units since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor as was the case with regard to the Cook outage, a regulatory asset is recorded and revenues are accrued. Due to the unscheduled Cook Plant outage, I&M's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million. The Indiana Utility Regulatory Commission approved two agreements authorizing I&M during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by I&M, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that it should be able to recover the Cook replacement energy costs; however, if recovery of the replacement costs is denied, results of operations and cash flows would be adversely affected. Revised Air Quality Standards The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the operating companies of the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by the Company of approximately $1.2 billion. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 RESULTS OF OPERATIONS Net income increased by $104.2 million or 114% for the quarter and $79.2 million or 21% for the year-to-date period due predominantly to the effect of an extraordinary loss from a United Kingdom (U.K.) one-time windfall tax enacted during the third quarter of 1997 and a significant increase in net revenues from energy sales due to favorable weather and energy marketing and trading activities within AEP's traditional marketing area. The windfall tax was based on a revision or recomputation of the original 1990 privatization value of certain privatized regional electric companies in the U.K. including Yorkshire Electricity Group. Income before extraordinary item decreased $6.4 million for the third quarter and $31.4 million for the year-to-date period as a result of a write-down of Yorkshire Electricity Group's investment in Ionica, a U.K. telecommunications company, expenditures to prepare the Cook Plant for restart following an extended outage and certain losses on energy trades outside of AEP's traditional marketing area. The significant changes in income statement line items and net revenues were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $3,054.1 193 $5,088.3 114 Fuel Expense . . . . . . . 41.2 10 114.8 10 Purchased Power Expense. . 2,881.7 N.M. 4,858.8 N.M. Net Revenues . . . . . . 131.2 114.7 Other Operation Expense. . 63.3 21 63.1 7 Maintenance Expense. . . . 6.9 6 28.3 8 Federal Income Taxes . . . 23.0 25 13.1 5 Nonoperating Income. . . . (39.1) (119) (48.6) (113) N.M. = Not Meaningful Operating revenues increased significantly in both the third quarter and the year-to-date periods due predominantly to increased sales to retail and wholesale customers. Energy sales to retail customers rose 6% in the quarter and 4% in the year-to-date period primarily due to warmer summer weather in 1998 and increased industrial customer usage. The significant increases in wholesale sales and wholesale revenues are attributable to growth in the power marketing and trading business in AEP's marketing area. The increases in fuel expense were primarily attributable to an increase in coal-fired generation to meet the increased demand for electricity and an increase in the average cost of fuel consumed reflecting the unavailability of lower cost nuclear generation due to the unplanned outage of both Cook Plant nuclear units in 1998. Purchases of electricity by the wholesale power marketing and trading business accounted for the significant increase in purchased power expense. The increase in net revenues of $131 million for the quarter and $115 million for the year-to-date period is due to the impact of warmer summer weather and increased industrial usage on retail sales and the successful trading of wholesale energy in a volatile market. The increases in other operation expenses are related to the increases in energy sales and the extended Cook Plant outage and in the third quarter increased incentive pay accruals. Maintenance expense increased for the year-to-date period largely as a result of expenditures to prepare the Cook Plant units for restart and to repair and restore service interruptions caused by two severe snowstorms. Federal income tax expense attributable to operations increased due to an increase in pre-tax operating income. The decreases in nonoperating income for both periods reflect the effect of the Company's equity share of Yorkshire's loss on its investment in Ionica, losses on certain energy trades and in the third quarter the effect of $26 million of tax benefits recognized in 1997 related to a reduction of the corporate income tax rate in the U.K. by Yorkshire and the utilization of certain foreign tax credits. The energy trades which produced the losses are marked-to-market and represent non-regulated trading activities outside the Company's traditional marketing area (see footnote 5). Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger. FINANCIAL CONDITION Total plant and property additions including capital leases for the first nine months of 1998 were $652 million. During the first nine months of 1998, subsidiaries issued $608 million principal amount of long-term obligations at interest rates ranging from 5.87% to 10.53%; retired $524 million principal amount of long-term debt with interest rates ranging from 2.85% to 9.15%; and decreased short-term debt by $20 million. COOK NUCLEAR PLANT SHUTDOWN As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition, both units of the Cook Nuclear Plant were shut down by Indiana Michigan Power Company (I&M) in September 1997 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 I&M to address the issues identified in the letter. I&M is working with the NRC to resolve the one remaining issue in the letter. On April 17, 1998, the NRC notified I&M that it had convened a Restart Panel for Cook Plant. On July 30, 1998, I&M received a letter from the NRC providing the NRC's list of required restart activities. I&M is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the items that need to be addressed in order to restart the units. When maintenance and other activities required for restart are complete, I&M will seek concurrence from the NRC to return the Cook Plant to service. I&M's current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition. The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter. On July 24, 1998, I&M received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In a letter dated October 13, 1998, the NRC issued to I&M a Notice of Violation and proposed a $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. I&M paid the penalty. The cost of electricity supplied to I&M's retail customers rose due to the outage of the two units since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor as was the case with regard to the Cook outage, a regulatory asset is recorded and revenues are accrued. Due to the unscheduled Cook Plant outage, I&M's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million. The Indiana Utility Regulatory Commission approved two agreements authorizing I&M during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by I&M, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the appropriateness of the recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that it should be able to recover the Cook replacement energy costs; however, if recovery of the replacement costs is denied, results of operations and cash flows would be adversely affected. The above timetable for the return to service of the Cook Plant constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, other unforeseen issues encountered in preparing the Cook Plant for restart and the unpredictability of the NRC regulatory process. REVISED AIR QUALITY STANDARDS The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the operating companies of the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by AEP of approximately $1.2 billion. Compliance costs can not 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, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. ENERGY MARKETING AND TRADING During 1998, the Company substantially increased the volume of its electricity and gas marketing and trading. The purpose of the marketing and trading business is to utilize the Company's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income, thereby enhancing both customer and shareholder value. The electricity and gas marketing and trading business involves the marketing of energy under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Company's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Company had open marketing contracts, not marked-to-market on its balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company has also purchased and sold electricity and gas options, futures and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity and gas outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. The unrealized mark-to-market gains and losses from such trading activity are reported as assets and liabilities, respectively. At September 30, 1998, the Company has open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity and gas with a notional value of approximately $755 million and to purchase electricity and gas with a notional value of approximately $585 million. Dependent on future electricity and gas market conditions these activities could produce material income or losses in future periods. TAXES As discussed in Note 10, "Federal Income Taxes", of the Notes to Consolidated Financial Statements in the 1997 Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deductions through September 30, 1998 would reduce earnings by approximately $310 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. COMPUTER ISSUE - YEAR 2000 On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were 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-Year 2000 ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem 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 Year 2000 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, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that: "While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30, 1999 to June 30, 1999. Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. Various state regulatory commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction. 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, communications, and the physical generation and delivery of energy; 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 our progress toward becoming ready for the Year 2000 as of September 30, 1998: 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% 11/30/1998 86% 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 2% replacing or retiring 60% those mission critical and high priority digital-based systems with problems Client processing dates past the Server: Year 2000. Testing these 1% 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 September 30, 1998, the Company has spent $15 million on the Year 2000 project and, estimates spending an additional $41 million to $53 million to achieve Year 2000 readiness. Most Year 2000 costs are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 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. In addition, although as discussed 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, Year 2000-related issues may materially adversely affect AEP. Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's Contingency Planning Guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999. Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others: * Continuing availability of experienced consultants and IT personnel and related resources * Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness * Ability of the Company to identify and implement contingency plans. PROPOSED MERGER AND ACQUISITION As discussed in the Management's Discussion and Analysis of Results of Operations and Financial Condition in the 1997 annual report and the Joint Proxy Statement/Prospectus dated April 16, 1998, the Company and Central and South West Corporation (CSW) have agreed to merge. At the May 1998 annual meeting, AEP shareholders approved the issuance of AEP common shares to effect the merger and approved an increase in the authorized shares of AEP Common Stock from 300,000,000 to 600,000,000. CSW stockholders approved the merger at their May 1998 annual meeting. The companies have filed for necessary approvals to merge with the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission, the NRC and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. Filings with the Federal Communications Commission and the Department of Justice are expected to be made before the end of 1998. The Company's target consummation date for the merger is the second quarter of 1999. In August 1998 the Arkansas Public Service Commission approved the merger, subject to a number of conditions including the approval of a regulatory plan for sharing net merger savings. On November 3, 1998 the Company, CSW and CSW's Arkansas operating subsidiary, Southwestern Electric Power Company, filed a settlement agreement for approval with the Arkansas Public Service Commission outlining a regulatory plan, agreed to with the Commission staff, which provides for a sharing of net merger savings through a reduction of rates for Arkansas retail customers. In October 1998 the Oklahoma Corporation Commission (OCC) approved plans by AEP and CSW to submit an amended filing seeking approval of the proposed merger. The amended application is being made as a result of an Oklahoma administrative law judge's recommendation that the merger filing be dismissed without prejudice for lack of information regarding the potential impact of the merger on the retail electric market in Oklahoma. Submission of the amended application will reset Oklahoma's 90-day statutory time period for OCC action on the merger phase of the application. The filing of the amended application should not affect the timing of the merger closing. In July 1998 the FERC issued an order which confirmed that the 250 megawatt firm contract path with the Ameren System is available. The contract path is required for AEP and CSW to meet the requirements of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. On November 10, 1998, the FERC issued an order establishing hearing procedures for the merger. A scheduling conference will be held in November 1998. The order indicated that the review of the proposed merger will address the issues of competition, market power and customer protection and instructed the companies to refile an updated market power study. The outcome of the FERC scheduling conference could extend the targeted completion date of the merger. A settlement agreement between AEP, CSW and certain key parties to the Texas merger proceeding has been reached. The staff of the Public Utility Commission of Texas was not a signatory to the settlement agreement, which resolves all issues for the signing parties. The settlement provides for, among other things, the approval of rate reductions to share net merger savings and settle existing rate reviews. The application by CSW's operating subsidiary, Central Power and Light Company, to the NRC requesting permission to transfer control of the license for the South Texas Project nuclear generating station to AEP was approved by the NRC. AEP has a 50% interest in Yorkshire Electricity Group, plc and CSW has a 100% interest in Seeboard, plc, two U.K. regional electricity companies (RECs). The proposed merger of CSW into AEP would result in common ownership of these U.K. entities. As a result, the common ownership of two U.K. RECs could be referred by the U.K. Secretary of State for Trade and Industry to the U.K. Mergers and Monopolies Commission for investigation. The merger, which is to be accounted for as a pooling of interests, is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions, including the condition that it must be a pooling, and some of these conditions may not be waived by the parties. The Company is unable to predict the outcome or the timing of the required regulatory proceedings. In September 1998 the Company and Equitable Resources, Inc. signed a definitive agreement for the Company to purchase Equitable's natural gas midstream assets and operations for approximately $320 million. The purchase includes an intrastate pipeline system, five natural gas processing plants, one natural gas storage facility and an energy trading business. The transaction is expected to close in the fourth quarter of 1998 and be accounted for as a purchase. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) OPERATING REVENUES . . . . . . . . . . . $59,262 $58,136 $167,596 $170,665 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 27,953 26,354 71,718 72,443 Rent - Rockport Plant Unit 2 . . . . . 17,071 17,071 51,212 51,212 Other Operation. . . . . . . . . . . . 2,174 2,518 7,547 8,362 Maintenance. . . . . . . . . . . . . . 2,703 2,372 9,110 10,115 Depreciation . . . . . . . . . . . . . 5,405 5,402 16,229 16,209 Taxes Other Than Federal Income Taxes. 882 1,015 2,759 2,744 Federal Income Taxes . . . . . . . . . 845 922 2,562 2,529 TOTAL OPERATING EXPENSES . . . 57,033 55,654 161,137 163,614 OPERATING INCOME . . . . . . . . . . . . 2,229 2,482 6,459 7,051 NONOPERATING INCOME. . . . . . . . . . . 837 831 2,457 2,631 INCOME BEFORE INTEREST CHARGES . . . . . 3,066 3,313 8,916 9,682 INTEREST CHARGES . . . . . . . . . . . . 903 986 2,494 2,997 NET INCOME . . . . . . . . . . . . . . . $ 2,163 $ 2,327 $ 6,422 $ 6,685 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $2,435 $3,672 $2,528 $1,886 NET INCOME . . . . . . . . . . . . . . . 2,163 2,327 6,422 6,685 CASH DIVIDENDS DECLARED. . . . . . . . . 2,176 3,286 6,528 5,858 BALANCE AT END OF PERIOD . . . . . . . . $2,422 $2,713 $2,422 $2,713 The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Financial Statements. AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production. . . . . . . . . . . . . . . . . . . . . . . . $629,055 $627,803 General . . . . . . . . . . . . . . . . . . . . . . . . . 3,151 3,137 Construction Work in Progress . . . . . . . . . . . . . . 2,510 2,510 Total Electric Utility Plant. . . . . . . . . . . 634,716 633,450 Accumulated Depreciation. . . . . . . . . . . . . . . . . 272,198 257,191 NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 362,518 376,259 CURRENT ASSETS: Cash and Cash Equivalents . . . . . . . . . . . . . . . . 142 237 Accounts Receivable . . . . . . . . . . . . . . . . . . . 22,674 20,710 Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 12,097 10,107 Materials and Supplies. . . . . . . . . . . . . . . . . . 4,126 4,246 Prepayments . . . . . . . . . . . . . . . . . . . . . . . 152 368 TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 39,191 35,668 REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 6,044 5,639 DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 1,570 1,492 TOTAL . . . . . . . . . . . . . . . . . . . . . $409,323 $419,058
See Notes to Financial Statements. AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (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 . . . . . . . . . . . . . . . . . . . . . 36,235 39,235 Retained Earnings . . . . . . . . . . . . . . . . . . . . 2,422 2,528 Total Common Shareholder's Equity . . . . . . . . 39,657 42,763 Long-term Debt. . . . . . . . . . . . . . . . . . . . . . 44,790 69,570 TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 84,447 112,333 OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 972 1,259 CURRENT LIABILITIES: Short-term Debt - Notes Payable . . . . . . . . . . . . . 8,175 11,750 Accounts Payable. . . . . . . . . . . . . . . . . . . . . 13,226 9,704 Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 4,751 3,420 Interest Accrued. . . . . . . . . . . . . . . . . . . . . 164 461 Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 23,427 4,963 Other . . . . . . . . . . . . . . . . . . . . . . . . . . 5,311 3,747 TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 55,054 34,045 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 134,723 138,901 REGULATORY LIABILITIES: Deferred Investment Tax Credits . . . . . . . . . . . . . 67,494 70,016 Deferred Amounts Due to Customers for Income Tax. . . . . 30,404 31,375 TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 97,898 101,391 DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 36,075 31,129 DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 154 - TOTAL . . . . . . . . . . . . . . . . . . . . . $409,323 $419,058
See Notes to Financial Statements. AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 6,422 $ 6,685 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . . 16,229 16,209 Deferred Federal Income Taxes. . . . . . . . . . . . . . 3,975 3,564 Deferred Investment Tax Credits. . . . . . . . . . . . . (2,522) (2,526) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2. . . . . . . . . (4,178) (4,178) Changes in Certain Current Assets and Liabilities: Accounts Receivable. . . . . . . . . . . . . . . . . . . (1,964) (1,804) Fuel, Materials and Supplies . . . . . . . . . . . . . . (1,870) 7,149 Accounts Payable . . . . . . . . . . . . . . . . . . . . 3,522 (2,655) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 1,331 2,292 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464 Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,174 (2,044) Net Cash Flows From Operating Activities . . . . . . 40,583 41,156 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (4,829) (2,042) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,254 - Net Cash Flows Used For Investing Activities . . . . (2,575) (2,042) FINANCING ACTIVITIES: Return of Capital to Parent Company. . . . . . . . . . . . (3,000) (2,000) Change in Short-term Debt (net). . . . . . . . . . . . . . (3,575) (9,575) Retirement of Long-term Debt . . . . . . . . . . . . . . . (25,000) (20,010) Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (6,528) (5,858) Net Cash Flows Used For Financing Activities . . . . (38,103) (37,443) Net Increase (Decrease) in Cash and Cash Equivalents . . . . (95) 1,671 Cash and Cash Equivalents at Beginning of Period . . . . . . 237 139 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 142 $ 1,810 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $2,508,000 and $2,699,000 and for income taxes was $(1,188,000) and $(1,598,000) in 1998 and 1997, respectively.
