-----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, F+AnPY+7XIFlkK/XUHplox6xpQaa0/0Zi7IA0pyT7r0oImtAqg8YK/l7pF1B41s/ 8hx4OnnTovwNb67tju6yvQ== 0000004904-99-000061.txt : 19990518 0000004904-99-000061.hdr.sgml : 19990518 ACCESSION NUMBER: 0000004904-99-000061 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990517 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: 99626557 BUSINESS ADDRESS: STREET 1: 40 FRANKLIN RD SW CITY: ROANOKE STATE: VA ZIP: 24011 BUSINESS PHONE: 7039852300 MAIL ADDRESS: STREET 1: 1 RIVERSIDE PLAZA CITY: COLUMBUS STATE: OH ZIP: 43215 10-Q 1 THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended MARCH 31, 1999 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period from to
Commission Registrant; State of Incorporation; I. R. S. Employer File Number Address; and Telephone Number Identification No. 1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640 (A New York Corporation) 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 40 Franklin Road, Roanoke, Virginia 24011 Telephone (540) 985-2300 1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455 One Summit Square P.O. Box 60, Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1701 Central Avenue, Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 301 Cleveland Avenue S.W., Caton, Ohio 44701 Telephone (330) 456-8173 AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at April 30, 1999 was 192,726,681. /TABLE AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended March 31, 1999
INDEX Page Part I. FINANCIAL INFORMATION American Electric Power Company, Inc. and Subsidiary Companies: Consolidated Statements of Income and Statements of Retained Earnings. . . . . . . . . . . . . . A-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2- A-3 Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4 Notes to Consolidated Financial Statements . . . . . . . . . A-5- A-13 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . A-14-A-28 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-8 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . C-9 - C-16 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-6 Management's Narrative Analysis of Results of Operations . . D-7 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-7 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . E-8 - E-15 Kentucky Power Company: Statements of Income and Statements of Retained Earnings . . F-1 Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3 Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4 Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-6 Management's Narrative Analysis of Results of Operations . . F-7 - F-8 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended March 31, 1999 INDEX Page Ohio Power Company and Subsidiaries: Consolidated Statements of Income and Consolidated Statements of Retained Earnings . . . . . . G-1 Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3 Consolidated Statements of Cash Flows. . . . . . . . . . . G-4 Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-6 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . G-7 - G-12 Part II. OTHER INFORMATION Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2 SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in millions, except per-share amounts) (UNAUDITED)
Three Months Ended March 31, 1999 1998 REVENUES: Domestic Regulated Electric Utilities. . . . . . . . . . $1,550 $1,509 Worldwide Non-regulated Electric and Gas Operations. . . 144 12 TOTAL REVENUES . . . . . . . . . . . . . . . . . 1,694 1,521 EXPENSES: Fuel and Purchased Power . . . . . . . . . . . . . . . . 491 485 Maintenance and Other Operation. . . . . . . . . . . . . 427 411 Depreciation and Amortization. . . . . . . . . . . . . . 148 144 Taxes Other Than Income Taxes. . . . . . . . . . . . . . 124 122 Worldwide Non-regulated Electric and Gas Operations. . . 123 15 TOTAL EXPENSES. . . . . . . . . . . . . . . . . . 1,313 1,177 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 381 344 OTHER LOSS, net. . . . . . . . . . . . . . . . . . . . . . (5) (4) INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES . . . . . . . . . . . . . . . . . . . . 376 340 INTEREST AND PREFERRED DIVIDENDS . . . . . . . . . . . . . 132 106 INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . 244 234 INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . . 93 83 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 151 $ 151 AVERAGE NUMBER OF SHARES OUTSTANDING . . . . . . . . . . . 192 190 EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . . $0.79 $0.79 CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . . $0.60 $0.60 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in millions) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $1,684 $1,605 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 151 151 DEDUCTIONS: Cash Dividends Declared. . . . . . . . . . . . . . . . . 115 114 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $1,720 $1,642 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in millions) ASSETS CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . $ 280 $ 173 Accounts Receivable (net). . . . . . . . . . . . . . 854 879 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 262 216 Materials and Supplies . . . . . . . . . . . . . . . 282 280 Accrued Utility Revenues . . . . . . . . . . . . . . 183 214 Energy Marketing and Trading Contracts . . . . . . . 603 372 Prepayments. . . . . . . . . . . . . . . . . . . . . 126 84 TOTAL CURRENT ASSETS . . . . . . . . . . . . 2,590 2,218 PLANT, PROPERTY AND EQUIPMENT: Electric: Production . . . . . . . . . . . . . . . . . . . 9,805 9,615 Transmission . . . . . . . . . . . . . . . . . . 3,592 3,692 Distribution . . . . . . . . . . . . . . . . . . 5,395 5,125 Other (including gas and coal mining assets and nuclear fuel) . . . . . . . . . . . . . . . . . 2,104 2,118 Construction Work in Progress. . . . . . . . . . . . 696 801 Total Plant, Property and Equipment. . . . . 21,592 21,351 Accumulated Depreciation and Amortization. . . . . . 8,777 8,549 NET PLANT, PROPERTY AND EQUIPMENT. . . . . . 12,815 12,802 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 1,908 1,847 OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 2,817 2,616 TOTAL. . . . . . . . . . . . . . . . . . . $20,130 $19,483 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable . . . . . . . . . . . . . . . . . . $ 741 $ 618 Short-term Debt. . . . . . . . . . . . . . . . . . . 626 617 Long-term Debt Due Within One Year . . . . . . . . . 490 206 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 387 382 Interest Accrued . . . . . . . . . . . . . . . . . . 117 75 Obligations Under Capital Leases . . . . . . . . . . 83 82 Energy Marketing and Trading Contracts . . . . . . . 585 360 Other. . . . . . . . . . . . . . . . . . . . . . . . 540 461 TOTAL CURRENT LIABILITIES. . . . . . . . . . 3,569 2,801 LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . 6,542 6,800 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,616 2,601 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 345 351 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 220 222 DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . 336 263 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,413 1,429 CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . 174 174 CONTINGENCIES (Note 8) COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50: 1999 1998 Shares Authorized . . . .600,000,000 600,000,000 Shares Issued . . . . . .201,561,414 200,816,469 (8,999,992 shares were held in treasury) . . . . . $ 1,310 $ 1,305 Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,885 1,853 Retained Earnings. . . . . . . . . . . . . . . . . . 1,720 1,684 TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . 4,915 4,842 TOTAL. . . . . . . . . . . . . . . . . . . $20,130 $19,483 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in millions) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 151 $ 151 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 172 153 Deferred Federal Income Taxes. . . . . . . . . . . . . . 30 8 Deferred Investment Tax Credits. . . . . . . . . . . . . (6) (6) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 25 (47) Fuel, Materials and Supplies . . . . . . . . . . . . . . (48) 7 Accrued Utility Revenues . . . . . . . . . . . . . . . . 31 26 Prepayments. . . . . . . . . . . . . . . . . . . . . . . (42) (11) Accounts Payable . . . . . . . . . . . . . . . . . . . . 123 (11) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 5 35 Interest Accrued . . . . . . . . . . . . . . . . . . . . 42 34 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 37 37 Other (net). . . . . . . . . . . . . . . . . . . . . . . . (117) (37) Net Cash Flows From Operating Activities . . . . . . 403 339 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (212) (153) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (5) (8) Net Cash Flows Used For Investing Activities . . . . (217) (161) FINANCING ACTIVITIES: Issuance of Common Stock . . . . . . . . . . . . . . . . . 31 19 Issuance of Long-term Debt . . . . . . . . . . . . . . . . 7 184 Change in Short-term Debt (net). . . . . . . . . . . . . . 9 85 Retirement of Long-term Debt . . . . . . . . . . . . . . . (11) (310) Dividends Paid on Common Stock . . . . . . . . . . . . . . (115) (114) Net Cash Flows Used For Financing Activities . . . . (79) (136) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 107 42 Cash and Cash Equivalents at Beginning of Period . . . . . . 173 91 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 280 $ 133 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $84 million and $66 million and for income taxes was $3 million and $2 million in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $18 million and $47 million in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state-ments should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING AND RELATED ACTIVITIES In April 1999 subsidiaries called $243 million of outstanding first mortgage bonds for early redemption in May 1999. Consequently the bonds were reclassified as a current liability on the Consolidated Balance Sheets. 3. NEW ACCOUNTING STANDARD In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income from marking open trading contracts to market is deferred as regulatory assets or liabilities for the portion of open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes in jurisdictions other than the Virginia retail jurisdiction. As a result of a prohibition against establishing additional regulatory assets contained in a Virginia settlement agreement, the Virginia retail jurisdictional share of the mark-to-market adjustment is included in net income. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. INVESTMENT IN YORKSHIRE The Company has a 50% ownership interest in Yorkshire Power Group Limited (Yorkshire) which is accounted for using the equity method of accounting. Equity income in Yorkshire is included in revenues from worldwide non-regulated operations. The following amounts which are not included in AEP's consolidated financial statements represent summarized consolidated financial information of Yorkshire: Three Months Ended March 31, 1999 1998 (in millions) Income Statement Data: Operating Revenues $652.0 $663.2 Operating Income 113.5 89.7 Net Income 34.6 6.9 5. BUSINESS SEGMENTS As of December 31, 1998, the Company adopted Statement of Financial Accounting Standards (SFAS) 131, "Disclosure about Segments of an Enterprise and Related Information." The Company's principal business segment is its cost based rate regulated Domestic Electric Utility business consisting of seven regulated utility operating companies providing residential, commercial, industrial and wholesale electric services in seven Atlantic and Midwestern states. Also included in this segment are the Company's electric power wholesale marketing and trading activities that are conducted as part of regulated operations and subject to regulatory ratemaking oversight. The World Wide Energy Investments segment represents principally international investments in energy-related projects and operations. It also includes the development and management of such projects and operations. Such investment activities include electric generation, supply and distribution, and natural gas pipeline, storage and other natural gas services. Other business segments include non-regulated electric and gas trading activities, telecommunication services, and the marketing of various energy saving products and services. Financial data for the business segments for the first quarter of 1999 and 1998 is in the following table:
Regulated Domestic World Electric Wide Energy Reconciling AEP Utilities Investments Other Adjustments Consolidated (in millions) March 31, 1999 Revenues from external customers $ 1,550 $ 165 $ 27 $(48) $ 1,694 Revenues from transactions with other operating segments - 17 31 (48) - Segment net income (loss) 150 8 (7) - 151 Total assets 17,440 2,148 542 - 20,130 March 31, 1998 Revenues from external customers 1,509 11 1 - 1,521 Revenues from transactions with other operating segments - - - - - Segment net income (loss) 156 (2) (3) - 151 Total assets 16,340 406 52 - 16,798 6. MERGER
As discussed in Note 5 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company and Central and South West Corporation (CSW) announced plans to merge in December 1997. In 1998 the appropriate shareholder proposals for the consummation of the merger were approved. Approval of the merger has been requested from the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the Nuclear Regulatory Commission (NRC) and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP and CSW plan to make the final two filings associated with approval of the merger with the Federal Communications Commission and the Department of Justice. The NRC and the Arkansas Public Service Commission approved the merger in 1998. In 1998 the FERC issued an order which confirmed that a 250 megawatt firm contract path with the Ameren System was available. The contract path was obtained by the Company and CSW to meet the requirement of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. In 1998 the FERC issued an order establishing hearing procedures for the merger and scheduled the hearings to begin on June 1, 1999. Subsequently, the FERC postponed the hearings until June 29, 1999. The 1998 FERC 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. On January 13, 1999, AEP and CSW filed an updated market power study with the FERC. On May 11, 1999, the Oklahoma Corporation Commission (OCC) approved the proposed merger between the Company and CSW. The approval follows an administrative law judge's oral decision on a partial settlement between certain principal parties to the Oklahoma merger proceeding which recommended that the OCC approve the merger. The partial settlement provides for sharing of net merger savings with Oklahoma customers; no increase of Oklahoma base rates prior to January 1, 2003; filing by December 31, 2001 with the FERC an application to join a regional transmission organization; and implementing additional quality of service standards for Oklahoma retail customers. Oklahoma's share (approximately $50 million) of net merger savings over the first five years after the merger is consummated will be split between Oklahoma customers and AEP shareholders, with customers receiving approximately 55% of the net savings. The partial settlement agreement includes a recommendation by the OCC staff that the OCC file with FERC indicating that it does not oppose the merger, but reserves the right to ensure that there are no adverse impacts on the Oklahoma transmission system. On May 4, 1999, AEP and CSW announced that a stipulated settlement had been reached in Texas. The agreement builds upon an earlier settlement agreement signed by AEP, CSW and certain parties to the Texas merger proceeding. In addition to the parties that were signatories to the earlier agreement, the staff of the Public Utility Commission of Texas is a signatory to the new settlement as well as other key parties to the merger proceeding. The stipulated settlement would result in rate reductions totaling $221 million over a six-year period for Texas customers after the merger is completed. The $221 million rate reduction represents $84.4 million of net merger savings and $136.6 million to resolve existing issues associated with CSW operating subsidiaries' rate and fuel reconciliation proceedings in Texas. Under the terms of the settlement agreement, base rates would not be increased before January 1, 2003 or three years after the merger, whichever is later. The settlement also calls for the divestiture of a total of 1,604 megawatts of existing and proposed generating capacity within Texas. If it is determined that the divestiture can proceed immediately after the merger closes without jeopardizing pooling-of-interests accounting treatment for the merger, sale of the plants would begin no later than 90 days after the merger closes. Absent that determination, the divestiture would occur approximately two years after the merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. Other provisions in the settlement agreement provide for, among other things, accelerated stranded cost recovery, quality-of-service standards, continuation of programs for disadvantaged customers and transfer of control of bulk transmission facilities to a regional transmission organization. The Indiana Utility Regulatory Commission (IURC) approved a settlement agreement related to the merger on April 26, 1999. The settlement agreement resulted from an investigation of the proposed merger between AEP and CSW initiated by the IURC. The terms of the settlement agreement provide for, among other things, a sharing of net merger savings through reductions in customers' bills of approximately $67 million over eight years after the merger is completed; a one year extension through January 1, 2005 of a freeze in base rates; additional annual deposits of $5.5 million to the nuclear decommissioning trust fund for the Indiana jurisdiction for the years 2001 through 2003; quality-of-service standards; and participation in a regional transmission organization. As part of the settlement agreement, the IURC agreed not to oppose the merger in FERC or SEC proceedings. AEP and CSW reached a settlement with the local unions of the International Brotherhood of Electrical Workers (IBEW) representing employees of AEP and CSW. Under the terms of the settlement, AEP and CSW will not terminate any current IBEW employee as a result of the merger and existing labor agreements will be recognized by the merged company. As part of the settlement, the IBEW local unions will withdraw their opposition to completing the merger. On April 15, 1999, in compliance with a request from the staff of the Kentucky Public Service Commission (KPSC) AEP filed an application seeking KPSC approval for the indirect change in control of Kentucky Power Company that will occur as a result of the proposed merger. AEP does not believe that the KPSC has the jurisdictional authority to approve the merger. Under the governing statute the KPSC must act on the application within 60 days. Therefore the KPSC proceeding is not expected to impact the timing of the merger. In April 1999 AEP and CSW announced that settlements were reached with certain wholesale customers that address issues related to the proposed merger. Under the terms of the settlements the wholesale customers agreed not to oppose the merger in FERC or SEC proceedings. The proposed merger of CSW into AEP would result in common ownership of two United Kingdom (UK) regional electricity companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50% ownership interest in Yorkshire and CSW has a 100% interest in Seeboard. Although the merger of CSW into AEP is not subject to approval by UK regulatory authorities, the common ownership of two UK RECs could be referred by the UK Secretary of State for Trade and Industry to the UK Competition Commission (formerly Monopolies and Mergers Commission) for investigation. The merger is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions, a number of which may not be waived by the parties, including the condition that the merger must be accounted for as a pooling of interests. The merger agreement will terminate on December 31, 1999 unless extended by either party as provided in the merger agreement. Although consummation of the merger is expected to occur in the fourth quarter of 1999, the Company is unable to predict the outcome or the timing of the required regulatory proceedings 7. VIRGINIA RESTRUCTURING In March 1999, a new law was enacted in Virginia to restructure the electric utility industry. Under the restructuring law a transition to choice of supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. Provisions allowing for an acceleration or limited delay in this schedule are also contained in the law. Except as provided in the law, the generation of electricity will not be subject to rate regulation after January 1, 2002. Additionally, each Virginia electric utility is required by 2001 to join or establish a regional transmission entity which will manage and control transmission assets. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded costs. Stranded costs are those costs above market including generation related net regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. The capped rates may be terminated after January 1, 2004, and prior to July 1, 2007, based upon the Virginia SCC determining that an effective competitive market exists. The wires charge will be equal to the difference between the generation component of the capped rates and the market price for generation service and will be imposed upon departing customers through the expiration of the rate cap period. Management has reviewed all the evidence currently available and concluded that as of March 31, 1999 the requirements to apply SFAS 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met for the Virginia retail jurisdiction. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates as provided in the law. When capped rates are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the generating business. At that time generation-related regulatory assets applicable to the Virginia jurisdiction will be written off to the extent that they cannot be recovered under the provisions of the restructuring law and generating assets for the Virginia retail jurisdiction will be evaluated for impairment. An impairment loss would be recorded to the extent that such assets cannot be recovered through the transition recovery mechanisms provided by the law. The amount of regulatory assets applicable to the Virginia generating business at March 31, 1999 is estimated to be $61 million before related tax effects and any possible offsetting regulatory liabilities. Regulatory liabilities applicable to the Virginia generation business at March 31, 1999 are estimated to be $38 million of which $25 million represents deferred investment tax credits (ITC). The Company is evaluating the tax normalization rules regarding the timing of the reversal of deferred ITC in connection with the Virginia restructuring law and the ability to record a reversal of deferred ITC in the same accounting periods when any possible losses from unrecovered regulatory assets are recorded. Should it not be possible under the Virginia law to recover all or a portion of the generation net regulatory assets, it could have a material adverse impact on results of operations; however, the amount of any impairment loss for Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation net regulatory assets cannot be estimated until such time as capped rates are determined under the law. 8. CONTINGENCIES Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to AEP's corporate owned life insurance (COLI) program for taxable years 1991-1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of COLI interest deductions through March 31, 1999 would reduce earnings by approximately $316 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other assets pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States (US) in the US District Court for the Southern District of Ohio in March 1998. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. Cook Plant Shutdown As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, both units of the Cook Plant were shut down in September 1997 due to questions regarding the operability of certain safety systems which arose during a NRC architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. During 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In January 1999 the Company announced that additional engineering reviews will be conducted at the Cook Plant delaying the restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. 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. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The NRC senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The cost of electricity supplied to retail customers remained higher due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal based purchased power continue to be substituted for low cost nuclear generation. The Indiana and Michigan retail jurisdictional 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 these 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. Therefore, a regulatory asset has been recorded and revenues accrued in anticipation of the future reconciliation and billing under the fuel cost recovery mechanisms of the higher fuel costs to replace Cook energy during the extended outage. At March 31, 1999, the regulatory asset was $118 million. On March 30, 1999, the IURC approved a settlement agreement that resolves all matters related to the reasonableness of fuel costs and all outage issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a credit of $55 million, including interest, to Indiana retail customers; authorization to defer any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $52.3 million revenue portion of the $55 million credit; authorization to defer up to $150 million of incremental operation and maintenance costs for the Cook Plant above the amount included in base rates; amortization of the fuel recoveries and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit will be refunded through customers' bills during the months of July, August and September 1999. The incremental costs incurred in first quarter 1999 for restart of the Cook units were $45 million of which $30 million were deferred pursuant to the settlement agreement discussed above. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be 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 1998 Annual Report. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 1999 vs. FIRST QUARTER 1998 RESULTS OF OPERATIONS Net income was unchanged in spite of the extended Cook Nuclear Plant outage and the expiration of a major wholesale power contract. Income statement line items which changed significantly were: Increase (in millions) % Revenues: Domestic Regulated Electric Utilities. . $ 41 3 Worldwide Non-regulated Operations . . . 132 N.M. Maintenance and Other Operation Expense. . . 16 4 Worldwide Non-regulated Operations Expense . 108 N.M. Interest and Preferred Dividends . . . . . . 26 25 Income Taxes . . . . . . . . . . . . . . . . 10 12 N.M. = Not Meaningful. Revenues from domestic regulated electric utility operations increased primarily due to a 4% increase in retail sales. Sales to weather-sensitive residential and commercial customers increased 10% and 3%, respectively, reflecting colder winter weather in 1999. Domestic regulated electric utility wholesale revenues declined reflecting the loss of a contract which supplied power to several municipal customers. The increase in revenues from worldwide non-regulated operations was predominantly due to the acquisitions of CitiPower, an Australian electric distribution utility, and midstream intrastate natural gas operations in December 1998. These new revenues were offset by an increase in worldwide non-regulated operations expenses. Maintenance and other operation expense increased due to an increase in nuclear engineering costs which were not subject to deferral. The increase in such costs were due to the extended outage of the Cook Nuclear Plant which was shutdown in September 1997. Worldwide non-regulated expenses increased as a result of the expansion of business development activities and expenses from the December 1998 acquisitions of CitiPower and the midstream gas operations. Additional borrowings to fund the Company's non-regulated operations, primarily the acquisitions of CitiPower and midstream natural gas assets in December 1998, were the primary reason for the significant increase in interest and preferred dividends. The increase in income taxes is primarily due to an increase in United States (US) federal, state and local income taxes. The increase is due to a rise in pre-tax income primarily from domestic regulated electric utility operations. FINANCIAL CONDITION Total plant and property additions including capital leases for the current period were $231 million. In April 1999 subsidiaries called $243 million of outstanding first mortgage bonds for early redemption in May 1999. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. OTHER MATTERS Spent Nuclear Fuel (SNF) Litigation As discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition (MDA) in the 1998 Annual Report, as a result of the Department of Energy's (DOE) failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, the Company along with a number of unaffiliated utilities and states filed suit in the US Court of Appeals for the District of Columbia Circuit requesting, among other things, that the court order DOE to meet its obligations under the law. The court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until 2010. In June 1998, the Company filed a complaint in the US Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits have been filed by other utilities. On April 6, 1999, the court granted DOE's motion to dismiss a similar lawsuit filed by another utility. Indiana Michigan Power Company's case has been suspended pending final resolution of the other utility's case. Cook Nuclear Plant Shutdown As discussed in MDA in the 1998 Annual Report, management shut down both units of the Cook Plant in September 1997 due to questions, which arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection, regarding the operability of certain safety systems. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. During 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In January 1999 the Company announced that additional engineering reviews will be conducted at the Cook Plant delaying the restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. 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. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The NRC senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The cost of electricity supplied to retail customers remained higher due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal based purchased power continue to be substituted for low cost nuclear generation. The Indiana and Michigan retail jurisdictional 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 these 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. Therefore, a regulatory asset has been recorded and revenues accrued in anticipation of the future reconciliation and billing under the fuel cost recovery mechanisms of the higher fuel costs to replace Cook energy during the extended outage. At March 31, 1999, this regulatory asset was $118 million. On March 30, 1999 the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement that resolves all matters related to the reasonableness of fuel costs and all outage issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a credit of $55 million, including interest, to Indiana retail customers; authorization to defer any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $52.3 million revenue portion of the $55 million credit; authorization to defer up to $150 million of incremental operation and maintenance costs for the Cook Plant above the amount included in base rates; amortization of the fuel recoveries and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit will be refunded through customers' bills during the months of July, August and September 1999. The incremental costs incurred in first quarter of 1999 for restart of the Cook units were $45 million of which $30 million were deferred pursuant to the settlement agreement discussed above. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows, and possibly financial condition. Merger As discussed in MDA in the 1998 Annual Report, the Company and Central and South West Corporation (CSW) announced plans to merge in December 1997. In 1998 the appropriate shareholder proposals for the consummation of the merger were approved. Approval of the merger has been requested from the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), the NRC and all of CSW's state regulatory commissions: Arkansas, Louisiana, Oklahoma and Texas. In the near future, AEP and CSW plan to make the final two filings associated with approval of the merger with the Federal Communications Commission and the Department of Justice. The NRC and the Arkansas Public Service Commission approved the merger in 1998. In 1998 the FERC issued an order which confirmed that a 250 megawatt firm contract path with the Ameren System was available. The contract path was obtained by the Company and CSW to meet the requirement of the Public Utility Holding Company Act of 1935 that the two systems operate on an integrated and coordinated basis. In 1998 the FERC issued an order establishing hearing procedures for the merger and scheduled the hearings to begin on June 1, 1999. Subsequently, the FERC postponed the hearings until June 29, 1999. The 1998 FERC 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. On January 13, 1999, AEP and CSW filed an updated market power study with the FERC. On May 11, 1999, the Oklahoma Corporation Commission (OCC) approved the proposed merger between the Company and CSW. The approval follows an administrative law judge's oral decision on a partial settlement between certain principal parties to the Oklahoma merger proceeding which recommended that the OCC approve the merger. The partial settlement provides for sharing of net merger savings with Oklahoma customers; no increase of Oklahoma base rates prior to January 1, 2003; filing by December 31, 2001 with the FERC an application to join a regional transmission organization; and implementing additional quality of service standards for Oklahoma retail customers. Oklahoma's share (approximately $50 million) of net merger savings over the first five years after the merger is consummated will be split between Oklahoma customers and AEP shareholders, with customers receiving approximately 55% of the net savings. The partial settlement agreement includes a recommendation by the OCC staff that the OCC file with FERC indicating that it does not oppose the merger, but reserves the right to ensure that there are no adverse impacts on the Oklahoma transmission system. On May 4, 1999, AEP and CSW announced that a stipulated settlement had been reached in Texas. The agreement builds upon an earlier settlement agreement signed by AEP, CSW and certain parties to the Texas merger proceeding. In addition to the parties that were signatories to the earlier agreement, the staff of the Public Utility Commission of Texas is a signatory to the new settlement as well as other key parties to the merger proceeding. The stipulated settlement would result in rate reductions totaling $221 million over a six-year period for Texas customers after the merger is completed. The $221 million rate reduction represents $84.4 million of net merger savings and $136.6 million to resolve existing issues associated with CSW operating subsidiaries' rate and fuel reconciliation proceedings in Texas. Under the terms of the settlement agreement, base rates would not be increased before January 1, 2003 or three years after the merger, whichever is later. The settlement also calls for the divestiture of a total of 1,604 megawatts of existing and proposed generating capacity within Texas. If it is determined that the divestiture can proceed immediately after the merger closes without jeopardizing pooling-of-interests accounting treatment for the merger, sale of the plants would begin no later than 90 days after the merger closes. Absent that determination, the divestiture would occur approximately two years after the merger closes to satisfy the requirements to use pooling-of-interests accounting treatment. Other provisions in the settlement agreement provide for, among other things, accelerated stranded cost recovery, quality-of-service standards, continuation of programs for disadvantaged customers and transfer of control of bulk transmission facilities to a regional transmission organization. The IURC approved a settlement agreement related to the merger on April 26, 1999. The settlement agreement resulted from an investigation of the proposed merger between AEP and CSW initiated by the IURC. The terms of the settlement agreement provide for, among other things, a sharing of net merger savings through reductions in customers' bills of approximately $67 million over eight years after the merger is completed; a one year extension through January 1, 2005 of a freeze in base rates; additional annual deposits of $5.5 million to the nuclear decommissioning trust fund for the Indiana jurisdiction for the years 2001 through 2003; quality-of-service standards; and participation in a regional transmission organization. As part of the settlement agreement, the IURC agreed not to oppose the merger in FERC or SEC proceedings. AEP and CSW reached a settlement with the local unions of the International Brotherhood of Electrical Workers (IBEW) representing employees of AEP and CSW. Under the terms of the settlement, AEP and CSW will not terminate any current IBEW employee as a result of the merger and existing labor agreements will be recognized by the merged company. As part of the settlement, the IBEW local unions will withdraw their opposition to completing the merger. On April 15, 1999, in compliance with a request from the staff of the Kentucky Public Service Commission (KPSC) AEP filed an application seeking KPSC approval for the indirect change in control of Kentucky Power Company that will occur as a result of the proposed merger. AEP does not believe that the KPSC has the jurisdictional authority to approve the merger. Under the governing statute the KPSC must act on the application within 60 days. Therefore the KPSC proceeding is not expected to impact the timing of the merger. In April 1999 AEP and CSW announced that settlements were reached with certain wholesale customers that address issued related to the proposed merger. Under the terms of the settlements the wholesale customers agreed not to oppose the merger in FERC or SEC proceedings. The proposed merger of CSW into AEP would result in common ownership of two United Kingdom (UK) regional electricity companies (RECs), Yorkshire Power Group Limited (Yorkshire) and Seeboard, plc. AEP has a 50% ownership interest in Yorkshire and CSW has a 100% interest in Seeboard. Although the merger of CSW into AEP is not subject to approval by UK regulatory authorities, the common ownership of two UK RECs could be referred by the UK Secretary of State for Trade and Industry to the UK Competition Commission (formerly Monopolies and Mergers Commission) for investigation. The merger is conditioned upon, among other things, the approval of the above state and federal regulatory agencies. The transaction must satisfy many conditions, a number of which may not be waived by the parties, including the condition that the merger must be accounted for as a pooling of interests. The merger agreement will terminate on December 31, 1999 unless extended by either party as provided in the merger agreement. Although consummation of the merger is expected to occur in the fourth quarter of 1999, the Company is unable to predict the outcome or the timing of the required regulatory proceedings Virginia Restructuring In March 1999, a new law was enacted in Virginia to restructure the electric utility industry. Under the restructuring law a transition to choice of supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. Provisions allowing for an acceleration or limited delay in this schedule are also contained in the law. Except as provided in the law, the generation of electricity will not be subject to rate regulation after January 1, 2002. Additionally, each Virginia electric utility is required by 2001 to join or establish a regional transmission entity which will manage and control transmission assets. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded costs. Stranded costs are those costs above market including generation related net regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. The capped rates may be terminated after January 1, 2004, and prior to July 1, 2007, based upon the Virginia SCC determining that an effective competitive market exists. The wires charge will be equal to the difference between the generation component of the capped rates and the market price for generation service and will be imposed upon departing customers through the expiration of the rate cap period. Management has reviewed all the evidence currently available and concluded that as of March 31, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met for the Virginia retail jurisdiction. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates as provided in the law. When capped rates are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the generating business. At that time generation-related regulatory assets applicable to the Virginia jurisdiction will be written off to the extent that they cannot be recovered under the provisions of the restructuring law and generating assets for the Virginia retail jurisdiction will be evaluated for impairment. An impairment loss would be recorded to the extent that such assets cannot be recovered through the transition recovery mechanisms provided by the law. The amount of regulatory assets applicable to the Virginia generating business at March 31, 1999 is estimated to be $61 million before related tax effects and any possible offsetting regulatory liabilities. Regulatory liabilities applicable to the Virginia generation business at March 31, 1999 are estimated to be $38 million of which $25 million represents deferred investment tax credits (ITC). The Company is evaluating the tax normalization rules regarding the timing of the reversal of deferred ITC in connection with the Virginia restructuring law and the ability to record a reversal of deferred ITC in the same accounting periods when any possible losses from unrecovered regulatory assets are recorded. Should it not be possible under the Virginia law to recover all or a portion of the generation net regulatory assets, it could have a material adverse impact on results of operations; however, the amount of any impairment loss for Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation net regulatory assets cannot be estimated until such time as capped rates are determined under the law. Market Risks The Company has certain market risks inherent in its business activities from changes in electricity commodity prices, foreign currency exchange rates and interest rates. The Company's exposure to market risk from the trading of electricity and natural gas and related financial derivative instruments has not changed materially since December 31, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices, foreign currency exchange rates and interest rates. There have been no material changes to the Company's exposure to fluctuations in foreign currency exchange rates related to foreign ventures and investments since December 31, 1998. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness. 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 Y2K readiness program. NERC then publicly reports summary information to the DOE regarding the Y2K readiness of electric utilities. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The NERC report, dated April 30, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - A Status Report and Work Plan, First Quarter 1999 states that: "With more than 75% of mission critical components tested through March 31, 1999, findings in the field continue to indicate that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities, including AEP, are working together to assess specific vendors' system problems and test plans. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The following chart shows our progress toward becoming ready for Y2K as of March 31, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Y2K activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65% replacing or retiring 94% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 56% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. *The Company is upgrading its 800 MHZ trunked radio system, a mission critical non-IT system, for Y2K readiness and it is anticipated that the upgrade should be complete by September 30, 1999. The Company continues to make steady progress toward the June 30, 1999 target date and anticipates completing the remediation/testing work for mission critical and high-priority systems by the June 30, 1999 target date except as noted in the table. The above chart does not reflect progress of midstream gas operations and CitiPower acquired in December 1998. The mission critical systems for the midstream gas operations are expected to be ready by June 30, 1999 and the mission critical systems for CitiPower are expected to be ready by October 1, 1999. Costs to Address the Company's Y2K Issues - Through March 31, 1999, the Company has spent $27 million on the Y2K project and estimates spending an additional $29 million to $41 million to achieve Y2K readiness. Most Y2K costs are for software, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Y2K compliant is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restorable in a reasonable period of time. CitiPower operates under a legal and regulatory regime which may expose it to customer claims, that may differ from claims under the US legal and regulatory regime, for service interruptions and/or power quality problems resulting from Y2K problems. In addition, although the Company is monitoring its relationships with third parties, such as suppliers, customers and other electric utilities, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others not affiliated with AEP, fail for critical applications, Y2K-related issues may materially adversely affect AEP. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a draft Y2K contingency plan and submitted it to the East Central Area Reliability Council (ECAR) in December 1998 as part of NERC's review of regional and individual electric utility contingency plans in 1999. NERC's target date is June 1999 for the completion of this contingency plan. In addition, the Company intends to establish contingency plans for its business units to address alternatives if Y2K related failures occur. These contingency plans will be developed by the end of 1999. AEP's Y2K contingency plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, with key employees on duty at those locations during the Y2K transition. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $52,827 $54,052 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 20,258 22,501 Rent - Rockport Plant Unit 2 . . . . . . . . . . . . . . 17,071 17,071 Other Operation. . . . . . . . . . . . . . . . . . . . . 3,370 2,649 Maintenance. . . . . . . . . . . . . . . . . . . . . . . 2,262 2,178 Depreciation . . . . . . . . . . . . . . . . . . . . . . 5,440 5,412 Taxes Other Than Federal Income Taxes. . . . . . . . . . 1,239 943 Federal Income Taxes . . . . . . . . . . . . . . . . . . 827 962 TOTAL OPERATING EXPENSES . . . . . . . . . . . . 50,467 51,716 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 2,360 2,336 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . 856 829 INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 3,216 3,165 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 602 785 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 2,614 $ 2,380 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $2,770 $2,528 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 2,614 2,380 CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . . . . 1,073 3,176 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $4,311 $1,732 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production. . . . . . . . . . . . . . . . . . . . . . $630,240 $630,260 General . . . . . . . . . . . . . . . . . . . . . . . 2,068 2,009 Construction Work in Progress . . . . . . . . . . . . 4,513 4,191 Total Electric Utility Plant. . . . . . . . . 636,821 636,460 Accumulated Depreciation. . . . . . . . . . . . . . . 283,005 277,855 NET ELECTRIC UTILITY PLANT. . . . . . . . . . 353,816 358,605 CURRENT ASSETS: Cash and Cash Equivalents . . . . . . . . . . . . . . 2,010 232 Accounts Receivable - Affiliated Companies. . . . . . 20,194 22,894 Fuel. . . . . . . . . . . . . . . . . . . . . . . . . 19,159 11,308 Materials and Supplies. . . . . . . . . . . . . . . . 3,912 3,900 Prepayments . . . . . . . . . . . . . . . . . . . . . 70 267 TOTAL CURRENT ASSETS. . . . . . . . . . . . . 45,345 38,601 REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . 5,924 5,984 DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . 3,248 702 TOTAL . . . . . . . . . . . . . . . . . . . $408,333 $403,892 See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $1,000: Authorized and Outstanding - 1,000 Shares . . . . . $ 1,000 $ 1,000 Paid-in Capital . . . . . . . . . . . . . . . . . . . 33,235 35,235 Retained Earnings . . . . . . . . . . . . . . . . . . 4,311 2,770 Total Common Shareholder's Equity . . . . . . 38,546 39,005 Long-term Debt. . . . . . . . . . . . . . . . . . . . 44,794 44,792 TOTAL CAPITALIZATION. . . . . . . . . . . . . 83,340 83,797 OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . 824 896 CURRENT LIABILITIES: Short-term Debt - Notes Payable . . . . . . . . . . . 5,575 24,450 Accounts Payable: General . . . . . . . . . . . . . . . . . . . . . . 8,911 6,419 Affiliated Companies. . . . . . . . . . . . . . . . 8,224 6,177 Taxes Accrued . . . . . . . . . . . . . . . . . . . . 8,854 3,227 Rent Accrued - Rockport Plant Unit 2. . . . . . . . . 23,427 4,963 Other . . . . . . . . . . . . . . . . . . . . . . . . 4,808 6,023 TOTAL CURRENT LIABILITIES . . . . . . . . . . 59,799 51,259 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . 131,937 133,330 REGULATORY LIABILITIES: Deferred Investment Tax Credits . . . . . . . . . . . 65,724 66,562 Amounts Due to Customers for Income Tax . . . . . . . 28,066 28,644 TOTAL REGULATORY LIABILITIES. . . . . . . . . 93,790 95,206 DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . 38,643 39,404 TOTAL . . . . . . . . . . . . . . . . . . . $408,333 $403,892 See Notes to Financial Statements.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS
(UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . $ 2,614 $ 2,380 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . 5,440 5,412 Deferred Federal Income Taxes. . . . . . . . . . . . (1,339) 1,446 Deferred Investment Tax Credits. . . . . . . . . . . (838) (841) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2. . . . . . . (1,393) (1,393) Deferred Property Taxes. . . . . . . . . . . . . . . (2,410) (2,385) Changes in Certain Current Assets and Liabilities: Accounts Receivable. . . . . . . . . . . . . . . . . 2,700 2,979 Fuel, Materials and Supplies . . . . . . . . . . . . (7,863) (3,821) Accounts Payable . . . . . . . . . . . . . . . . . . 4,539 4,119 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 5,627 2,716 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 18,464 18,464 Other (net). . . . . . . . . . . . . . . . . . . . . . (1,045) (3,019) Net Cash Flows From Operating Activities . . . . 24,496 26,057 INVESTING ACTIVITIES - Net Cash Flows Used for Construction . . . . . . . . . . . . . . . . . . . (770) (1,416) FINANCING ACTIVITIES: Return of Capital to Parent Company. . . . . . . . . . (2,000) - Retirement of Long-term Debt . . . . . . . . . . . . . - (25,000) Change in Short-term Debt (net). . . . . . . . . . . . (18,875) 3,425 Dividends Paid . . . . . . . . . . . . . . . . . . . . (1,073) (3,176) Net Cash Flows Used For Financing Activities . . (21,948) (24,751) Net Increase (Decrease) in Cash and Cash Equivalents . . 1,778 (110) Cash and Cash Equivalents at Beginning of Period . . . . 232 237 Cash and Cash Equivalents at End of Period . . . . . . . $ 2,010 $ 127 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $470,000 and $982,000 in 1999 and 1998, respectively, and for income taxes was $15,000 in 1998. See Notes to Financial Statements.