See Notes to Financial Statements. AEP GENERATING COMPANY NOTES TO FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. FINANCING ACTIVITIES In March 1998 $12.5 million of the 1995 Series A pollution control revenue bonds due 2025 and $12.5 million of the 1995 Series B pollution control revenue bonds due 2025 were redeemed. 3. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies and one unaffiliated utility pursuant to Federal Energy Regulatory Commission (FERC) approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Net income decreased $0.2 million or 7% for the third quarter and $0.3 million or 4% for the year-to-date period as a result of capital returned to the parent company in 1997, May 1998 and August 1998. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $ 1.1 2 $(3.1) (2) Fuel Expense. . . . . . . . 1.6 6 (0.7) (1) Other Operation Expense . . (0.3) (14) (0.8) (10) Maintenance Expense . . . . 0.3 14 (1.0) (10) Interest Charges. . . . . . (0.1) (8) (0.5) (17) The increase in operating revenues for the third quarter reflects the recovery through the unit power agreements of higher operating expenses, primarily fuel expense. In the year-to-date period, lower operating expenses and a lower return on common equity reflecting the return of capital are the primary reasons for the decline in operating revenues. Fuel expense increased in the third quarter reflecting a 7% increase in generation. While year-to-date generation increased 5%, a lower average cost of fuel consumed, due to lower coal prices, produced a reduction in fuel expense. The decline in other operation expense in both the quarter and year-to-date periods is primarily due to a decline in administrative and general expenses reflecting a reduction in allocated wages and employee benefit costs and a reduction in a FERC assessment. Maintenance expense increased during the quarter due to a rise in boiler plant repair expenditures, while for the year-to-date period the reduction in maintenance expense reflects a longer duration outage in 1997 compared with 1998's outage. The decline in interest charges was due to a reduction in outstanding long-term debt balances reflecting the redemption of $20 million in June 1997 and $25 million in March 1998 of pollution control revenue bonds. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) OPERATING REVENUES . . . . . . . . . . . $1,312,293 $438,510 $2,689,576 $1,228,044 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 113,059 104,514 322,459 288,773 Purchased Power. . . . . . . . . . . . 939,595 100,587 1,654,929 261,595 Other Operation. . . . . . . . . . . . 73,988 60,585 191,297 185,852 Maintenance. . . . . . . . . . . . . . 30,691 27,615 97,519 79,505 Depreciation and Amortization. . . . . 36,059 34,568 107,252 102,817 Taxes Other Than Federal Income Taxes. 29,003 29,544 89,181 89,580 Federal Income Taxes . . . . . . . . . 18,947 16,317 45,547 45,411 TOTAL OPERATING EXPENSES . . . 1,241,342 373,730 2,508,184 1,053,533 OPERATING INCOME . . . . . . . . . . . . 70,951 64,780 181,392 174,511 NONOPERATING INCOME (LOSS) . . . . . . . (5,664) 305 (4,490) 628 INCOME BEFORE INTEREST CHARGES . . . . . 65,287 65,085 176,902 175,139 INTEREST CHARGES . . . . . . . . . . . . 31,841 30,332 95,133 88,524 NET INCOME . . . . . . . . . . . . . . . 33,446 34,753 81,769 86,615 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 675 681 1,822 6,326 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 32,771 $ 34,072 $ 79,947 $ 80,289 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $195,262 $197,471 $207,544 $208,472 NET INCOME . . . . . . . . . . . . . . . 33,446 34,753 81,769 86,615 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 29,729 28,609 89,187 85,827 Cumulative Preferred Stock . . . . . 567 572 1,499 2,649 Capital Stock Expense. . . . . . . . . 108 109 323 3,677 BALANCE AT END OF PERIOD . . . . . . . . $198,304 $202,934 $198,304 $202,934 The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,959,309 $1,942,325 Transmission . . . . . . . . . . . . . . . . . . . . 1,117,332 1,079,919 Distribution . . . . . . . . . . . . . . . . . . . . 1,647,232 1,583,161 General. . . . . . . . . . . . . . . . . . . . . . . 228,803 207,380 Construction Work in Progress. . . . . . . . . . . . 77,573 88,261 Total Electric Utility Plant . . . . . . . . 5,030,249 4,901,046 Accumulated Depreciation and Amortization. . . . . . 1,958,654 1,869,057 NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,071,595 3,031,989 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 109,354 34,544 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 8,467 6,947 Accounts Receivable. . . . . . . . . . . . . . . . . 161,074 164,657 Allowance for Uncollectible Accounts . . . . . . . . (1,590) (1,333) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 48,425 47,901 Materials and Supplies . . . . . . . . . . . . . . . 63,860 57,359 Accrued Utility Revenues . . . . . . . . . . . . . . 40,630 51,208 Prepayments and Other. . . . . . . . . . . . . . . . 16,671 6,960 TOTAL CURRENT ASSETS . . . . . . . . . . . . 337,537 333,699 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 434,704 441,223 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 37,346 41,975 TOTAL. . . . . . . . . . . . . . . . . . . $3,990,536 $3,883,430
See Notes to Consolidated Financial Statements. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (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. . . . . . . . . . . . . . . . . . . 638,510 613,048 Retained Earnings. . . . . . . . . . . . . . . . . . 198,304 207,544 Total Common Shareholder's Equity. . . . . . 1,097,272 1,081,050 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 19,439 19,747 Subject to Mandatory Redemption. . . . . . . . . . 22,310 22,310 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,532,809 1,415,026 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,671,830 2,538,133 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 164,715 137,371 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 19,504 79,509 Short-term Debt. . . . . . . . . . . . . . . . . . . 61,975 130,300 Accounts Payable . . . . . . . . . . . . . . . . . . 80,625 96,816 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 43,772 41,549 Customer Deposits. . . . . . . . . . . . . . . . . . 14,194 13,713 Interest Accrued . . . . . . . . . . . . . . . . . . 29,841 20,949 Revenue Refunds Accrued. . . . . . . . . . . . . . . 42,418 3,311 Other. . . . . . . . . . . . . . . . . . . . . . . . 91,876 68,812 TOTAL CURRENT LIABILITIES. . . . . . . . . . 384,205 454,959 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 649,472 658,655 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 63,948 67,496 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 56,366 26,816 CONTINGENCIES (Note 6) TOTAL. . . . . . . . . . . . . . . . . . . $3,990,536 $3,883,430
See Notes to Consolidated Financial Statements. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 81,769 $ 86,615 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 108,158 103,796 Deferred Federal Income Taxes. . . . . . . . . . . . . . (1,452) (8,719) Deferred Investment Tax Credits. . . . . . . . . . . . . (3,548) (3,571) Provision for Rate Refunds . . . . . . . . . . . . . . . 9,342 3,083 Deferred Power Supply Costs (net). . . . . . . . . . . . 25,137 13,951 Amortization of Deferred Property Taxes. . . . . . . . . 12,940 13,240 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 3,840 13,458 Fuel, Materials and Supplies . . . . . . . . . . . . . . (7,025) (1,763) Accrued Utility Revenues . . . . . . . . . . . . . . . . 10,578 18,942 Prepayments and Other Current Assets . . . . . . . . . . (9,711) 3,695 Accounts Payable . . . . . . . . . . . . . . . . . . . . (16,191) 13,188 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,223 1,642 Interest Accrued . . . . . . . . . . . . . . . . . . . . 8,892 12,285 Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 39,107 (1,933) Payment of Disputed Tax and Interest Related to COLI . . . (68,316) - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 22,652 (19,383) Net Cash Flows From Operating Activities . . . . . . 218,395 248,526 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (138,297) (146,039) Proceeds from Sale of Property . . . . . . . . . . . . . . 914 4,204 Net Cash Flows Used For Investing Activities . . . . (137,383) (141,835) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . 25,000 20,000 Issuance of Long-term Debt . . . . . . . . . . . . . . . . 193,431 183,257 Change in Short-term Debt (net). . . . . . . . . . . . . . (68,325) 22,825 Retirement of Cumulative Preferred Stock . . . . . . . . . (229) (183,842) Retirement of Long-term Debt . . . . . . . . . . . . . . . (138,472) (56,378) Dividends Paid on Common Stock . . . . . . . . . . . . . . (89,187) (85,827) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,710) (5,319) Net Cash Flows Used For Financing Activities . . . . (79,492) (105,284) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 1,520 1,407 Cash and Cash Equivalents at Beginning of Period . . . . . . 6,947 7,260 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,467 $ 8,667 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $83,359,000 and $73,466,000 and for income taxes was $38,378,000 and $46,965,000 in 1998 and 1997, respectively. Noncash acquisitions under capital leases were $16,909,000 and $14,377,000 in 1998 and 1997, respectively.
See Notes to Consolidated Financial Statements. APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. RATE MATTER In September 1992 the Company implemented, subject to refund, an $8.7 million annual rate increase to its wholesale customers pending a final order from the Federal Energy Regulatory Commission (FERC). On June 29, 1998 the FERC granted an annual rate increase of $3.4 million and required a refund including interest of amounts collected in excess of the $3.4 million annual increase. A rehearing of the FERC's order has been requested. At September 30, 1998, the Company had fully provided for the refund obligation plus interest as a current liability. 3. FINANCING ACTIVITIES During the first nine months of 1998, the Company issued two series of senior unsecured notes of $100 million each with rates of 7.20% and 7.30% due in 2038. During the first nine months of 1998, the Company reacquired the following first mortgage bonds for $138 million including reacquisition premiums: Principal Amount % Rate Due Date Reacquired (in thousands) 8.75 2022 - February 1 $29,919 8.70 2022 - May 22 35,000 7.95 2002 - March 1 60,000 8.43 2022 - June 1 12,529 In June 1998, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital. 4. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed software acquisition and development costs with the exception of newly developed customer service and billing software costs which were capitalized in accordance with an order of the Virginia State Corporation Commission. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. 5. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $320 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $70 million for sales and approximately $45 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. 6. CONTINGENCIES Taxes As discussed in Note 9, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $77 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Revised Air Quality Standards The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $325 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1997 Annual Report. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 RESULTS OF OPERATIONS Despite an increase in revenues net of fuel and purchased power expenses (net revenues) of $26.3 million for the third quarter and $34.5 million for the year-to-date period due to an increase in weather related retail sales and wholesale power marketing and trading transactions within AEP's traditional marketing area, net income decreased $1.3 million or 4% for the quarter and $4.8 million or 6% for the year-to-date period. The decline in net income was primarily due to an increase in operating expenses other than fuel and purchased power, losses on certain non-regulated energy trades outside of the Company's marketing area, an increase in interest charges and the recordation of provisions for revenue refunds, net of tax. The significant changes in income statement line items and net revenues were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $873.8 199 $1,461.5 119 Fuel Expense . . . . . . . 8.5 8 33.7 12 Purchased Power Expense. . 839.0 N.M. 1,393.3 N.M. Net Revenues . . . . . . 26.3 34.5 Other Operation Expense. . 13.4 22 5.4 3 Maintenance Expense. . . . 3.1 11 18.0 23 Depreciation and Amortization . . . . . . 1.5 4 4.4 4 Federal Income Taxes . . . 2.6 16 0.1 - Nonoperating Income. . . . (6.0) N.M. (5.1) N.M. Interest Charges . . . . . 1.5 5 6.6 7 N.M. = Not Meaningful Operating revenues increased significantly in both the third quarter and the year-to-date periods due predominantly to increased retail and wholesale sales. The increase in retail revenues can be attributed to increased energy sales to residential and commercial customers reflecting warmer spring and summer weather in 1998. Revenues from wholesale customers increased significantly reflecting growth in power marketing and trading transactions. The increases in fuel expense for the quarter and year-to-date periods were primarily due to increased coal fired generation to meet the increased demand. Purchased power expense increased primarily as a result of the growth in power marketing and trading activities. The increase in other operation expense was mainly due to costs related to the increase in sales and employee incentive pay accruals. Maintenance expense increased as a result of an increase in planned expenditures to maintain transmission and distribution right-of-ways and, for the year-to-date period, costs for repair and restoration of service caused by two severe snowstorms. The increase in depreciation and amortization expense is mainly due to additional investment in depreciable plant reflecting improvements to the transmission and distribution system. In the third quarter federal income tax expense attributable to operations increased primarily due to an increase in pre-tax operating income. The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 5, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger. Interest charges for the quarter and year-to-date periods increased as a result of the accrual of interest on a revenue refund to wholesale customers under the terms of a final rate order and an increase in long-term debt outstanding. FINANCIAL CONDITION Total plant and property additions including capital leases for the first nine months of 1998 were $155 million. During the first nine months of 1998, the Company issued two series of senior unsecured notes of $100 million each with rates of 7.20% and 7.30% due in 2038 and redeemed $137 million principal amount of first mortgage bonds with interest rates from 7.95% to 8.75%. Short-term debt decreased by $68 million from year-end balances. In June 1998, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital. REVISED AIR QUALITY STANDARDS The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $325 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. COMPUTER ISSUE - YEAR 2000 On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were 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-Year 2000 ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem 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 Year 2000 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, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that: "While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30, 1999 to June 30, 1999. Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. Various state regulatory commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction. 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, communications, and the physical generation and delivery of energy; 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 our progress toward becoming ready for the Year 2000 as of September 30, 1998: 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% 11/30/1998 86% 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 2% replacing or retiring 60% those mission critical and high priority digital-based systems with problems Client processing dates past the Server: Year 2000. Testing these 1% 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 September 30, 1998, the Company has spent $4 million on the Year 2000 project and, estimates spending an additional $12 million to $16 million to achieve Year 2000 readiness. Most Year 2000 costs are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 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. In addition, although as discussed 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, Year 2000-related issues may materially adversely affect AEP. Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's Contingency Planning Guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999. Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others: * Continuing availability of experienced consultants and IT personnel and related resources * Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness * Ability of the Company to identify and implement contingency plans. TAXES As discussed in Note 9, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $77 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $320 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $70 million for sales and approximately $45 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) OPERATING REVENUES . . . . . . . . . . . $843,007 $313,024 $1,711,773 $841,294 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 49,693 52,269 143,533 134,198 Purchased Power. . . . . . . . . . . . 561,812 54,444 972,535 138,278 Other Operation. . . . . . . . . . . . 59,478 46,505 150,843 132,256 Maintenance. . . . . . . . . . . . . . 13,932 17,535 43,128 50,602 Depreciation . . . . . . . . . . . . . 22,760 22,784 68,454 67,800 Amortization of Zimmer Plant Phase-in Costs . . . . . . . . . . . - - - 15,744 Taxes Other Than Federal Income Taxes. 29,295 29,861 86,921 89,484 Federal Income Taxes . . . . . . . . . 31,774 24,731 69,716 57,639 TOTAL OPERATING EXPENSES . . . 768,744 248,129 1,535,130 686,001 OPERATING INCOME . . . . . . . . . . . . 74,263 64,895 176,643 155,293 NONOPERATING INCOME (LOSS) . . . . . . . (2,337) 658 (1,109) 2,018 INCOME BEFORE INTEREST CHARGES . . . . . 71,926 65,553 175,534 157,311 INTEREST CHARGES . . . . . . . . . . . . 19,635 20,065 58,856 59,069 NET INCOME . . . . . . . . . . . . . . . 52,291 45,488 116,678 98,242 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 532 532 1,598 1,909 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 51,759 $ 44,956 $ 115,080 $ 96,333 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $160,171 $111,953 $138,172 $ 99,582 NET INCOME . . . . . . . . . . . . . . . 52,291 45,488 116,678 98,242 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 20,661 19,671 61,983 59,013 Cumulative Preferred Stock . . . . . 437 437 1,312 1,312 Capital Stock Expense. . . . . . . . . 95 95 286 261 BALANCE AT END OF PERIOD . . . . . . . . $191,269 $137,238 $191,269 $137,238 The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,520,079 $1,521,381 Transmission . . . . . . . . . . . . . . . . . . . . 338,743 336,446 Distribution . . . . . . . . . . . . . . . . . . . . 927,225 926,178 General. . . . . . . . . . . . . . . . . . . . . . . 122,532 138,041 Construction Work in Progress. . . . . . . . . . . . 120,161 54,064 Total Electric Utility Plant . . . . . . . . 3,028,740 2,976,110 Accumulated Depreciation . . . . . . . . . . . . . . 1,118,654 1,074,588 NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,910,086 1,901,522 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 67,941 33,235 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 6,505 12,626 Accounts Receivable (net). . . . . . . . . . . . . . 129,936 110,969 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 15,856 19,549 Materials and Supplies . . . . . . . . . . . . . . . 30,442 27,628 Accrued Utility Revenues . . . . . . . . . . . . . . 50,537 51,765 Prepayments. . . . . . . . . . . . . . . . . . . . . 34,219 30,397 TOTAL CURRENT ASSETS . . . . . . . . . . . . 267,495 252,934 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 351,571 359,481 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 21,658 66,688 TOTAL. . . . . . . . . . . . . . . . . . . $2,618,751 $2,613,860
See Notes to Consolidated Financial Statements. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (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. . . . . . . . . . . . . . . . . . . 572,397 572,112 Retained Earnings. . . . . . . . . . . . . . . . . . 191,269 138,172 Total Common Shareholder's Equity. . . . . . 804,692 751,310 Cumulative Preferred Stock - Subject to Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000 Long-term Debt . . . . . . . . . . . . . . . . . . . 959,651 887,850 TOTAL CAPITALIZATION . . . . . . . . . . . . 1,789,343 1,664,160 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 46,028 42,271 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . - 81,750 Short-term Debt. . . . . . . . . . . . . . . . . . . 55,350 66,600 Accounts Payable . . . . . . . . . . . . . . . . . . 52,053 71,287 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 95,052 131,107 Interest Accrued . . . . . . . . . . . . . . . . . . 24,227 14,198 Other. . . . . . . . . . . . . . . . . . . . . . . . 42,908 28,972 TOTAL CURRENT LIABILITIES. . . . . . . . . . 269,590 393,914 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 436,168 433,593 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 50,272 52,934 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 27,350 26,988 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $2,618,751 $2,613,860
See Notes to Consolidated Financial Statements. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 116,678 $ 98,242 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . 68,617 67,978 Deferred Federal Income Taxes. . . . . . . . . . . . . . 12,398 (741) Deferred Investment Tax Credits. . . . . . . . . . . . . (2,662) (2,705) Deferred Fuel Costs (net). . . . . . . . . . . . . . . . (10,169) (4,089) Amortization of Zimmer Plant Operating Expenses and Carrying Charges . . . . . . . . . . . . . . . . . . . - 15,936 Amortization of Deferred Property Taxes. . . . . . . . . 48,775 48,601 Changes in Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (18,967) (52,786) Fuel, Materials and Supplies . . . . . . . . . . . . . . 879 1,364 Accrued Utility Revenues . . . . . . . . . . . . . . . . 1,228 (14,057) Accounts Payable . . . . . . . . . . . . . . . . . . . . (19,234) 2,008 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (36,055) (50,645) Interest Accrued . . . . . . . . . . . . . . . . . . . . 10,029 12,707 Other Current Assets and Current Liabilities . . . . . . 10,114 5,350 Payment of Disputed Tax and Interest Related to COLI . . . (37,243) - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 16,799 (9,827) Net Cash Flows From Operating Activities . . . . . . 161,187 117,336 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (84,178) (82,696) Proceeds from Sale of Property and Other . . . . . . . . . 2,546 1,586 Net Cash Flows Used For Investing Activities . . . . (81,632) (81,110) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . 111,075 38,574 Change in Short-term Debt (net). . . . . . . . . . . . . . (11,250) 42,925 Retirement of Cumulative Preferred Stock . . . . . . . . . - (52,953) Retirement of Long-term Debt . . . . . . . . . . . . . . . (122,206) - Dividends Paid on Common Stock . . . . . . . . . . . . . . (61,983) (59,013) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,312) (2,297) Net Cash Flows Used For Financing Activities . . . . (85,676) (32,764) Net Increase (Decrease) in Cash and Cash Equivalents . . . . (6,121) 3,462 Cash and Cash Equivalents at Beginning of Period . . . . . . 12,626 9,134 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 6,505 $ 12,596 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $46,014,000 and $43,341,000 and for income taxes was $27,254,000 and $50,609,000 in 1998 and 1997, respectively. Noncash acquisitions under capital leases were $10,029,000 and $6,583,000 in 1998 and 1997, respectively.
See Notes to Consolidated Financial Statements. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. FINANCING ACTIVITIES During the first nine months of 1998 the Company redeemed $57 million of 9.15% and $25 million of 7.00% first mortgage bonds at maturity and $40 million of 7.95% first mortgage bonds due 2002 and issued $52 million of 6.51% and $60 million of 6.55% senior unsecured notes due in 2008. 3. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. 4. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $190 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside the traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $40 million for sales and approximately $25 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. 5. CONTINGENCIES Taxes As discussed in Note 8, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of COLI interest deductions through September 30, 1998 would reduce earnings by approximately $42 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998, the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Revised Air Quality Standards The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $140 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1997 Annual Report. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 Net income increased $6.8 million or 15% for the third quarter and $18.4 million or 19% for the year-to-date period primarily due to increased sales to retail customers reflecting warmer summer weather and growth in wholesale power marketing and trading activities. The significant changes in income statement line items and net revenues were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $530.0 169 $870.5 103 Fuel Expense. . . . . . . . (2.6) (5) 9.3 7 Purchased Power Expense . . 507.4 N.M. 834.3 N.M. Net Revenues. . . . . . . 25.2 26.9 Other Operation Expense . . 13.0 28 18.6 14 Maintenance Expense . . . . (3.6) (21) (7.5) (15) Amortization of Zimmer Plant Phase-in Costs. . . - - (15.7) N.M. Federal Income Taxes. . . . 7.0 28 12.1 21 Nonoperating Income . . . . (3.0) N.M. (3.1) (155) N.M. = Not Meaningful Operating revenues increased significantly in both the third quarter and the year-to-date period due predominantly to increased retail and wholesale sales. The increase in retail revenues resulted from increased sales to residential customers reflecting warmer summer weather in 1998. Revenues from wholesale customers increased reflecting substantial increases in power marketing and trading transactions. The increase in fuel expense for the year-to-date period was due to an increase in generation reflecting the increase in demand for electricity. Purchased power expense increased primarily as a result of increased power marketing and trading activities. Net revenues increased $25.2 million in the third quarter and $26.9 million in the year-to-date period due to increased retail sales reflecting warmer summer weather and the successful trading of wholesale energy in a volatile market. The increase in other operation expense was mainly due to costs related to the increase in sales including increased emission allowance consumption, transmission costs and employee pensions and benefits expense. Maintenance expense decreased due to the effect of scheduled power plant maintenance outages in 1997 and a decline in overhead line maintenance expenditures in 1998. In 1997 two generating units underwent a scheduled outage for inspection and repairs while in 1998 only one unit had a scheduled outage for inspection and repairs. Expenditures for overhead line maintenance declined in 1998 as a result of lower expenditures for tree trimming and repair of conductors and pole attachments. The reduction in the amortization of deferred Zimmer Plant phase-in costs reflects the completion of the surcharge recovery plan and the amortization of the original deferral in June 1997. The cessation of the amortization did not affect net income since the amortization was being recovered in revenues through a surcharge which terminated with the completion of the amortization. Federal income taxes attributable to operations increased primarily due to an increase in pre-tax operating income. The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) OPERATING REVENUES . . . . . . . . . . . $945,474 $362,058 $1,978,907 $1,023,879 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 51,014 62,275 133,768 176,051 Purchased Power. . . . . . . . . . . . 625,294 54,043 1,126,651 124,216 Other Operation. . . . . . . . . . . . 97,985 80,399 257,268 240,310 Maintenance. . . . . . . . . . . . . . 39,107 29,408 99,444 85,103 Depreciation and Amortization. . . . . 36,380 35,271 108,407 105,395 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals. . . . . . . - 2,999 - 10,821 Taxes Other Than Federal Income Taxes. 16,514 15,781 49,011 49,657 Federal Income Taxes . . . . . . . . . 20,541 21,433 52,157 61,843 TOTAL OPERATING EXPENSES . . . 886,835 301,609 1,826,706 853,396 OPERATING INCOME . . . . . . . . . . . . 58,639 60,449 152,201 170,483 NONOPERATING INCOME (LOSS) . . . . . . . (2,404) 499 191 1,464 INCOME BEFORE INTEREST CHARGES . . . . . 56,235 60,948 152,392 171,947 INTEREST CHARGES . . . . . . . . . . . . 17,544 15,857 51,421 48,689 NET INCOME . . . . . . . . . . . . . . . 38,691 45,091 100,971 123,258 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,208 1,219 3,627 4,544 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 37,483 $ 43,872 $ 97,344 $118,714 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $279,943 $285,783 $278,814 $269,071 NET INCOME . . . . . . . . . . . . . . . 38,691 45,091 100,971 123,258 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 29,366 44,066 88,098 102,196 Cumulative Preferred Stock . . . . . 1,183 1,186 3,550 3,573 Capital Stock Expense. . . . . . . . . 25 33 77 971 BALANCE AT END OF PERIOD . . . . . . . . $288,060 $285,589 $288,060 $285,589 The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,555,893 $2,545,484 Transmission . . . . . . . . . . . . . . . . . . . . 912,155 908,736 Distribution . . . . . . . . . . . . . . . . . . . . 756,348 737,902 General (including nuclear fuel) . . . . . . . . . . 229,589 233,888 Construction Work in Progress. . . . . . . . . . . . 129,122 88,487 Total Electric Utility Plant . . . . . . . . 4,583,107 4,514,497 Accumulated Depreciation and Amortization. . . . . . 2,049,510 1,973,937 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,533,597 2,540,560 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . . 627,792 566,390 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 211,848 156,085 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 10,838 5,860 Accounts Receivable. . . . . . . . . . . . . . . . . 171,428 137,310 Allowance For Uncollectible Accounts . . . . . . . . (1,978) (1,188) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 15,985 17,182 Materials and Supplies . . . . . . . . . . . . . . . 80,206 78,701 Accrued Utility Revenues . . . . . . . . . . . . . . 40,378 30,521 Prepayments. . . . . . . . . . . . . . . . . . . . . 7,821 4,828 TOTAL CURRENT ASSETS . . . . . . . . . . . . 324,678 273,214 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 413,799 400,489 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 30,583 31,060 TOTAL. . . . . . . . . . . . . . . . . . . $4,142,297 $3,967,798
See Notes to Consolidated Financial Statements. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (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. . . . . . . . . . . . . . . . . . . 732,573 732,472 Retained Earnings. . . . . . . . . . . . . . . . . . 288,060 278,814 Total Common Shareholder's Equity. . . . . . 1,077,217 1,067,870 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 9,346 9,435 Subject to Mandatory Redemption. . . . . . . . . . 68,445 68,445 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,124,961 1,014,237 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,279,969 2,159,987 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning. . . . . . . . . . . . . . . 440,447 381,016 Other. . . . . . . . . . . . . . . . . . . . . . . . 236,876 232,667 TOTAL OTHER NONCURRENT LIABILITIES . . . . . 677,323 613,683 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . - 35,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 103,500 119,600 Accounts Payable . . . . . . . . . . . . . . . . . . 79,011 68,394 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 43,615 46,850 Interest Accrued . . . . . . . . . . . . . . . . . . 16,081 15,741 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963 Obligations Under Capital Leases . . . . . . . . . . 32,976 34,033 Other. . . . . . . . . . . . . . . . . . . . . . . . 79,289 58,548 TOTAL CURRENT LIABILITIES. . . . . . . . . . 377,899 383,129 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 559,596 559,708 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 132,318 138,045 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 89,639 92,419 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 25,553 20,827 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $4,142,297 $3,967,798
See Notes to Consolidated Financial Statements. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 100,971 $ 123,258 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 111,510 111,176 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals. . . . . . . . . . . . . . . . - 10,821 Deferral of Incremental Nuclear Refueling Outage Expenses (net). . . . . . . . . . . . . . . . . 11,368 (2,402) Deferred Federal Income Taxes. . . . . . . . . . . . . . 11,226 (9,753) Deferred Investment Tax Credits. . . . . . . . . . . . . (5,727) (5,906) Under-recovery of Fuel and Purchased Power . . . . . . . (42,676) (9,554) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (33,328) 7,029 Fuel, Materials and Supplies . . . . . . . . . . . . . . (308) 8,705 Accrued Utility Revenues . . . . . . . . . . . . . . . . (9,857) 7,284 Accounts Payable . . . . . . . . . . . . . . . . . . . . 10,617 (36,462) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (3,235) (13,615) Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464 Payment of Disputed Tax and Interest Related to COLI . . . (53,628) - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 24,237 26,966 Net Cash Flows From Operating Activities . . . . . . 139,634 236,011 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (98,218) (79,066) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 4,154 1,798 Net Cash Flows Used For Investing Activities . . . . (94,064) (77,268) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . 122,222 47,728 Retirement of Cumulative Preferred Stock . . . . . . . . . (65) (78,838) Retirement of Long-term Debt . . . . . . . . . . . . . . . (55,000) (50,000) Change in Short-term Debt (net). . . . . . . . . . . . . . (16,100) 14,350 Dividends Paid on Common Stock . . . . . . . . . . . . . . (88,098) (87,195) Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,551) (4,746) Net Cash Flows Used For Financing Activities . . . . (40,592) (158,701) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 4,978 42 Cash and Cash Equivalents at Beginning of Period . . . . . . 5,860 8,233 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 10,838 $ 8,275 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $49,041,000 and $44,575,000 and for income taxes was $20,224,000 and $83,580,000 in 1998 and 1997, respectively. Noncash acquisitions under capital leases were $7,050,000 and $80,231,000 in 1998 and 1997, respectively.
See Notes to Consolidated Financial Statements. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. FINANCING ACTIVITIES In 1998 the Company redeemed $35 million of 7.00% first mortgage bonds at maturity and $20 million of 7.80% first mortgage bonds due 2023 at face value. In May 1998 $125 million of 7.60% junior subordinated deferrable interest debentures due 2038 were issued. 3. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there are no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. 4. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $200 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998 the Company's share of the unrealized mark-to-market gains and losses of such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $45 million for sales and approximately $30 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. 5. CONTINGENCIES Taxes As discussed in Note 7, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $64 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Cook Nuclear Plant Shutdown As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1997 Annual Report, both units of the Cook Nuclear Plant were shut down by the Company in September 1997 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 the issues identified in the letter. The Company is working with the NRC to resolve a remaining issue in the letter. On April 17, 1998, the NRC notified the Company that it had convened a Restart Panel for the Cook Plant. On July 30, 1998, the Company received a letter from the NRC providing the NRC's list of required restart activities. The Company is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the issues necessary for the restart of the units. 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. The current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition. The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter. On July 24, 1998, the Company received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In a letter dated October 13, 1998, the NRC issued to the Company a Notice of Violation and proposed $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. The Company paid the penalty. The cost of electricity supplied to retail customers rose due to the outage of the two units since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor as was the case with regard to Cook, a regulatory asset is recorded and revenues are accrued. Due to the unscheduled Cook Plant outage, the Company's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million. The Indiana Utility Regulatory Commission approved two agreements authorizing the Company during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by the Company, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the recovery of replacement energy cost due to the extended Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that the Company should be able to recover the Cook replacement energy costs; however, if recovery of the replacement costs is denied, results of operations and cash flows would be adversely affected. Revised Air Quality Standards The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $169 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition Other The Company continues to be involved in certain other matters discussed in its 1997 Annual Report. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 RESULTS OF OPERATIONS Despite substantial increases in operating revenues due to increased retail sales and power marketing and trading activities, net income decreased $6.4 million or 14% for the quarter and $22.3 million or 18% for the year-to-date period. The decreases in net income are due primarily to increased costs related to an extended Cook Nuclear Plant outage, increased purchased power costs, losses on certain energy trades outside AEP's traditional market area and a decrease in capacity credits from the AEP System Power Pool (Power Pool). Under the terms of the Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the Power Pool members based on their relative peak demands and generating reserves. The reduction in capacity credits received can be attributed to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all Power Pool members. As discussed in Note 5 of the Notes to Consolidated Financial Statements, the Cook Nuclear Plant was shut down in September 1997. The shutdown has had a significant impact on the operations of the Company as reflected in the variations of certain income statement line items discussed below. Income statement line items which changed significantly were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $583.4 161 $ 955.0 93 Fuel Expense . . . . . . . (11.3) (18) (42.3) (24) Purchased Power Expense. . 571.3 N.M. 1,002.4 N.M. Other Operation Expense. . 17.6 22 17.0 7 Maintenance Expense. . . . 9.7 33 14.3 17 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals. . . . . . (3.0) N.M. (10.8) N.M. Federal Income Taxes . . . (0.9) (4) (9.7) (16) Nonoperating Income. . . . (2.9) N.M. (1.3) (87) N.M. = Not Meaningful Operating revenues increased significantly in both periods due predominantly to an increase in sales to retail and wholesale customers. The increase in retail revenues can be attributed to increased energy sales to all retail customer classes reflecting warmer summer weather and increased industrial customer usage. Fuel and power supply cost recovery accruals also contributed to the increase in retail revenues. Under the fuel cost recovery mechanism, revenues are accrued to match increased fuel expense in both of the Company's retail jurisdictions and for replacement power costs in the Michigan jurisdiction. The fuel and purchased power costs incurred are subsequently reviewed by the commissions and, if acceptable, approved for recovery through billings. During the extended outage of both nuclear units, retail revenues increased from the accrual of revenues to match the increased fuel costs and purchase power expense incurred to replace the unavailable lower cost nuclear power. Revenues from wholesale customers increased reflecting growth in power marketing and trading activities. Fuel expense decreased significantly in both periods due to a decline in nuclear generation reflecting the outages of both nuclear units in 1998. The significant increase in purchased power expense for both periods was the result of purchases for the power marketing and trading business and additional energy purchases from the Power Pool due to the unavailability of the nuclear units. Other operation expense increased for both periods as a result of costs associated with the extended Cook Plant outage and increased incentive pay accruals. The increase in maintenance expense for both periods was the result of additional expenditures to prepare the nuclear units for restart. The recovery periods for Rockport Plant Unit 1 costs deferred under a rate phase-in plan in the Indiana and FERC jurisdictions ended in the fall of 1997 causing the decrease in amortization of phase-in plan deferrals. The deferred costs were amortized over a 10-year period commensurate with their collection from customers pursuant to commission orders. The Company has increased its decommissioning expense accruals (approximately $12 million through September 30, 1998), pending approval from the Indiana Utility Regulatory Commission (IURC), in an amount equal to the continuing phase-in plan revenues. On November 12, 1998 the IURC issued an order that denied the Company's request to increase its decommissioning accruals and requires the Company to submit revised quarterly net operating income calculations for each quarter subsequent to August 1997. The Company will be making the revised calculations and under the worst case scenario there would be no favorable impact on results of operations. Federal income taxes attributable to operations decreased for the year-to-date period as a result of a decrease in pre-tax operating income. The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger. FINANCIAL CONDITION Total plant and property additions including capital leases for the year-to-date period were $106 million. During the first nine months of 1998 short-term debt outstanding decreased by $16 million. During the first nine months of 1998 the Company redeemed two series of first mortgage bonds; $35 million at 7.00% at maturity and $20 million at 7.80% due 2023, and issued $125 million of 7.60% junior subordinated deferrable interest debentures due 2038. COOK NUCLEAR PLANT SHUTDOWN As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1997 Annual Report, both units of the Cook Nuclear Plant were shut down by the Company in September 1997 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 the issues identified in the letter. The Company is working with the NRC to resolve a remaining issue in the letter. On April 17, 1998, the NRC notified the Company that it had convened a Restart Panel for the Cook Plant. On July 30, 1998, the Company received a letter from the NRC providing the NRC's list of required restart activities. The Company is and will be meeting with the Panel on a regular basis, until the Cook Plant units are returned to service, to identify and address the issues necessary for the restart of the units. 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. The current restart schedule indicates Unit 1 is expected to return to service by the end of the first quarter of 1999. The restart schedule for Unit 2 has not been completed; however, management anticipates that Unit 2 may return to service 90 days after Unit 1. If the units are not returned to service, there could be a material adverse effect on financial condition. The incremental cost expected to be incurred to restart the Cook units is approximately $70 million for 1998, of which $34 million has been incurred through September 30, 1998. However, approximately $20 million of previously budgeted work for 1998 at the Cook Plant will not be incurred and will partially mitigate the incremental restart costs. The cost and schedule for the outage during 1999 could be significantly impacted if additional work is identified beyond the $35 million planned for the first quarter. On July 24, 1998, the Company received an "adverse trend letter" from the NRC indicating that NRC senior managers had determined that there had been a slow decline in performance at the Cook Plant during the 18 month period preceding the letter. The letter indicated that the NRC will closely monitor efforts to address issues at Cook Plant through additional inspection activities. In a letter dated October 13, 1998, the NRC issued to the Company a Notice of Violation and proposed $500,000 civil penalty for alleged violations at the Cook Plant discovered during five inspections conducted between August 4, 1997 and April 15, 1998. The Company paid the penalty. As a result of the extended outage, the cost of electricity supplied to retail customers increased since higher cost coal-fired generation and purchased power were substituted for low cost nuclear generation. In the Indiana and Michigan retail jurisdictions fuel cost recovery mechanisms permit the recovery, subject to regulatory commission review and approval, of changes in fuel costs including the fuel component of purchased power in the Indiana jurisdiction and changes in replacement power in the Michigan jurisdiction. Under the fuel cost recovery mechanisms, retail rates contain a fuel cost adjustment factor that reflects estimated fuel costs for the period during which the factor will be in effect subject to reconciliation to actual fuel costs in a future proceeding. When actual fuel costs exceed the estimated costs reflected in the billing factor, a regulatory asset is recorded and revenues are accrued. Due to the unscheduled Cook Plant outage, the Company's actual fuel costs significantly exceeded the estimated fuel costs reflected in its fuel cost adjustment factors. A regulatory asset has been recorded for revenues accrued in anticipation of future reconciliation and billing of the higher fuel costs to customers. At September 30, 1998, the regulatory asset was $61 million. The IURC approved two agreements authorizing the Company during the billing months of July through December 1998 to apply a fuel cost adjustment factor less than that requested by the Company, subject to future reconciliation or refund. The agreements provide the parties to the proceedings with the opportunity to conduct discovery regarding certain issues that were raised in the proceedings, including the recovery of replacement energy cost due to the Cook Plant outage, in anticipation of resolving the issues in a future fuel cost adjustment proceeding. Management believes that the Company should be able to recover the Cook replacement costs; however, if recovery of the replacement costs is denied, results of operations and cash flows would be adversely affected. The timetable for the return to service of the Cook Plant constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, other unforeseen issues encountered in preparing the Cook Plant for restart and the unpredictability of the NRC regulatory process. REVISED AIR QUALITY STANDARDS The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $169 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the Power Pool, substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $200 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998 the Company's share of the unrealized mark-to-market gains and losses of such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $45 million for sales and approximately $30 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. TAXES As discussed in Note 7, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $64 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. COMPUTER ISSUE - YEAR 2000 On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were 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-Year 2000 ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem 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 Year 2000 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, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that: "While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30, 1999 to June 30, 1999. Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. Various state regulatory commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction. 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, communications, and the physical generation and delivery of energy; 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 our progress toward becoming ready for the Year 2000 as of September 30, 1998: 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% 11/30/1998 86% 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 2% replacing or retiring 60% those mission critical and high priority digital-based systems with problems Client processing dates past the Server: Year 2000. Testing these 1% 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 September 30, 1998, the Company has spent $3 million on the Year 2000 project and, estimates spending an additional $7 million to $10 million to achieve Year 2000 readiness. Most Year 2000 costs are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 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. In addition, although as discussed 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, Year 2000-related issues may materially adversely affect AEP. Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's Contingency Planning Guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999. Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others: * Continuing availability of experienced consultants and IT personnel and related resources * Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness * Ability of the Company to identify and implement contingency plans. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) OPERATING REVENUES . . . . . . . . . . . . $282,319 $89,791 $571,743 $256,472 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . 21,478 20,020 61,963 58,647 Purchased Power. . . . . . . . . . . . . 208,945 28,632 375,333 73,775 Other Operation. . . . . . . . . . . . . 13,647 13,241 36,633 37,130 Maintenance. . . . . . . . . . . . . . . 7,335 6,148 23,759 16,826 Depreciation and Amortization. . . . . . 7,068 6,649 20,956 19,708 Taxes Other Than Federal Income Taxes. . 2,668 2,427 7,420 7,266 Federal Income Taxes . . . . . . . . . . 4,627 1,837 7,406 7,614 TOTAL OPERATING EXPENSES. . . . . 265,768 78,954 533,470 220,966 OPERATING INCOME . . . . . . . . . . . . . 16,551 10,837 38,273 35,506 NONOPERATING LOSS. . . . . . . . . . . . . (902) (62) (1,066) (351) INCOME BEFORE INTEREST CHARGES . . . . . . 15,649 10,775 37,207 35,155 INTEREST CHARGES . . . . . . . . . . . . . 7,207 6,323 21,335 18,431 NET INCOME . . . . . . . . . . . . . . . . $ 8,442 $ 4,452 $ 15,872 $ 16,724 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . $71,356 $82,982 $78,076 $84,090 NET INCOME . . . . . . . . . . . . . . . . 8,442 4,452 15,872 16,724 CASH DIVIDENDS DECLARED. . . . . . . . . . 7,075 6,690 21,225 20,070 BALANCE AT END OF PERIOD . . . . . . . . . $72,723 $80,744 $72,723 $80,744 The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Financial Statements. KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $ 259,980 $ 249,184 Transmission . . . . . . . . . . . . . . . . . . . . 325,854 303,456 Distribution . . . . . . . . . . . . . . . . . . . . 347,834 350,793 General. . . . . . . . . . . . . . . . . . . . . . . 74,670 71,462 Construction Work in Progress. . . . . . . . . . . . 24,167 32,060 Total Electric Utility Plant . . . . . . . . 1,032,505 1,006,955 Accumulated Depreciation and Amortization. . . . . . 310,083 296,318 NET ELECTRIC UTILITY PLANT . . . . . . . . . 722,422 710,637 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 12,031 6,414 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 955 1,381 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 18,122 24,127 Affiliated Companies . . . . . . . . . . . . . . . 11,469 1,722 Miscellaneous. . . . . . . . . . . . . . . . . . . 4,221 3,276 Allowance for Uncollectible Accounts . . . . . . . (698) (525) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 9,300 10,685 Materials and Supplies . . . . . . . . . . . . . . . 14,212 14,054 Accrued Utility Revenues . . . . . . . . . . . . . . 11,587 12,981 Other. . . . . . . . . . . . . . . . . . . . . . . . 3,568 1,715 TOTAL CURRENT ASSETS . . . . . . . . . . . . 72,736 69,416 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 91,502 90,045 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 6,788 10,159 TOTAL. . . . . . . . . . . . . . . . . . . $ 905,479 $ 886,671
See Notes to Financial Statements. KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (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. . . . . . . . . . . . . . . . . . . 138,750 128,750 Retained Earnings. . . . . . . . . . . . . . . . . . 72,723 78,076 Total Common Shareholder's Equity. . . . . . 261,923 257,276 Long-term Debt . . . . . . . . . . . . . . . . . . . 313,979 341,051 TOTAL CAPITALIZATION . . . . . . . . . . . . 575,902 598,327 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 28,124 26,544 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 25,000 - Short-term Debt. . . . . . . . . . . . . . . . . . . 49,350 36,500 Accounts Payable . . . . . . . . . . . . . . . . . . 20,817 24,574 Customer Deposits. . . . . . . . . . . . . . . . . . 3,999 3,660 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 4,937 6,130 Interest Accrued . . . . . . . . . . . . . . . . . . 8,097 6,015 Other. . . . . . . . . . . . . . . . . . . . . . . . 18,069 15,084 TOTAL CURRENT LIABILITIES. . . . . . . . . . 130,269 91,963 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 155,655 153,945 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 14,700 15,615 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 829 277 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $905,479 $886,671
See Notes to Financial Statements. KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 15,872 $ 16,724 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 20,966 19,718 Deferred Federal Income Taxes. . . . . . . . . . . . . . 1,173 163 Deferred Investment Tax Credits. . . . . . . . . . . . . (915) (924) Amortization of Deferred Property Taxes. . . . . . . . . 3,840 3,690 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (4,514) (305) Fuel, Materials and Supplies . . . . . . . . . . . . . . 1,227 (113) Accrued Utility Revenues . . . . . . . . . . . . . . . . 1,394 1,712 Accounts Payable . . . . . . . . . . . . . . . . . . . . (3,757) (9,040) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (1,193) (1,237) Payment of Disputed Taxes and Interest Related to COLI . . (5,376) - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,952 5,301 Net Cash Flows From Operating Activities . . . . . . 30,669 35,689 INVESTING ACTIVITIES - Construction Expenditures . . . . . . (30,517) (45,023) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . 10,000 10,000 Change in Short-term Debt (net). . . . . . . . . . . . . . 12,850 19,775 Retirement of Long-term Debt . . . . . . . . . . . . . . . (2,203) - Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (21,225) (20,070) Net Cash Flows From (Used For) Financing Activities. (578) 9,705 Net Increase (Decrease) in Cash and Cash Equivalents . . . . (426) 371 Cash and Cash Equivalents at Beginning of Period . . . . . . 1,381 1,106 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 955 $ 1,477 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $18,950,000 and $16,950,000 and for income taxes was $5,812,000 and $8,115,000 in 1998 and 1997, respectively. Noncash acquisitions under capital leases were $4,448,000 and $3,571,000 in 1998 and 1997, respectively.
See Notes to Financial Statements. KENTUCKY POWER COMPANY NOTES TO FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. FINANCING ACTIVITIES The Company received from its parent a cash capital contribution of $10 million in June 1998 which was credited to paid-in capital. 3. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there were no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. 4. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $70 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside its traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating loss. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $15 million for sales and approximately $10 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. 5. CONTINGENCIES Taxes As discussed in Note 8, "Federal Income Taxes" of the Notes to Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1992-96. A disallowance of COLI interest deductions through September 30, 1998 would reduce earnings by approximately $7 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998, the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1992-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Revised Air Quality Standards The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in capital expenditures of approximately $105 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in its 1997 Annual Report. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 Net income increased $4 million or 90% for the quarter and decreased $0.9 million or 5% for the year-to-date period. The increase in net income for the quarter is attributable to an increase in retail and wholesale revenues reflecting increased sales. The decline in year-to-date net income is due to increased maintenance and interest costs. The significant changes in income statement line items and net revenues were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $192.5 214 $315.3 123 Fuel Expense. . . . . . . . 1.5 7 3.3 6 Purchased Power Expense . . 180.3 N.M. 301.6 409 Net Revenues 10.7 10.4 Maintenance Expense . . . . 1.2 19 6.9 41 Depreciation and Amortization. . . . . . . 0.4 6 1.2 6 Federal Income Taxes. . . . 2.8 152 (0.2) (3) Nonoperating Loss . . . . . (0.8) N.M. (0.7) N.M. Interest Charges. . . . . . 0.9 14 2.9 16 N.M. = Not Meaningful The substantial increases in operating revenues for the third quarter and year-to-date periods were due primarily to increased sales volume. Retail revenues increased 4% in the third quarter and 2% year-to-date reflecting the impact of warmer summer weather on retail usage. Wholesale revenues increased in both periods due to growth in the power marketing and trading business which contributed substantially to an increase in wholesale sales. Fuel expense increased due to additional generation to meet the increase in demand and an increase in the cost of coal. The significant increase in purchased power expense resulted from the growth of the power marketing and trading business. Net revenues increased $10.7 million in the third quarter and $10.4 million in the year-to-date period due to increased retail sales reflecting the impact of warmer summer weather and the successful trading of wholesale energy in a volatile market. The increase in maintenance expense in both periods reflects the effects of scheduled steam plant maintenance work in 1998 at the Company's Big Sandy Plant and, for the year-to-date period, expenditures for repair and restoration of distribution service caused by two severe snowstorms. Depreciation and amortization expense increased due to additional investment in depreciable plant reflecting improvements to the transmission and distribution systems completed during 1997. The increase in federal income taxes for the third quarter resulted from an increase in pre-tax operating income. Nonoperating income declined due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger. The increase in interest charges reflects an increase in outstanding long-term debt due to the issuance of Senior Unsecured Notes in October 1997. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) OPERATING REVENUES . . . . . . . . . . . $1,361,336 $486,398 $2,901,072 $1,417,845 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 199,934 156,482 574,156 462,720 Purchased Power. . . . . . . . . . . . 824,021 37,270 1,392,404 69,738 Other Operation. . . . . . . . . . . . 96,254 78,623 260,097 240,182 Maintenance. . . . . . . . . . . . . . 34,900 39,443 98,651 102,292 Depreciation and Amortization. . . . . 36,236 35,323 108,097 105,351 Taxes Other Than Federal Income Taxes. 42,931 42,938 127,451 126,801 Federal Income Taxes . . . . . . . . . 38,222 27,203 102,444 92,022 TOTAL OPERATING EXPENSES . . . 1,272,498 417,282 2,663,300 1,199,106 OPERATING INCOME . . . . . . . . . . . . 88,838 69,116 237,772 218,739 NONOPERATING INCOME (LOSS) . . . . . . . (2,665) 2,273 2,022 9,803 INCOME BEFORE INTEREST CHARGES . . . . . 86,173 71,389 239,794 228,542 INTEREST CHARGES . . . . . . . . . . . . 20,212 20,718 60,338 61,961 NET INCOME . . . . . . . . . . . . . . . 65,961 50,671 179,456 166,581 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 369 370 1,107 2,278 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 65,592 $ 50,301 $ 178,349 $ 164,303 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $597,357 $573,236 $590,151 $584,015 NET INCOME . . . . . . . . . . . . . . . 65,961 50,671 179,456 166,581 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 52,775 37,562 158,325 161,771 Cumulative Preferred Stock . . . . . 369 370 1,108 2,829 Capital Stock Expense. . . . . . . . . - - - 21 BALANCE AT END OF PERIOD . . . . . . . . $610,174 $585,975 $610,174 $585,975 The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,636,368 $2,606,981 Transmission . . . . . . . . . . . . . . . . . . . . 841,410 837,953 Distribution . . . . . . . . . . . . . . . . . . . . 938,470 927,239 General (including mining assets). . . . . . . . . . 686,593 709,475 Construction Work in Progress. . . . . . . . . . . . 103,453 74,149 Total Electric Utility Plant . . . . . . . . 5,206,294 5,155,797 Accumulated Depreciation and Amortization. . . . . . 2,425,511 2,349,995 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,780,783 2,805,802 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 219,677 113,279 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 95,620 44,203 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 329,254 196,982 Affiliated Companies . . . . . . . . . . . . . . . 73,956 55,597 Miscellaneous. . . . . . . . . . . . . . . . . . . 20,884 43,594 Allowance for Uncollectible Accounts . . . . . . . (1,838) (2,501) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 87,763 119,543 Materials and Supplies . . . . . . . . . . . . . . . 84,433 80,853 Accrued Utility Revenues . . . . . . . . . . . . . . 43,900 37,586 Prepayments. . . . . . . . . . . . . . . . . . . . . 37,905 37,257 TOTAL CURRENT ASSETS . . . . . . . . . . . . 771,877 613,114 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 528,068 523,891 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 46,127 107,116 TOTAL. . . . . . . . . . . . . . . . . . . $4,346,532 $4,163,202
See Notes to Consolidated Financial Statements. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
September 30, December 31, 1998 1997 (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. . . . . . . . . . . . . . . . . . . 462,314 462,296 Retained Earnings. . . . . . . . . . . . . . . . . . 610,174 590,151 Total Common Shareholder's Equity. . . . . . 1,393,689 1,373,648 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 17,471 17,542 Subject to Mandatory Redemption. . . . . . . . . . 11,850 11,850 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,027,587 1,012,031 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,450,597 2,415,071 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 315,114 295,375 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 16,289 83,195 Short-term Debt. . . . . . . . . . . . . . . . . . . 98,808 78,700 Accounts Payable - General . . . . . . . . . . . . . 286,042 146,824 Accounts Payable - Affiliated Companies. . . . . . . 44,392 37,923 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 114,435 160,055 Interest Accrued . . . . . . . . . . . . . . . . . . 22,165 16,255 Obligations Under Capital Leases . . . . . . . . . . 27,994 30,307 Other. . . . . . . . . . . . . . . . . . . . . . . . 114,733 94,829 TOTAL CURRENT LIABILITIES. . . . . . . . . . 724,858 648,088 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 723,718 723,172 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 40,293 42,821 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 91,952 38,675 CONTINGENCIES (Note 5) TOTAL. . . . . . . . . . . . . . . . . . . $4,346,532 $4,163,202
See Notes to Consolidated Financial Statements. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, 1998 1997 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 179,456 $ 166,581 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . 129,366 129,597 Deferred Federal Income Taxes. . . . . . . . . . . . . . 12,504 85 Amortization of Deferred Property Taxes. . . . . . . . . 58,664 57,646 Changes in Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (128,584) (9,892) Fuel, Materials and Supplies . . . . . . . . . . . . . . 28,200 (5,112) Accrued Utility Revenues . . . . . . . . . . . . . . . . (6,314) 10,044 Accounts Payable . . . . . . . . . . . . . . . . . . . . 145,687 34,712 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (45,620) (80,111) Other Current Assets and Current Liabilities . . . . . . 22,853 31,267 Payment of Disputed Tax and Interest Related to COLI . . . (104,222) - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 68,381 (24,047) Net Cash Flows From Operating Activities . . . . . . 360,371 310,770 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (121,310) (102,469) Proceeds from Sale of Property and Other . . . . . . . . . 4,348 8,553 Net Cash Flows Used For Investing Activities . . . . (116,962) (93,916) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . 137,566 146,589 Change in Short-term Debt (net). . . . . . . . . . . . . . 20,108 53,123 Retirement of Cumulative Preferred Stock . . . . . . . . . (52) (117,601) Retirement of Long-term Debt . . . . . . . . . . . . . . . (190,181) (119,542) Dividends Paid on Common Stock . . . . . . . . . . . . . . (158,325) (161,771) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,108) (2,829) Net Cash Flows Used For Financing Activities . . . . (191,992) (202,031) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 51,417 14,823 Cash and Cash Equivalents at Beginning of Period . . . . . . 44,203 24,003 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 95,620 $ 38,826 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $52,523,000 and $54,010,000 and for income taxes was $55,898,000 and $98,341,000 in 1998 and 1997, respectively. Noncash acquisitions under capital leases were $24,740,000 and $41,677,000 in 1998 and 1997, respectively.
See Notes to Consolidated Financial Statements. OHIO POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1998 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1997 Annual Report as incorporated in and filed with the Form 10-K. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations and financial condition for interim periods. 2. FINANCING ACTIVITY In April 1998 the Company issued $140 million of 7-3/8% senior unsecured notes due 2038. During the first nine months of 1998 the Company and a subsidiary retired $183 million of long-term debt: $56 million of 6-3/4% first mortgage bonds and $17 million of 6.85% notes payable at maturity and two series of $50 million first mortgage bonds due in 2002 with interest rates of 8.10% and 8.25% and $10 million of variable rate notes payable due in 1999. As a result of the redemption of the 6-3/4% series first mortgage bonds due in 1998, the restriction on the use of retained earnings for the payment of common stock dividends was eliminated. 3. NEW ACCOUNTING STANDARDS Statement of Financial Accounting Standards (SFAS) No. 130 "Reporting Comprehensive Income" was adopted by the Company in the first quarter of 1998. SFAS No. 130 established the standards for reporting and displaying components of "comprehensive income," which is the total of net income and all transactions not included in net income affecting equity except those with shareholders. For the quarter and year-to-date periods ended September 30, 1998, there are no material differences between comprehensive income and net income. In the first quarter of 1998 the Company adopted the American Institute of Certified Public Accountants' Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." The SOP requires the capitalization and amortization of certain costs of acquiring or developing internal use computer software. Previously the Company expensed all software acquisition and development costs. The SOP must be adopted at the beginning of a fiscal year with no restatement or retroactive adjustment of prior periods. The adoption of the SOP effective January 1, 1998 did not have a material effect on results of operations, cash flows or financial condition. 4. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $290 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside the traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $65 million for sales and approximately $40 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. 5. CONTINGENCIES Taxes As discussed in Note 8, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $115 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. Revised Air Quality Standards The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by the Company of approximately $452 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. Other The Company continues to be involved in certain other matters discussed in the 1997 Annual Report. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION THIRD QUARTER 1998 vs. THIRD QUARTER 1997 AND YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997 RESULTS OF OPERATIONS Net income increased $15.3 million or 30% for the quarter and $12.9 million or 8% for the year-to-date period primarily due to increased energy sales to retail customers, reflecting warmer summer weather and increased industrial energy consumption, and growth in wholesale power marketing and trading activities. The significant changes in income statement line items and net revenues were: Increase (Decrease) Third Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . $874.9 180 $1,483.2 105 Fuel Expense. . . . . . . 43.5 28 111.4 24 Purchased Power . . . . . 786.8 N.M. 1,322.7 N.M. Net Revenues. . . . . . 44.6 49.1 Other Operation Expense . 17.6 22 19.9 8 Maintenance Expense . . . (4.5) (12) (3.6) (4) Federal Income Taxes. . . 11.0 41 10.4 11 Nonoperating Income . . . (4.9) (217) (7.8) (79) N.M. = Not Meaningful Operating revenues increased significantly in both the third quarter and year-to-date periods due predominantly to increased retail and wholesale sales. Retail sales increased 6% in the third quarter and 4% year-to-date reflecting warmer summer weather in 1998 and the resumption of operations by a major industrial customer following an extended labor strike. Operating revenues from wholesale sales increased significantly as a result of growth in power marketing and trading activities and increased sales to the AEP System Power Pool (Power Pool) to replace power previously generated at an affiliate's nuclear plant which was out of service. The increases in fuel expense for the third quarter and year-to-date periods were mainly due to an increase in generation, reflecting the rise in demand and the replacement of energy previously supplied to the Power Pool by an affiliate's out-of-service nuclear plant, and an increase in the cost of fuel consumed. Purchased power expense increased substantial for both periods primarily due to the growth of power marketing and trading activities. The increase in net revenues of $45 million in the third quarter and $49 million in the year-to-date period reflects the impact of warmer summer weather and increased industrial usage on retail sales and the successful trading of wholesale energy in a volatile market. Other operation expense increased in both periods primarily due to costs related to the increase in energy sales, employer pension and benefit expense, a reduction in gains on emission allowance sales and increased costs under the AEP System transmission equalization agreement. The transmission equalization agreement combines certain AEP System companies' investment in transmission facilities and shares the costs of ownership of those facilities in proportion to each AEP System company's peak demand relative to the peak demands of all AEP System companies utilizing the AEP System transmission system. The charges paid by the Company under the agreement increased due to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all transmission agreement members. The decreases in maintenance expense for both periods were mainly due to decreased boiler plant maintenance reflecting a reduction in planned maintenance work on the Company's generating units. Federal income taxes attributable to operations increased due to an increase in pre-tax operating income. The decrease in nonoperating income is primarily due to losses on certain power marketing and trading transactions. These transactions, which are marked-to-market and described in footnote 4, represent non-regulated trading activities outside the Company's traditional marketing area. Although losses were incurred on these non-regulated energy trades, net revenues from power marketing and trading operations within the Company's traditional marketing area were significantly larger. FINANCIAL CONDITION Total plant and property additions including capital leases for the first nine months of 1998 were $146 million. During the first nine months of 1998, the Company and a subsidiary retired $183 million principal amount of long-term debt with interest rates ranging from 6.11% to 8.25%, issued $140 million of senior unsecured notes at an interest rate of 7-3/8% and increased short-term debt by $20 million. As a result of the redemption of the 6-3/4% series first mortgage bonds due in 1998, the restriction on the use of retained earnings for the payment of common stock dividends was eliminated. REVISED AIR QUALITY STANDARDS The United States Environmental Protection Agency (Federal EPA) published in October 1997 a proposed nitrogen oxides (NOx) emissions reduction rule which called for new state implementation plans (SIPs). SIPs are a procedural method used by each state to comply with Federal EPA rules. Eight northeastern states also filed petitions in 1997 with Federal EPA claiming NOx emissions from plants in midwestern states prevent them from complying with air quality standards. On September 24, 1998, Federal EPA issued final rules which require reductions in NOx emissions in 22 eastern states, including the states in which the Company's generating plants are located. The implementation of the final rules would be achieved through the revision of SIPs by September 1999 that, by the year 2003, anticipate the imposition of a NOx reduction on utility sources of approximately 85% below 1990 emission levels. On October 30, 1998, a number of utilities, including the Company and its affiliates in the AEP System, filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the final rules. Should the states fail to adopt the required revisions to their SIPs within one year of the date of the final rules (September 24, 1999), Federal EPA has proposed to implement a federal plan to accomplish the NOx reductions. Federal EPA also proposed the approval of portions of the petitions filed by the eight northeastern states that would result in imposition of NOx emission reductions on utility and industrial sources. These reductions are substantially the same as those required by the final rules and could be adopted by Federal EPA in the event the states fail to implement SIPs in accordance with the final rules. Based on initial studies, preliminary estimates indicate that compliance costs could result in required capital expenditures by the Company of approximately $452 million. Compliance costs can not be estimated with certainty and the actual costs incurred to comply could be significantly different from the preliminary estimate depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless such costs are recovered from customers, they would have a material adverse effect on results of operations, cash flows and possibly financial condition. COMPUTER ISSUE - YEAR 2000 On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems were 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-Year 2000 ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Year 2000-related failures and repair such failures if they occur. This includes both information technology systems (IT), which are mainframe and client server applications, and embedded logic systems (non-IT), such as process controls for energy production and delivery. Externally, the problem 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 Year 2000 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, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Year 2000 readiness program. NERC then publicly reports summary information to the U.S. Department of Energy regarding the Year 2000 readiness of electric utilities. In 1999 AEP plans to participate in two NERC-sponsored coordinated electric industry Year 2000 readiness drills. The first NERC report, dated September 17, 1998 and titled Preparing the Electric Power Systems of North America for Transition to the Year 2000-A Status Report and Work Plan, states that: "Mission critical systems and components are to be made Y2K Ready by June 30, 1999." In addition, the report indicates that: "While many organizations are on track to meet these targets, many others need to accelerate project plans and resources." In response to the report, the Company has accelerated its Year 2000 readiness date for mission critical and high priority systems and components from September 30 to June 30, 1999. Through the Electric Power Research Institute, an electric industry-wide effort has been established to deal with Year 2000 problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. Various state commissions are also reviewing the Year 2000 readiness of electric utilities subject to their jurisdiction. 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, communications, and the physical generation and delivery of energy; 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 our progress toward becoming ready for the Year 2000 as of September 30, 1998: 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% 11/30/1998 86% 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 2% replacing or retiring 60% those mission critical and high priority digital-based Client systems with problems Server: processing dates past the 1% Year 2000. Testing these 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 September 30, 1998, the Company has spent $5 million on the Year 2000 project and, estimates spending an additional $12 million to $16 million to achieve Year 2000 readiness. Most Year 2000 costs are software- and salary-related and are expensed; however, in certain cases the Company has acquired hardware that is capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Year 2000 ready is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Year 2000 Issues - The applications posing the greatest business risk to the Company's operations should they experience Year 2000 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. In addition, although as discussed 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, Year 2000-related issues may materially adversely affect AEP. Company's Contingency Plans - The Company intends to establish contingency plans on a case-by-case basis to address alternatives if Year 2000 failures of automatic systems and equipment occur as part of its Year 2000 readiness program. The contingency plans will be based upon a risk analysis process and will be developed by the fourth quarter of 1999. These plans will build upon disaster recovery, system restoration, and contingency planning that we now have in place. We have begun the contingency planning process, including the review of NERC's contingency planning and preparations guide. The Company plans to submit a draft of its contingency plans to NERC as part of NERC's review of drafts of regional and individual electric utility contingency plans in 1999. Forward-Looking Statements - This description of Year 2000 problems, the consequences of Year 2000 failures and the estimated costs of, and timetable for, becoming Year 2000 ready constitute "forward looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Such statements are based on management's beliefs as well as assumptions made by, and information currently available to, management. Investors are cautioned that such statements and estimates could differ materially from actual results because of factors referred to specifically in connection with such forward-looking statements and, in addition, the following other factors, among others: * Continuing availability of experienced consultants and IT personnel and related resources * Ability of third parties to complete their Year 2000 remediations on a timely basis and accuracy of representations made by such third parties concerning their Year 2000 readiness * Ability of the Company to identify and implement contingency plans. TAXES As discussed in Note 8, "Federal Income Taxes" of the Notes to Consolidated Financial Statements in the 1997 Annual Report, the Internal Revenue Service (IRS) agents auditing the AEP System's consolidated federal income tax returns requested a ruling from their National Office that certain interest deductions relating to corporate owned life insurance (COLI) claimed by the Company should not be allowed. As a result of a suit filed in United States District Court (discussed below) this request for ruling has been withdrawn. Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions for taxable years 1991-96. A disallowance of the COLI interest deduction through September 30, 1998 would reduce earnings by approximately $115 million (including interest). The Company has made no provision for any possible adverse earnings impact from this matter. In order to resolve this issue without further delay, on March 24, 1998, the Company filed suit against the United States in the United States District Court for the Southern District of Ohio. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In July 1998 the Company made a payment of taxes and interest attributable to COLI interest deductions for taxable years 1991-96 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. In September 1998 the Company made an additional payment for the 1997 tax year. The payments were included on the balance sheet in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations and cash flows. POWER MARKETING AND TRADING During 1998, American Electric Power Service Corporation, as agent for the Company and its affiliates in the AEP System Power Pool (Power Pool), substantially increased the volume of its electricity marketing and trading. The purpose of the power marketing and trading business is to utilize AEP's knowledge of the energy markets in order to improve the competitiveness of its generation business and contribute to net income. Revenues and expenses from these activities are shared by the Power Pool members based on their relative peak demands. The power marketing and trading business involves the marketing of power under physical forward contracts at fixed and variable prices and the trading of options, futures, swaps and other financial derivative contracts at both fixed and variable prices. Most contracts represent physical forward electricity marketing contracts for the purchase and sale of electricity in the Power Pool's traditional marketing area which are recorded as operating revenues and purchased power expense when the contracts settle. At September 30, 1998, the Power Pool had open marketing contracts, not on the balance sheet, in its traditional marketing area through the year 2004 to sell electricity with a notional value of approximately $1.1 billion and to purchase electricity with a notional value of approximately $1.1 billion. The Company's share of these notional values is approximately $290 million. The Power Pool has also purchased and sold electricity options, futures, and swaps, and entered into forward purchase and sale contracts for the future delivery or receipt of electricity outside the traditional marketing area. These transactions represent non-regulated trading activities that are marked-to-market and recorded in nonoperating income. At September 30, 1998, the Company's share of the unrealized mark-to-market gains and losses from such trading contracts are reported as assets and liabilities, respectively. At September 30, 1998, the Power Pool had open marketing contracts outside its traditional marketing area through the year 2008 to sell electricity with a notional value of approximately $230 million and to purchase electricity with a notional value of approximately $145 million. The Company's share of these notional values is approximately $65 million for sales and approximately $40 million for purchases. Dependent on future electricity market conditions these activities could produce material income or losses in future periods. PART II. OTHER INFORMATION Item 5. Other Information. American Electric Power Company, Inc. ("AEP") The deadline for submission of shareholder proposals pursuant to Rule 14a-8 under the Securities Exchange Act of 1934, as amended, ("Rule 14a-8"), for inclusion in AEP's proxy statement for its 1999 Annual Meeting of Shareholders was November 10, 1998. After February 1, 1999, notice to AEP of a shareholder proposal submitted otherwise than pursuant to Rule 14a-8 will be considered untimely, and the persons named in proxies solicited by AEP's Board of Directors for its 1999 Annual Meeting of Shareholders may exercise discretionary voting power with respect to any such proposal as to which AEP does not receive timely notice. AEP and Appalachian Power Company ("APCo") Reference is made to page 10 of the Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K") and page II-1 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, for a discussion of retail competition in Virginia. Pursuant to an order of the Virginia State Corporation Commission ("Virginia SCC"), APCo filed its Customer Choice Pilot Program with the Virginia SCC on November 2, 1998. The Virginia SCC must approve the program before it becomes effective. The proposed two-year program would give approximately 3,200 APCo retail customers in Virginia--residential, commercial and industrial--an opportunity to choose an Energy Service Provider ("ESP") of generation service other than APCo. ESPs include marketers, brokers and aggregators who provide generation service at unregulated prices. If a participating customer were to pick an ESP for generation service, APCo would continue to provide distribution and transmission service. Participation would be open to 2% or 50 megawatts of APCo's Virginia load. Reference is made to pages 12 and 13 of the 1997 10-K and page II-3 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, for a discussion of APCo's proposed transmission facilities. By Hearing Examiner's Ruling of June 9, 1998, the procedural schedule for the certificate in Virginia was suspended for 90 days to allow APCo to conduct additional studies. On August 21, 1998, APCo filed a report stating that a two-phased alternative project could provide electrical transmission reinforcement comparable to the Wyoming-Cloverdale line. II-1 By Hearing Examiner's Ruling of September 22, 1998, the proceeding was continued and APCo was directed to study the first phase of the alternative project, involving a line running from Wyoming Station in West Virginia to APCo's existing Jacksons Ferry Station in Virginia or any point on the Jacksons Ferry-Cloverdale 765kV transmission line. APCo estimates that the Wyoming-Jacksons Ferry line would be between 82-100 miles in length, including 32 miles in West Virginia previously certified. APCo must file its study by June 1, 1999. The Hearing Examiner also ordered APCo and the Virginia SCC Staff to provide at the evidentiary hearing information on generation alternatives, specifically natural gas generation, to APCo's proposed transmission line. Management estimates that the earliest APCo could complete either the Wyoming-Cloverdale or Wyoming-Jacksons Ferry project is the winter of 2003/2004. AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern Power Company ("CSPCo"), Indiana Michigan Power Company ("I&M"), Kentucky Power Company ("KEPCo") and Ohio Power Company ("OPCo") Reference is made to page 22 of the 1997 10-K for a discussion of proposed revisions to the new source performance standard for nitrogen oxides emissions from new utility and large industrial boilers. On September 3, 1998, the U.S. Environmental Protection Agency issued final revisions to this standard. The revised rule specifies the emission limit for new sources in terms of output rather than emission rate. The emission limit is set at a level which cannot currently be achieved by combustion controls and will require the use of post combustion control equipment. Imposition of this standard to existing sources which might become subject to the rule based on an administrative finding that an existing source had been modified or reconstructed could result in substantial capital and operating expenditures. AEP and OPCo Reference is made to page 31 of the 1997 10-K for a discussion of litigation with Ormet Corporation involving the ownership of sulfur dioxide allowances. In a letter dated August 27, 1998, the U.S. District Court, Northern District of West Virginia, advised the parties to the litigation that the court would issue an order granting the motion for summary judgment filed by OPCo and the AEP Service Corporation. II-2 Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo and OPCo Exhibit 10 - AEP System Survivor Benefit Plan, effective January 27, 1998. APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 12 - Statement re: Computation of Ratios. AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 27 - Financial Data Schedule. (b) Reports on Form 8-K: AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo No reports on Form 8-K were filed during the quarter ended September 30, 1998. II-3 Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/ Armando A. Pena By: /s/ Leonard V. Assante Armando A. Pena Leonard V. Assante Treasurer Controller and Chief Accounting Officer (Duly Authorized Officer) (Chief Accounting Officer) AEP GENERATING COMPANY APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY By: /s/ Armando A. Pena By: /s/ Leonard V. Assante Armando A. Pena Leonard V. Assante Vice President, Treasurer, Controller and and Chief Financial Officer Chief Accounting Officer (Duly Authorized Officer) (Chief Accounting Officer) Date: November 12, 1998 II-4 EX-10 2 EXHIBIT 10 - AEP System Survivor Benefit Plan, effective January 27,1998. EXHIBIT 10 AEP SYSTEM SURVIVOR BENEFIT PLAN JANUARY 27, 1998 TABLE OF CONTENTS PAGE ARTICLE I-PURPOSE 1 1.1 Purpose 1 1.2 Effective Date 1 ARTICLE II-DEFINITIONS 1 2.1 Alternative Term Rate 1 2.2 Base Coverage 1 2.3 Board 1 2.4 Cash Value 1 2.5 Committee 1 2.6 Compensation 2 2.7 Date of Participation 2 2.8 Employer 2 2.9 Employer's Premium 2 2.10 Endow 2 2.11 Enhanced Postretirement Benefit 2 2.12 Entry Date 3 2.13 Insurer 3 2.14 Participant 3 2.15 Participant's Cash Value 3 2.16 Participant's Share of Premium 3 2.17 Plan 3 2.18 Plan Benefit 4 2.19 Policy 4 2.20 Retirement 4 2.21 Standard Postretirement Benefit 4 2.22 Supplemental Coverage 4 2.23 Totally and Permanently Disabled 5 ARTICLE III-PARTICIPATION 5 3.1 Eligibility 5 3.2 Participation 5 ARTICLE IV-POLICY OWNERSHIP 5 4.1 Policy Ownership 5 4.2 Accelerated Living Benefit Limitation 6 4.3 Employer's Security Interest 6 ARTICLE V-PREMIUM PAYMENT 6 5.1 Premium Payment 6 5.2 Payment of Participant's Share 6 ARTICLE VI-EMPLOYER'S INTEREST IN THE POLICY 6 6.1 Collateral Assignment 6 6.2 Limitations 6 ARTICLE VII-PARTICIPANT'S INTEREST IN THE POLICY 7 7.1 Cash Surrender Value 7 7.2 Plan Benefit 7 7.3 Insurance Proceeds 7 ARTICLE VIII-TERMINATION, RETIREMENT, DISABILITY 7 8.1 Termination of Employment Prior to Retirement 7 8.2 Termination of Employment Due to Retirement 7 ARTICLE IX-AMENDMENT AND TERMINATION OF PLAN 8 9.1 Amendment 8 9.2 Termination 8 ARTICLE X-INSURER NOT A PARTY TO PLAN 9 ARTICLE XI-NAMED FIDUCIARY 9 11.1 Named Fiduciary 9 11.2 Indemnification 9 ARTICLE XII-CLAIMS PROCEDURE 9 12.1 Claims 9 12.2 Review of Claim 9 12.3 Notice of Denial of Claim 10 12.4 Reconsideration of Denied Claim 10 12.5 Employer to Supply Information 10 ARTICLE XIII-MISCELLANEOUS 11 13.1 Not a Contract of Employment 11 13.2 Protective Provisions 11 13.3 Transfer of Participant's Interest in the Policy 11 13.4 Terms 11 13.5 Governing Law 11 13.6 Validity 11 13.7 Notice 11 13.8 Successors 12 EXHIBIT A Collateral Assignment AEP SYSTEM SURVIVOR BENEFIT PLAN ARTICLE I-PURPOSE 1.1 Purpose This Plan has been established to provide certain key employees of American Electric Power Service Corporation, its affiliates and subsidiaries with life insurance pro- tection. The Plan will provide life insurance benefits to the beneficiaries of the participating employees under a split-dollar life insurance arrangement. 1.2 Effective Date This Plan will be effective as of January 27, 1998. ARTICLE II-DEFINITIONS Whenever used in this Plan, the following terms shall have the meanings set forth in this Article unless a con- trary or different meaning is expressly provided: 2.1 Alternative Term Rate "Alternative Term Rate" shall equal the lower of the PS 58 rate or the Insurer's current published premium rate for annually renewable term insurance for standard risk. 2.2 Base Coverage "Base Coverage" shall equal one (1) times the Par- ticipant's Compensation, rounded to the nearest thousand. 2.3 Board "Board" shall mean the Board of Directors of American Electric Power Service Corporation, a New York corpora- tion. 2.4 Cash Value "Cash Value" shall mean the cash value of the Policy, as that term is defined in the Policy. 2.5 Committee "Committee" shall mean the AEP Employee Benefits Trust Committee appointed to administer the Plan pursuant to Article XI. 2.6 Compensation "Compensation" shall mean the base annual salary rate payable to the Participant as of January 1 and considered to be "wages" for purposes of federal income tax withhold- ing before reduction for amounts deferred under any elec- tive salary reduction program (regardless of whether such program is "qualified" or "nonqualified" under the Inter- nal Revenue Code of 1986, as amended). "Compensation" does not include long-term incentive compensation, bonuses, cash awards, expense reimbursement, reimbursements for premium or taxes under this Plan, any form of noncash com- pensation, or benefits. 2.7 Date of Participation "Date of Participation" shall mean the date on which the Policy is issued. 2.8 Employer "Employer" shall mean American Electric Power Service Corporation, a New York corporation, and any affiliate or subsidiary of American Electric Power Service Corporation participating in this Plan. 2.9 Employer's Premium "Employer's Premium" shall mean the aggregate amount of insurance premium paid by the Employer, less the Par- ticipant's Share of Premium. 2.10 Endow "Endow" shall mean that when using the interest cred- iting rate and mortality charges, in effect at the time of testing, the Policy is projected to have a cash value equal to the Plan Benefit at age ninety-five (95), assum- ing no additional premium payments after the Employer re- leases its interest in the Policy. 2.11 Enhanced Postretirement Benefit "Enhanced Postretirement Benefit" shall mean that, for Participants who elect such benefit, it shall be one hundred percent (100%) of the Postretirement Benefit through age seventy-five (75). On each anniversary of the policy following age seventy-five (75), the Participant's benefit shall be adjusted as follows: Age Benefit Level as a Percent of Preretirement Benefit 65-75 100% 76 95 77 90 78 85 79 80 80 75 81 70 82 65 83 60 84 55 85 and Thereafter 50 2.12 Entry Date "Entry Date" shall mean the first (1st) of the month following the date in which the employee becomes eligible to participate in the Plan pursuant to Section 3.1. 2.13 Insurer The "Insurer" with respect to any Policy maintained under the Plan shall mean the insurance company issuing such Policy. 2.14 Owner "Owner" shall mean the Participant or the Partici- pant's transferee, as specified in Section 13.3, who has the ownership rights in the Policy. 2.15 Participant "Participant" shall mean a key employee of the Em- ployer who is at least salary grade 30, or a key employee approved for participation by the Chief Executive Officer of the Employer, and has completed all documentation re- quired under Section 3.2. 2.16 Participant's Cash Value "Participant's Cash Value" shall mean the portion of the Cash Value that exceeds Employer's Premium. 2.17 Participant's Share of Premium "Participant's Share of Premium" shall mean the ag- gregate portion of premiums required to be contributed by the Owner. This amount shall be based on the Postretire- ment Benefit elected by the Owner. (a) If the Participant elects the Standard Postre- tirement Benefit, the Participant's Share of Premium shall be an amount equal to the sum of the Base Cov- erage times the Alternative Term Rate, plus the Sup- plemental Coverage (if any), times two (2) times the Alternative Term Rate. This amount shall be payable by the Participant regardless of the actual amount (if any) of premiums paid by the Employer with re- spect to the Policy in any particular year. (b) If a Participant elects the Enhanced Postre- tirement Benefit, the Participant's Share of Premium shall equal the sum of the Base Coverage times one and one-half (1.5) times the Alternative Term Rate, plus the Supplemental Coverage (if any), times two and one-half (2.5) times the Alternative Term Rate. However, any Participant who enters the Plan after February 1, 1998 shall only pay one (1) times the Alterna- tive Term Rate on the amount of coverage elected for the period from the Participant's Entry date until the Par- ticipant's Date of Participation; thereafter the above schedule shall apply. 2.18 Plan "Plan" shall mean the AEP System Survivor Benefit Plan. 2.19 Plan Benefit "Plan Benefit" shall mean insurance proceeds payable to the Participant's Beneficiary equal to the following: (a) Preretirement. The preretirement benefit shall equal the Base Coverage plus any Supplemental Coverage elected by the Participant. The preretire- ment Plan Benefit shall be adjusted annually in Feb- ruary based on the Participant's annual Compensation rate on January 1 of the current calendar year. (b) Postretirement. The insurance proceeds pay- able to the Participant's Beneficiaries shall be one hundred percent (100%) of the preretirement benefit through age sixty-five (65). On the anniversary of the policy following the Participant's birthday, the benefit shall be adjusted based upon the Standard or Enhanced Postretirement Benefit elected by the Par- ticipant. 2.20 Policy "Policy" shall mean, with respect to each Partici- pant, all life insurance policies which are maintained un- der the Plan on the life of such Participant. 2.21 Retirement "Retirement" shall mean termination of employment with the Employer on or after age fifty-five (55) and five (5) Years of Service. 2.22 Standard Postretirement Benefit "Standard Postretirement Benefit" shall mean that, for Participants who elected such benefit and retired, on the anniversary of the policy following the Participant's birthday, the Postretirement Benefit shall be as follows: Age Benefit Level as a Percent of Preretirement Benefit 66 90% 67 80 68 70 69 60 70 and Thereafter 50 2.23 Supplemental Coverage "Supplemental Coverage" shall be coverage in addition to the Base Coverage elected by the Participant which shall be equal to one (1) or two (2) times the Partici- pant's Base Coverage. 2.24 Totally and Permanently Disabled "Totally and Permanently Disabled" shall mean that the Participant, due to sickness or injury, is not engaged in the Participant's or any other gainful occupation and will continue to be unable to engage in any gainful occu- pation for which the Participant is, or may reasonably be- come, fitted by education, training, or experience. ARTICLE III-PARTICIPATION 3.1 Eligibility All employees of the Employer who are in or enter salary grade 30 or higher shall be eligible to partici- pate. Such other employees of the Employer who are ap- proved for participation by the Chief Executive Officer of the Employer shall also be eligible to participate. 3.2 Participation In order to participate in the Plan, a designated em- ployee must complete and execute such documents and agree- ments as are prescribed by the Committee for use in carry- ing out the terms and provisions of the Plan. An employee who becomes eligible for the Plan after February 1, 1998, shall not be a Participant until the first (1st) of the month following the date in which the employee became eli- gible under Section 3.1. If an eligible employee fails to complete the necessary documents and agreements within thirty (30) days after receipt, such employee shall not be a Participant in this Plan. ARTICLE IV-POLICY OWNERSHIP 4.1 Policy Ownership The Owner of the Policy may exercise all ownership rights granted to the Owner by the terms of the Policy, subject to the rights of the Employer as herein provided. The Owner's rights shall include, but are not limited to, the right to assign the Owner's interest in the Policy (subject to the rights of the Employer in the Policy), the right to change the beneficiary of that portion of the proceeds to which the Owner is entitled under Article VII, and the right to exercise settlement options with respect to that portion. Prior to the release of the Employer's Security Interest, the Owner shall not borrow against, surrender, or cancel the Policy nor terminate the Policy dividend election without the express written consent of the Employer. 4.2 Accelerated Living Benefit Limitation Subject to all of the provisions of the Policy, if a Participant becomes terminally ill and has a life expec- tancy of twelve (12) months or less, the Owner of the pol- icy may request a portion of the Plan Benefit while the Participant is living. The amount the Owner receives shall be limited to the lesser of five hundred thousand dollars ($500,000) or fifty percent (50%) of the Plan Benefit. 4.3 Employer's Security Interest The Employer shall have a security interest as de- fined in the Form of Collateral Assignment attached hereto as Exhibit A and as hereinafter provided under Article VI in a portion of the death benefit and Cash Value of the Policy equal to the Employer's Premium. ARTICLE V-PREMIUM PAYMENT 5.1 Premium Payment Each premium on the Policy shall be paid by the Em- ployer as it becomes due. 5.2 Payment of Participant's Share Annually, the Employer shall notify the Participant of the Participant's Share of Premium. The Employer may: (1) deduct such amount from the Participant's Compensa- tion; (2) deduct such amount from the Participant's pay- ments from the American Electric Power System Retirement Plan, if applicable; or invoice the Owner annually for the amount of each premium payment until the Employer releases all interest in the policy. If the Participant becomes To- tally and Permanently Disabled before Retirement, the pay- ment of the Participant's Share of Premium shall be waived by the Employer. ARTICLE VI-EMPLOYER'S INTEREST IN THE POLICY 6.1 Collateral Assignment Each Owner shall assign the Policy to the Employer as collateral under the Form of Collateral Assignment at- tached hereto as Exhibit A. Such assignment shall give the Employer the limited power to enforce its right to recover the Employer's Premium from the Cash Value or from the death benefit of the policy. The collateral assignment of the Policy to the Employer shall not be terminated, al- tered, or amended by the Owner without the express written consent of the Employer. The Employer and each Owner will take all action necessary to cause the collateral assign- ment to conform to the provisions of this Plan. 6.2 Limitations The interest of the Employer in and to the Policy shall be specifically limited to the following rights in and to the Cash Value and a portion of the death benefit: (a) The right to recover Cash Value equal to the Employer's Premium in the event the Policy is surren- dered or canceled prior to the Participant's Retire- ment; (b) Upon the death of the Participant prior to the release of the Collateral Assignment, the right to recover all of the Policy proceeds in excess of the Plan Benefit under Section 7.2; (c) The right to withdraw from the Policy the Em- ployer's Premium in the event of termination of em- ployment by the Participant prior to Retirement for reasons other than death or Disability; and (d) The right to withdraw from the Policy the Em- ployer's Premium at or after retirement as set out in Section 8.2. ARTICLE VII-PARTICIPANT'S INTEREST IN THE POLICY 7.1 Cash Surrender Value Notwithstanding any other provision in the Plan to the contrary, the Owner shall at all times own that por- tion of the Cash Value which exceeds the Employer's Pre- mium. In the event of the Participant's termination of em- ployment prior to Retirement or the Employer's termination of the Plan, the Employer shall withdraw from the Policy Cash Value an amount equal to the Employer's Premium and then release the Collateral Assignment. 7.2 Plan Benefit Upon the death of the Participant, the beneficiary or beneficiaries designated by the Participant shall be enti- tled to receive the Plan Benefit. 7.3 Insurance Proceeds The Employer shall promptly take all action and exe- cute all documents necessary to facilitate the payment of the Plan Benefit. ARTICLE VIII-TERMINATION, RETIREMENT, DISABILITY 8.1 Termination of Employment Prior to Retirement In the event of the Participant's termination of em- ployment prior to Retirement for reasons other than death or Disability, the Employer shall withdraw from the Policy Cash Value an amount equal to the Employer's Premium and then release the Collateral Assignment. 8.2 Termination of Employment Due to Retirement In the event of the Participant's termination of em- ployment with the Employer due to Retirement, the Employer shall do the following: (a) If the Participant's termination date occurs prior to the fifteenth (15th) anniversary of the Par- ticipant's Date of Participation, the Employer and Participant shall continue to pay any premiums due through the fifteenth (15th) anniversary of the Par- ticipant's Date of Participation. After the fifteenth (15th) anniversary, the Employer shall immediately withdraw from the Policy Cash Value an amount equal to the Employer's Premium and release its interest in the Policy and in the collateral assignment. Upon re- lease of the collateral assignment, the Employer shall have no further obligation to pay future Policy premiums and the Employer shall have no further in- terest in the Policy. (b) If the Participant's termination date occurs after the fifteenth (15th) anniversary of the Par- ticipant's Date of Participation, then the Employer shall immediately withdraw from the Policy Cash Value an amount equal to the Employer's Premium and release its interest in the Policy and in the collateral as- signment. Upon release of the collateral assignment, the Employer shall have no further obligation to pay future Policy Premiums and the Employer shall have no further interest in the Policy. (c) It is the intent of this Plan that retired Participants be provided the Plan Benefit from the Policy as set out in Section 2.18. Before such Policy is released in (a) or (b) above, the Policy shall be tested to ensure Cash Value will Endow the Policy at age ninety-five (95). If the Participant's Cash Value is insufficient to Endow the Policy, then Employer shall either leave a portion of the Employer's Pre- mium Value in the contract so that the total Cash Value left in the Policy at release is sufficient to Endow the Policy, or the Employer shall pay addi- tional premiums until such point as there is suffi- cient Participant Cash Value to Endow the Policy. The action taken above shall be mutually agreed upon by the Owner and Employer, and there shall be no re- quired additional premium payments by the Owner to the Employer. ARTICLE IX-AMENDMENT AND TERMINATION OF PLAN 9.1 Amendment The Employer may amend this Plan from time to time as may be necessary for administrative purposes and legal compliance. The power to amend the Plan pursuant to this Section 9.1 shall include, but not be limited to, the power to increase or decrease the Plan Benefit as defined under the Plan. However, no such amendment shall reduce the amount of benefit payable with respect to a Partici- pant who is eligible to retire or who has retired. 9.2 Termination The Employer may, at any time, in its sole discre- tion, terminate the Plan, in whole or in part. Upon termi- nation, in whole or in part, the Employer shall withdraw from the Policy Cash Value an amount equal to the Em- ployer's Premium and then release the Collateral Assign- ment. However, such termination shall not apply to a Par- ticipant who has retired or who is eligible for Retirement before the effective date of termination of the Plan. Pre- miums on the Policy on such Participant shall continue to be paid, and said Policy shall be transferred to such Par- ticipant as provided in Section 8.2. ARTICLE X-INSURER NOT A PARTY TO PLAN The Insurer shall be bound only by the provisions of the Policy, any endorsements on the Policy and the collat- eral assignment. Any payments made or action taken by an Insurer in accordance therewith shall fully discharge it from all claims, suits, and demands of all persons whatso- ever. Except as specifically provided by endorsement on the Policy, it shall in no way be bound by the provisions of this Plan. ARTICLE XI-NAMED FIDUCIARY 11.1 Named Fiduciary The Committee is hereby designated as the "Named Fi- duciary." As the Named Fiduciary, the Committee shall have the authority to make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and decide or resolve any and all questions, including interpretations of the Plan, as may arise in such administration. The Committee may allocate to others certain aspects of the management and operation responsi- bilities of the Plan, including the employment of advisors and the delegation of any ministerial duties to qualified individuals. 11.2 Indemnification The Employer shall indemnify and hold harmless the Committee and its individual members from and against any and all claims, loss, damage, expense, or liability aris- ing from any action or failure to act with respect to this Plan, except in the case of gross negligence or willful misconduct. ARTICLE XII-CLAIMS PROCEDURE 12.1 Claims The Committee shall establish rules and procedures to be followed by Participants and their beneficiaries: (a) In filing claims for benefits; and (b) For furnishing and verifying proofs necessary to establish the right to benefits in accordance with the Plan, consistent with the remainder of this Arti- cle. Such rules and procedures shall require that claims and proofs be made in writing and directed to the Commit- tee. 12.2 Review of Claim The Committee shall review all claims for benefits. Upon receipt by the Committee of such a claim, it shall determine all facts which are necessary to establish the right of the claimant to benefits under the provisions of the Plan and the amount thereof as herein provided within ninety (90) days of receipt of such claim. If prior to the expiration of the initial ninety (90) day period the Com- mittee determines additional time is needed to come to a determination on the claim, the Committee shall provide written notice to the Participant, the beneficiary or beneficiaries, or other claimant of the need for the ex- tension, not to exceed a total of one hundred eighty (180) days from the date the application was received. 12.3 Notice of Denial of Claim In the event that any Participant, beneficiary, or other claimant claims to be entitled to a benefit under the Plan, and the Committee determines that such claim should be denied in whole or in part, the Committee shall notify such claimant in writing that his or her claim has been denied, in whole or in part, setting forth the spe- cific reasons for such denial. Such notification shall be written in a manner reasonably expected to be understood by such claimant and shall refer to the specific Sections of the Plan relied on, shall describe any additional mate- rial or information necessary for the claimant to perfect the claim and an explanation of why such material or in- formation is necessary, and where appropriate, shall in- clude an explanation of how the claimant can obtain recon- sideration of such denial. 12.4 Reconsideration of Denied Claim (a) Within sixty (60) days after receipt of notice of the denial of a claim, such claimant or his duly- authorized representative may request, by mailing or delivery of such written notice to the Committee, a reconsideration by the Committee of the decision de- nying the claim. If the claimant or his duly- authorized representative fails to request such a re- consideration within such sixty (60) day period, it shall be conclusively determined for all purposes of this Plan that the denial of such claim by the Com- mittee is correct. If such claimant or his duly- authorized representative requests a reconsideration within such sixty (60) day period, the claimant or his duly-authorized representative shall have thirty (30) days after filing a request for reconsideration to submit additional written material in support of the claim, review pertinent documents, and submit is- sues and comments in writing. (b) After such reconsideration request, the Com- mittee shall determine within sixty (60) days of re- ceipt of the claimant's request for reconsideration whether such denial of the claim was correct and shall notify such claimant in writing of its determi- nation. The written notice of decision shall include specific reasons for the decision, written in a man- ner calculated to be understood by the claimant, as well as specific references to the pertinent Plan provisions on which the decision is based. In the event of special circumstances determined by the Com- mittee, the time for the Committee to make a decision may be extended for an additional sixty (60) days upon written notice to the claimant prior to com- mencement of the extension. If such determination is favorable to the claimant, it shall be binding and conclusive. If such determination is adverse to such claimant, it shall be binding and conclusive unless the claimant or his duly-authorized representative notifies the Committee within ninety (90) days after the mailing or delivery to the claimant by the Com- mittee of its determination that the claimant intends to institute legal proceedings challenging the deter- mination of the Committee and actually institutes such legal proceedings within one hundred eighty (180) days after such mailing or delivery. 12.5 Employer to Supply Information To enable the Committee to perform its functions, the Employer shall supply full and timely information to the Committee of all matters relating to the employment, Re- tirement, death, or other cause for termination of employ- ment of all Participants and such other pertinent facts as the Committee may require. ARTICLE XIII-MISCELLANEOUS 13.1 Not a Contract of Employment The terms and conditions of the Plan shall not be deemed to constitute a contract of employment between the Employer and the Participant, and neither the Participant nor the Participant's beneficiary or beneficiaries shall have any rights against the Employer except as may other- wise be specifically provided herein. Moreover, nothing in this Plan shall be deemed to give a Participant the right to be retained in the service of the Employer or to inter- fere with the right of the Employer to discipline or dis- charge him at any time. 13.2 Protective Provisions The Participant will cooperate with the Employer by furnishing any and all information requested by the Em- ployer in order to facilitate the payment of benefits hereunder, by taking such physical examinations as the In- surer may require, and by taking such other reasonable ac- tion as may be requested by the Employer. 13.3 Transfer of Participant's Interest in the Policy In the event the Participant shall transfer all of his interest in the Policy, then all of the Participant's interest in the Policy shall be vested in his transferee, who shall be substituted as a party hereunder, and the Participant shall have no further interest in the Policy. 13.4 Terms In this Plan, unless the context clearly indicates to the contrary, the references to the masculine gender will be deemed to include the feminine gender, and the singular shall include the plural. 13.5 Governing Law The provisions of this Plan shall be construed and interpreted according to the laws of the State of Ohio, except as preempted by federal law. 13.6 Validity In case any provision of this Plan shall be held il- legal or invalid for any reason, such illegality or inva- lidity shall not affect the remaining parts hereof, but this Plan shall be construed and enforced as if such ille- gal and invalid provision had never been inserted herein. 13.7 Notice Any notice or filing required or permitted to be given to the Employer under this Plan shall be sufficient if in writing and hand delivered or sent by registered or certified mail to the Committee. Such notice, if mailed, shall be addressed to the principal offices of the Em- ployer, Attention, Director-Employee Benefits, System Hu- man Resources. Notices mailed to the Participant shall be at such address as is given in the records of the Em- ployer. Notices shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. 13.8 Successors The provisions of this Plan shall bind and inure to the benefit of the Employer and its successors and as- signs. The term "successors" as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase, or otherwise, acquire all or substantially all of the business and as- sets of the Employer and successors of any such corpora- tion or other business entity. IN WITNESS WHEREOF, the Employer has caused this Plan to be executed by its officer thereunto duly authorized as of the 27th day of January, 1998. AMERICAN ELECTRIC POWER SERVICE CORPORATION By: /s/ Armando A. Pena Title: Senior Vice President - Finance, Treasurer and Chief Financial Officer AEP SYSTEM SURVIVOR BENEFIT PLAN EXHIBIT A Collateral Assignment THIS ASSIGNMENT, made and entered into this _________ day of _____________, 19_____, by the undersigned as owner (the "Owner") of that certain Life Insurance Policy No. _____________ issued by Pacific Life Insurance Company, Newport Beach, California ("Insurer") and any supplemen- tary contracts issued in connection therewith (said policy and contract being herein called the "Policy"), upon the life of ______________________________ ("Insured"), to American Electric Power Service Corporation, a New York corporation (the "Company") and any participating affili- ate or subsidiary of the Company ("Assignee"). WITNESSETH: WHEREAS, the Insured is an employee of the Company; and WHEREAS, said Assignee desires to assist the Insured by paying a portion of the annual premium due on the Pol- icy, as more specifically provided for in that certain AEP System Survivor Benefit Plan dated January 1, 1998, adopted by the Company (the "Plan"); and WHEREAS, in consideration of the Assignee agreeing to pay such premiums, the Owner agrees to grant the Assignee a security interest in said Policy as a collateral secu- rity for the repayment of that portion of the premiums paid by the Assignee. NOW, THEREFORE, for value received, the undersigned hereby assigns, transfers and sets over to the Assignee, its successors and assigns, the following specific rights in the Policy and subject to the following terms and con- ditions: 1. This Assignment is made, and the Policy is to be held, as collateral security for all liabilities of the Owner to the Assignee, either now existing or that may hereafter arise, pursuant to the terms of the Plan. 2. The Assignee's interest in the Policy shall fur- ther be limited to: (a) The right to recover from the Policy Cash Value the Employer's Premium in the event the Policy is surrendered or canceled, prior to the Insured's Retirement, as provided in the Plan; (b) The right to recover, upon the death of the Insured, all of the Policy proceeds in excess of those payable to the Participant's beneficiary or beneficiaries, as provided under the Plan, reduced by any indebtedness against the Policy; and (c) The right to withdraw from the Policy Cash Value equal to the Employer's Premium in the event of termination of the Insured's employment prior to Re- tirement for reasons other than death or Disability; and AEP SYSTEM SURVIVOR BENEFIT PLAN EXHIBIT A Collateral Assignment (d) The right to withdraw from the Policy Cash Value equal to the Employer's Premium at or after Re- tirement as provided in Article VIII of the Plan Document. (e) The right to withdraw from the Policy Cash Value equal to the Employer's Premium in the event the Plan is terminated by the Board prior to the In- sured's Retirement. 3. Except as specifically herein granted to the As- signee, the Owner shall retain all incidents of ownership in the Policy, including the right to assign his interest in the Policy, the right to change the beneficiary of that portion of the proceeds to which he is entitled under Ar- ticle VII of the Plan, and the right to exercise all set- tlement options permitted by the terms of the Policy; pro- vided, however, that all rights retained by Owner shall be subject to the terms and conditions of the Plan. 4. The Assignee shall, upon request, forward the Pol- icy to the Insurer, without reasonable delay, for endorse- ment of any designation or change of beneficiary, any election of optional mode of settlement, or the exercise of any other right reserved by the Owner hereunder. 5. The Insurer is hereby authorized to recognize the Assignee's claims to rights hereunder without investigat- ing the reason for any action taken by the Assignee, the validity or amount of liabilities of the Owner to the As- signee under the Agreement, the existence of any default therein, the giving of any notice required herein, or the application to be made by the Assignee of any amounts to be paid to the Assignee. The signature of the Assignee shall be sufficient for the exercise of any rights under the Policy assigned hereby to the Assignee and the receipt of the Assignee for any sums received by it shall be a full discharge and release therefor to the Insurer. 6. Upon termination of employment at Retirement, the Assignee shall, as provided for under Paragraph 8.2 of the Plan, reassign to the Owner the Policy and all specific rights included in this Collateral Assignment. IN WITNESS WHEREOF, the undersigned Owner has exe- cuted this Assignment. Witness Owner Relationship to In- sured EX-12 3 EXHIBIT 12 APPALACHIAN POWER COMPANY Computation of Consolidated Ratio of Earnings to Fixed Charges (in thousands except ratio data)
Twelve Months Year Ended December 31, Ended 1993 1994 1995 1996 1997 9/30/98 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . $ 80,472 $ 75,815 $ 80,777 $ 82,082 $ 81,009 $ 74,898 Interest on Other Long-term Debt. . . . . . . . 16,846 16,415 16,404 18,025 28,163 37,066 Interest on Short-term Debt . . . . . . . . . . 1,615 3,366 5,119 3,639 4,569 4,955 Miscellaneous Interest Charges. . . . . . . . . 2,954 3,913 5,323 7,327 6,857 10,469 Estimated Interest Element in Lease Rentals . . 7,900 7,700 7,000 6,600 6,000 6,000 Total Fixed Charges. . . . . . . . . . . . $109,787 $107,209 $114,623 $117,673 $126,598 $133,388 Earnings: Net Income. . . . . . . . . . . . . . . . . . . $125,132 $102,345 $115,900 $133,689 $120,514 $115,668 Plus Federal Income Taxes . . . . . . . . . . . 51,681 39,599 53,355 65,801 54,835 52,440 Plus State Income Taxes . . . . . . . . . . . . 8,887 5,910 7,273 10,180 8,109 7,480 Plus Fixed Charges (as above) . . . . . . . . . 109,787 107,209 114,623 117,673 126,598 133,388 Total Earnings . . . . . . . . . . . . . . $295,487 $255,063 $291,151 $327,343 $310,056 $308,796 Ratio of Earnings to Fixed Charges. . . . . . . . 2.69 2.37 2.54 2.78 2.44 2.31
EX-27 4 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000006879 APPALACHIAN POWER COMPANY 1,000 9-MOS DEC-31-1997 SEP-30-1998 PER-BOOK 3,071,595 109,354 337,537 37,346 434,704 3,990,536 260,458 638,510 198,304 1,097,272 22,310 19,439 1,532,809 18,475 0 43,500 19,504 0 53,487 12,760 1,170,980 3,990,536 2,689,576 52,323 2,455,861 2,508,184 181,392 (4,490) 176,902 95,133 81,769 1,822 79,947 89,187 54,586 218,395 0 0 All common stock owned by parent company; no EPS required.
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