AEP GENERATING COMPANY NOTES TO FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 1999 vs. FIRST QUARTER 1998 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies and one unaffiliated utility pursuant to Federal Energy Regulatory Commission (FERC) approved long-term unit power agreements. The unit power agreements provide for recovery of the cost of producing the power including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. A monthly power bill for energy supplied is issued based on estimated expenses for the month and adjusted to actual amounts in the following month. Net income increased $0.2 million or 10% primarily as a result of the use of estimates for power production operation and maintenance expenses to bill customers which were in excess of the actual expenses incurred and included in the Statements of Income. The estimates will be adjusted to actual amounts in the customers' April bills. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues $(1.2) (2) Fuel Expense (2.2) (10) Other Operation Expense 0.7 27 Taxes Other Than Federal Income Taxes 0.3 31 Federal Income Taxes (0.1) (14) Interest Charges (0.2) (23) The decrease in operating revenues reflects recovery of lower operating expenses primarily reduced fuel expense. Fuel expense decreased due to a reduction in generation in the first quarter of 1999 as a result of reduced availability of the Rockport Plant. In 1999 outages of the Rockport Plant units were of longer duration than in 1998 causing the reduction in Rockport Plant availability. The increase in other operation expense is primarily due to the Company's allocated share of Rockport Plant's employee severance expense incurred in 1999 in excess of amounts accrued at December 31, 1998 and a payment to the City of Rockport in settlement of an annexation issue. Taxes other than federal income taxes increased due to an increase in state income taxes which resulted from an increase in pre-tax operating income in 1999 due to the cessation of tax depreciation for Rockport Plant Unit 1. The decline in federal income taxes attributable to operations was due to the reversal of deferred taxes in excess of the statutory tax rate partially offset by an increase in pre-tax operating income. Interest charges decreased due to a reduction in outstanding long-term debt balances reflecting the redemption of $25 million in March 1998 of pollution control revenue bonds. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $427,702 $415,366 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 123,573 108,209 Purchased Power. . . . . . . . . . . . . . . . . . . . . 50,591 69,262 Other Operation. . . . . . . . . . . . . . . . . . . . . 62,749 54,867 Maintenance. . . . . . . . . . . . . . . . . . . . . . . 28,511 35,352 Depreciation and Amortization. . . . . . . . . . . . . . 36,551 35,405 Taxes Other Than Federal Income Taxes. . . . . . . . . . 29,975 30,244 Federal Income Taxes . . . . . . . . . . . . . . . . . . 24,145 17,778 TOTAL OPERATING EXPENSES . . . . . . . . . . . . 356,095 351,117 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 71,607 64,249 NONOPERATING LOSS. . . . . . . . . . . . . . . . . . . . . (1,088) (387) INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 70,519 63,862 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 31,258 30,663 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 39,261 33,199 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 675 469 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 38,586 $ 32,730 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $179,461 $207,544 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 39,261 33,199 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . 30,348 29,729 Cumulative Preferred Stock . . . . . . . . . . . . . . 567 362 Capital Stock Expense. . . . . . . . . . . . . . . . . . 108 107 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $187,699 $210,545 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements. /TABLE APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,996,848 $1,979,180 Transmission . . . . . . . . . . . . . . . . . . . . 1,122,987 1,118,726 Distribution . . . . . . . . . . . . . . . . . . . . 1,650,705 1,641,523 General. . . . . . . . . . . . . . . . . . . . . . . 229,512 228,464 Construction Work in Progress. . . . . . . . . . . . 121,376 119,466 Total Electric Utility Plant . . . . . . . . 5,121,428 5,087,359 Accumulated Depreciation and Amortization. . . . . . 2,018,326 1,984,856 NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,103,102 3,102,503 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 120,748 111,020 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 36,098 7,755 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 88,504 122,746 Affiliated Companies . . . . . . . . . . . . . . . 23,084 35,802 Miscellaneous. . . . . . . . . . . . . . . . . . . 9,335 8,572 Allowance for Uncollectible Accounts . . . . . . . . (2,487) (2,234) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 54,937 49,826 Materials and Supplies . . . . . . . . . . . . . . . 61,128 60,440 Accrued Utility Revenues . . . . . . . . . . . . . . 35,008 45,985 Energy Marketing and Trading Contracts . . . . . . . 138,195 22,436 Prepayments. . . . . . . . . . . . . . . . . . . . . 14,499 8,151 TOTAL CURRENT ASSETS . . . . . . . . . . . . 458,301 359,479 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 424,314 433,516 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 43,529 40,520 TOTAL. . . . . . . . . . . . . . . . . . . $4,149,994 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 30,000,000 Shares Outstanding - 13,499,500 Shares. . . . . . . . . $ 260,458 $ 260,458 Paid-in Capital. . . . . . . . . . . . . . . . . . 663,743 663,633 Retained Earnings. . . . . . . . . . . . . . . . . 187,699 179,461 Total Common Shareholder's Equity. . . . . 1,111,900 1,103,552 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . 19,353 19,359 Subject to Mandatory Redemption. . . . . . . . . 22,310 22,310 Long-term Debt . . . . . . . . . . . . . . . . . . 1,395,477 1,472,451 TOTAL CAPITALIZATION . . . . . . . . . . . 2,549,040 2,617,672 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . 123,043 120,281 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . 157,239 80,004 Short-term Debt. . . . . . . . . . . . . . . . . . 57,275 76,400 Accounts Payable . . . . . . . . . . . . . . . . . 97,080 110,882 Taxes Accrued. . . . . . . . . . . . . . . . . . . 50,421 35,719 Customer Deposits. . . . . . . . . . . . . . . . . 13,537 14,123 Interest Accrued . . . . . . . . . . . . . . . . . 29,288 19,990 Revenue Refunds Accrued. . . . . . . . . . . . . . 44,818 95,267 Energy Marketing and Trading Contracts . . . . . . 138,960 24,076 Other. . . . . . . . . . . . . . . . . . . . . . . 84,242 78,808 TOTAL CURRENT LIABILITIES. . . . . . . . . 672,860 535,269 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 653,896 643,711 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . 61,059 62,231 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . 90,096 67,874 CONTINGENCIES (Note 6) TOTAL. . . . . . . . . . . . . . . . . . $4,149,994 $4,047,038 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 39,261 $ 33,199 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . 36,814 35,731 Deferred Federal Income Taxes. . . . . . . . . . . . . 12,362 (2,138) Deferred Investment Tax Credits. . . . . . . . . . . . (1,172) (1,182) Deferred Power Supply Costs (net). . . . . . . . . . . 14,706 7,390 Provision for Revenue Refunds. . . . . . . . . . . . . - 14,965 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . 46,450 (4,682) Fuel, Materials and Supplies . . . . . . . . . . . . . (5,799) (2,968) Accrued Utility Revenues . . . . . . . . . . . . . . . 10,977 15,450 Prepayments. . . . . . . . . . . . . . . . . . . . . . (6,348) 465 Accounts Payable . . . . . . . . . . . . . . . . . . . (13,802) (15,103) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 14,702 23,570 Interest Accrued . . . . . . . . . . . . . . . . . . . 9,298 8,780 Other (net). . . . . . . . . . . . . . . . . . . . . . . (41,060) (14,392) Net Cash Flows From Operating Activities . . . . . 116,389 99,085 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . (38,129) (40,066) Proceeds from Sale of Property . . . . . . . . . . . . . 127 535 Net Cash Flows Used For Investing Activities . . . (38,002) (39,531) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . - 96,781 Change in Short-term Debt (net). . . . . . . . . . . . . (19,125) 12,100 Retirement of Cumulative Preferred Stock . . . . . . . . (4) (117) Retirement of Long-term Debt . . . . . . . . . . . . . . - (138,470) Dividends Paid on Common Stock . . . . . . . . . . . . . (30,348) (29,729) Dividends Paid on Cumulative Preferred Stock . . . . . . (567) (572) Net Cash Flows Used For Financing Activities . . . (50,044) (60,007) Net Increase (Decrease) in Cash and Cash Equivalents . . . 28,343 (453) Cash and Cash Equivalents at Beginning of Period . . . . . 7,755 6,947 Cash and Cash Equivalents at End of Period . . . . . . . . $ 36,098 $ 6,494 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $21,009,000 and $20,933,000 and for income taxes was $57,000 and $570,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $2,453,000 and $6,120,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to agree with current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In April 1999 the Company called $77 million of first mortgage bonds, $37 million of 8.43% series due 2022, $30 million of 7.90% series due 2023 and $10 million of 7.80% series due 2023, for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. 3. VIRGINIA RESTRUCTURING As discussed in Note 2 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, in February 1999 the Virginia legislature passed comprehensive legislation, which became law upon the Governor's signature in March 1999, to restructure the electric utility industry. Under the restructuring law a transition to choice of supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. Provisions allowing for an acceleration or limited delay in this schedule are also contained in the law. Except as provided in the law, the generation of electricity will not be subject to rate regulation after January 1, 2002. Additionally, each Virginia electric utility is required by 2001 to join or establish a regional transmission entity which will manage and control transmission assets. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded costs. Stranded costs are those costs above market including generation related net regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. The capped rates may be terminated after January 1, 2004, and prior to July 1, 2007, based upon the Virginia SCC determining that an effective competitive market exists. The wires charge will be equal to the difference between the generation component of the capped rates and the market price for generation service and will be imposed upon departing customers through the expiration of the rate cap period. Management has reviewed all the evidence currently available and concluded that as of March 31, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates as provided in the law. When capped rates are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the generating business. At that time generation-related regulatory assets applicable to the Virginia jurisdiction will have to be written off to the extent that they cannot be recovered under the provisions of the restructuring law and generating assets for the Virginia retail jurisdiction will have to be evaluated for impairment. An impairment loss would be recorded to the extent that such assets cannot be recovered through the transition recovery mechanisms provided by the law. The amount of regulatory assets applicable to the Virginia generating business at March 31, 1999 is estimated to be $61 million before related tax effects and any possible offsetting regulatory liabilities. Regulatory liabilities applicable to the Virginia generation business at March 31, 1999 are estimated to be $38 million of which $25 million represents deferred investment tax credits (ITC). The Company is evaluating the tax normalization rules regarding the timing of the reversal of deferred ITC in connection with the Virginia restructuring law and the ability to record a reversal of deferred ITC in the same accounting periods when any possible losses from unrecovered regulatory assets are recorded. Should it not be possible under the Virginia law to recover all or a portion of the generation net regulatory assets, it could have a material adverse impact on results of operations; however, the amount of any impairment loss for Virginia retail jurisdictional generating assets and any loss from a possible inability to recover generation net regulatory assets cannot be estimated until such time as capped rates are determined under the law. 4. RATE MATTERS Virginia Jurisdiction As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company and the staff of the Virginia SCC filed a settlement agreement with the Virginia SCC in January 1999. The settlement agreement was approved by the Virginia SCC in February 1999. It required a refund to customers of all amounts collected in excess of the settlement rates. In February 1999 new rates were implemented, and in March 1999 refunds of $48.8 million including interest were made to customers. A liability for the refunds and interest had previously been recorded by the Company. Wholesale Jurisdiction As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the Company had requested a rehearing of a June 1998 Federal Energy Regulatory Commission (FERC) order which granted an annual rate increase of $3.4 million in response to a request for an $8.7 million annual rate increase. The FERC had authorized the Company to implement the $8.7 million annual rate increase subject to refund in 1992. On April 5, 1999, the FERC denied the rehearing request. As a result the Company will make the refund to customers following FERC approval of the Company's compliance filing of proposed new rates as ordered by the FERC. A refund liability of $44.4 million, including interest, has been accrued. West Virginia Jurisdiction On May 12, 1999, the Company filed with the West Virginia Public Service Commission for a base rate increase of $50.3 million annually and a reduction in expanded net energy cost rates of $37.9 million annually. The filings request that the new rates become effective January 1, 2000 when the current rate freeze expires. 5. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for the portion of open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes in the Company's non-Virginia jurisdictions. The Virginia jurisdiction net mark-to-market pre-tax gain of $1.5 million for the first quarter of 1999 is included in net income as a result of an agreed prohibition against establishing regulatory assets in a February 1999 Virginia SCC ordered settlement agreement. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 6. CONTINGENCIES Litigation As discussed in Note 4 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of COLI interest deductions through March 31, 1999 would reduce earnings by approximately $79 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 1999 vs. FIRST QUARTER 1998 RESULTS OF OPERATIONS Net income increased $6.1 million or 18% as a result of increased retail sales reflecting colder winter weather and a favorable accrual adjustment to a revenue refund provision, partially offset by decreased wholesale sales reflecting the loss of certain wholesale customers. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues. . . . . . . . . . $ 12.3 3 Fuel Expense. . . . . . . . . . . . . 15.4 14 Purchased Power Expense . . . . . . . (18.7) (27) Other Operation Expense . . . . . . . 7.9 14 Maintenance Expense . . . . . . . . . (6.8) (19) Federal Income Taxes. . . . . . . . . 6.4 36 The increase in operating revenues is attributable to a 5% increase in retail revenues, reflecting increased sales to residential customers of 15% due to colder winter weather, and the effect of a favorable adjustment to a provision for revenue refunds in the Company's Virginia jurisdiction in connection with the execution of the refund. A 26% reduction in wholesale revenues, reflecting the loss of a contract which supplied power to several municipal customers, partly offset the increase in retail revenues. The increase in fuel expense was primarily due to an increase in generation to meet the increased retail demand for electricity. Purchased power expense decreased due to a decrease in purchases of energy from the American Electric Power (AEP) System Power Pool (AEP Power Pool). The increase in other operation expense primarily reflects an increase in employee benefit costs as a result of incentive compensation plan accrual adjustments in connection with the payment of such compensation, which adjustments were unfavorable in 1999 and favorable in 1998, and an increase in workers' compensation accruals. Maintenance expense decreased significantly due to reduced expenditures resulting from costs incurred in 1998 to repair overhead transmission and distribution lines following two severe snowstorms. The increase in federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes. FINANCIAL CONDITION Total plant and property additions including capital leases for the first three months of 1999 were $41 million. Short-term debt decreased by $19 million during the quarter. In April 1999 the Company called $77 million of first mortgage bonds, $37 million of 8.43% series due 2022, $30 million of 7.90% series due 2023 and $10 million of 7.80% series due 2023, for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. OTHER MATTERS Virginia Restructuring As discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition in the 1998 Annual Report, in February 1999 the Virginia legislature passed comprehensive legislation, which became law in March 1999, to restructure the electric utility industry in Virginia. Under the restructuring law a transition to choice of supplier for retail customers will commence on January 1, 2002 and be completed, subject to a finding by the Virginia State Corporation Commission (Virginia SCC) that an effective competitive market exists, on January 1, 2004. Provisions allowing for an acceleration or limited delay in this schedule are also contained in the law. Except as provided in the law, the generation of electricity will not be subject to rate regulation after January 1, 2002. Additionally, each Virginia electric utility is required by 2001 to join or establish a regional transmission entity which will manage and control transmission assets. The Virginia restructuring law also provides an opportunity for recovery of just and reasonable net stranded costs. Stranded costs are those costs above market including generation related net regulatory assets and impaired tangible assets that potentially would not be recoverable in a competitive market. The mechanisms in the Virginia law for stranded cost recovery are: a capping of incumbent utility rates until as late as July 1, 2007, and the application of a wires charge upon customers who may depart the incumbent utility in favor of an alternative supplier prior to the termination of the rate cap. The law provides for the establishment of capped rates prior to January 1, 2001. The capped rates may be terminated after January 1, 2004, and prior to July 1, 2007, based upon the Virginia SCC determining that an effective competitive market exists. The wires charge will be equal to the difference between the generation component of the capped rates and the market price for generation service and will be imposed upon departing customers through the expiration of the rate cap period. Management has reviewed all the evidence currently available and concluded that as of March 31, 1999 the requirements to apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," continue to be met. The Company's Virginia rates for generation will continue to be cost-based regulated until the establishment of capped rates as provided in the law. When capped rates are established in Virginia, the application of SFAS 71 would be discontinued for the Virginia retail jurisdiction portion of the generating business, generation-related regulatory assets applicable to the Virginia jurisdiction will have to be written off to the extent that they cannot be recovered under the provisions of the restructuring law and generating assets for the Virginia retail jurisdiction will have to be evaluated for impairment. An impairment loss would be recorded to the extent that such assets cannot be recovered through the transition recovery mechanisms provided by the law. The amount of regulatory assets applicable to the Virginia generating business at March 31, 1999 is estimated to be $61 million before related tax effects and any possible offsetting regulatory liabilities. Regulatory liabilities applicable to the Virginia generation business at March 31, 1999 are estimated to be $38 million of which $25 million represents deferred investment tax credits (ITC). The Company is evaluating the tax normalization rules regarding the timing of the reversal of deferred ITC in connection with the Virginia restructuring law and the ability to record a reversal of deferred ITC in the same accounting periods when any possible losses from unrecovered regulatory assets are recorded. Should it not be possible under the Virginia law to recover all or a portion of the generation net regulatory assets, it could have a material adverse impact on results of operations; however, the amount of any impairment loss for Virginia retail jurisdictional generating assets and any loss from a possible inability to recover net generation regulatory assets cannot be estimated until such time as capped rates are determined under the law. Market Risks The Company has certain market risks inherent in its business activities from changes in electricity commodity prices and interest rates. The Company's exposure to market risk from the trading of electricity and related financial derivative instruments, which are allocated to the Company through the AEP Power Pool, has not changed materially since December 31, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The Company, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reports summary information to the U.S. Department of Energy (DOE) regarding the Y2K readiness of electric utilities. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The NERC report, dated April 30, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - - A Status Report and Work Plan, First Quarter 1999, states that: "With more than 75% of mission critical components tested through March 31, 1999, findings in the field continue to indicate that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The following chart shows our progress toward becoming ready for the Y2K as of March 31, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65% replacing or retiring 94% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 56% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. *The Company is upgrading its 800 MHZ trunked radio system, a mission critical non-IT system, for Y2K readiness and it is anticipated that the upgrade should be complete by September 30, 1999. The Company continues to make steady progress toward the June 30, 1999 target date and anticipates completing the remediation/testing work for mission critical and high-priority systems by the June 30, 1999 target date except as noted in the table. Costs to Address the Company's Year 2000 Issues - Through March 31, 1999, the Company has spent $8 million on the Y2K project and, estimates spending an additional $9 million to $12 million to achieve Y2K readiness. Most Y2K costs are for software modifications, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Y2K compliant is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restorable in a reasonable period of time. In addition, although relationships with third parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others who impact the AEP System's operations but are not affiliated with the AEP System, fail for critical applications, Y2K-related issues may materially adversely affect the Company. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a draft Y2K contingency plan and submitted it to the East Central Area Reliability Council in December 1998 as part of NERC's review of regional and individual electric utility contingency plans in 1999. NERC's target date is June 1999 for the completion of this contingency plan. In addition, the Company intends to establish contingency plans for its business units to address alternatives if Y2K related failures occur. Contingency plans will be developed by the end of 1999. The Company's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, with key employees on duty at those locations during the Y2K transition. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . $279,067 $266,399 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 45,856 46,980 Purchased Power. . . . . . . . . . . . . . . . . . . . 55,191 47,837 Other Operation. . . . . . . . . . . . . . . . . . . . 45,969 44,582 Maintenance. . . . . . . . . . . . . . . . . . . . . . 13,946 14,307 Depreciation . . . . . . . . . . . . . . . . . . . . . 23,184 22,850 Taxes Other Than Federal Income Taxes. . . . . . . . . 31,078 29,936 Federal Income Taxes . . . . . . . . . . . . . . . . . 17,796 14,678 TOTAL OPERATING EXPENSES. . . . . . . . . . . . 233,020 221,170 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . 46,047 45,229 NONOPERATING INCOME (LOSS) . . . . . . . . . . . . . . . 361 (28) INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . 46,408 45,201 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . 18,990 19,556 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . 27,418 25,645 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . 533 533 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . $ 26,885 $ 25,112 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . $186,441 $138,172 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . 27,418 25,645 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . 21,999 20,661 Cumulative Preferred Stock . . . . . . . . . . . . . 437 437 Capital Stock Expense. . . . . . . . . . . . . . . . . 96 96 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . $191,327 $142,623 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,533,468 $1,526,869 Transmission . . . . . . . . . . . . . . . . . . . . 341,734 339,934 Distribution . . . . . . . . . . . . . . . . . . . . 947,759 938,283 General. . . . . . . . . . . . . . . . . . . . . . . 131,789 130,002 Construction Work in Progress. . . . . . . . . . . . 114,899 118,477 Total Electric Utility Plant . . . . . . . . 3,069,649 3,053,565 Accumulated Depreciation . . . . . . . . . . . . . . 1,155,909 1,134,348 NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,913,740 1,919,217 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 79,670 73,088 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 14,728 7,206 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 85,674 89,522 Affiliated Companies . . . . . . . . . . . . . . . 24,514 17,966 Miscellaneous. . . . . . . . . . . . . . . . . . . 11,440 11,989 Allowance for Uncollectible Accounts . . . . . . . (2,993) (2,598) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 22,604 22,140 Materials and Supplies . . . . . . . . . . . . . . . 31,183 33,263 Accrued Utility Revenues . . . . . . . . . . . . . . 35,643 40,127 Energy Marketing and Trading Contracts . . . . . . . 79,987 12,670 Prepayments. . . . . . . . . . . . . . . . . . . . . 38,312 29,084 TOTAL CURRENT ASSETS . . . . . . . . . . . . 341,092 261,369 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 346,940 353,369 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 56,185 74,647 TOTAL. . . . . . . . . . . . . . . . . . . $2,737,627 $2,681,690 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 24,000,000 Shares Outstanding - 16,410,426 Shares. . . . . . . . . . $ 41,026 $ 41,026 Paid-in Capital. . . . . . . . . . . . . . . . . . . 572,587 572,492 Retained Earnings. . . . . . . . . . . . . . . . . . 191,327 186,441 Total Common Shareholder's Equity. . . . . . 804,940 799,959 Cumulative Preferred Stock - Subject to Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000 Long-term Debt . . . . . . . . . . . . . . . . . . . 959,922 959,786 TOTAL CAPITALIZATION . . . . . . . . . . . . 1,789,862 1,784,745 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 43,866 42,176 CURRENT LIABILITIES: Short-term Debt. . . . . . . . . . . . . . . . . . . 45,700 52,500 Accounts Payable - General . . . . . . . . . . . . . 23,416 34,631 Accounts Payable - Affiliated Companies. . . . . . . 41,148 37,132 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 127,913 141,831 Interest Accrued . . . . . . . . . . . . . . . . . . 24,294 14,355 Energy Marketing and Trading Contracts . . . . . . . 80,429 13,682 Other. . . . . . . . . . . . . . . . . . . . . . . . 33,053 37,197 TOTAL CURRENT LIABILITIES. . . . . . . . . . 375,953 331,328 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 438,645 442,100 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 47,842 48,710 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 41,459 32,631 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . . . . . $2,737,627 $2,681,690 See Notes to Consolidated Financial Statements. /TABLE COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 27,418 $ 25,645 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . . 23,232 22,907 Deferred Federal Income Taxes. . . . . . . . . . . . . . (48) 1,481 Deferred Investment Tax Credits. . . . . . . . . . . . . (868) (888) Deferred Fuel Costs (net). . . . . . . . . . . . . . . . 836 (522) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (1,756) (35,821) Fuel, Materials and Supplies . . . . . . . . . . . . . . 1,616 (2,455) Accrued Utility Revenues . . . . . . . . . . . . . . . . 4,484 4,439 Prepayments. . . . . . . . . . . . . . . . . . . . . . . (9,228) (3,683) Accounts Payable . . . . . . . . . . . . . . . . . . . . (7,199) 34,627 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (13,918) (15,181) Interest Accrued . . . . . . . . . . . . . . . . . . . . 9,939 11,857 Other (net). . . . . . . . . . . . . . . . . . . . . . . . 18,912 7,568 Net Cash Flows From Operating Activities . . . . . . 53,420 49,974 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (16,908) (22,113) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 246 2,129 Net Cash Flows Used For Investing Activities . . . . (16,662) (19,984) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 51,552 Change in Short-term Debt (net). . . . . . . . . . . . . . (6,800) (6,550) Retirement of Long-term Debt . . . . . . . . . . . . . . . - (57,000) Dividends Paid on Common Stock . . . . . . . . . . . . . . (21,999) (20,661) Dividends Paid on Cumulative Preferred Stock . . . . . . . (437) (437) Net Cash Flows Used For Financing Activities . . . . (29,236) (33,096) Net Increase (Decrease) in Cash and Cash Equivalents . . . . 7,522 (3,106) Cash and Cash Equivalents at Beginning of Period . . . . . . 7,206 12,626 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 14,728 $ 9,520 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $8,115,000 and $6,744,000 and for income taxes was $44,000 and $129,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $2,182,000 and $3,378,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform with current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 3. CONTINGENCIES As discussed in Note 3, of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of COLI interest deductions through March 31, 1999 would reduce earnings by approximately $43 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 1999 vs. FIRST QUARTER 1998 Net income increased $1.8 million or 7% in the first quarter due primarily to increased retail sales. Income statement line items which changed significantly were: Increase (in millions) % Operating Revenues . . . . . . . . . . . $12.7 5 Purchased Power Expense. . . . . . . . . 7.4 15 Federal Income Taxes . . . . . . . . . . 3.1 21 Operating revenues from retail customers increased $12.4 million reflecting increased sales to residential and commercial customers of 13% and 5%, respectively. Colder winter weather and customer growth were the main reasons for the increased sales. The increase in purchased power expense is primarily due to increased capacity charges from the American Electric Power (AEP) System Power Pool (AEP Power Pool). Under the terms of the AEP Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. The increase in capacity charges can be attributed to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all AEP Power Pool members. Federal income taxes attributable to operations increased primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis for rate-making purposes. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $334,113 $328,468 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 41,800 44,879 Purchased Power. . . . . . . . . . . . . . . . . . . . . 62,315 58,159 Other Operation. . . . . . . . . . . . . . . . . . . . . 91,575 76,433 Maintenance. . . . . . . . . . . . . . . . . . . . . . . 31,202 27,078 Depreciation and Amortization. . . . . . . . . . . . . . 36,985 35,793 Taxes Other Than Federal Income Taxes. . . . . . . . . . 19,029 18,697 Federal Income Taxes . . . . . . . . . . . . . . . . . . 12,369 18,366 TOTAL OPERATING EXPENSES . . . . . . . . . . . . 295,275 279,405 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 38,838 49,063 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . 1,735 1,315 INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 40,573 50,378 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 20,503 16,634 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 20,070 33,744 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 1,214 1,217 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 18,856 $ 32,527 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $253,154 $278,814 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 20,070 33,744 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . 28,664 29,366 Cumulative Preferred Stock . . . . . . . . . . . . . . 1,182 1,184 Capital Stock Expense. . . . . . . . . . . . . . . . . . 32 33 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $243,346 $281,975 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements. /TABLE INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,580,567 $2,565,041 Transmission . . . . . . . . . . . . . . . . . . . . 917,008 913,495 Distribution . . . . . . . . . . . . . . . . . . . . 773,187 768,888 General (including nuclear fuel) . . . . . . . . . . 227,347 228,013 Construction Work in Progress. . . . . . . . . . . . 161,984 156,411 Total Electric Utility Plant . . . . . . . . 4,660,093 4,631,848 Accumulated Depreciation and Amortization. . . . . . 2,113,688 2,081,355 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,546,405 2,550,493 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS . . . . . . . . . . . . . . . . 672,940 648,307 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 207,609 197,368 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 26,851 12,465 Accounts Receivable (net). . . . . . . . . . . . . . 124,769 130,746 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 30,482 20,857 Materials and Supplies . . . . . . . . . . . . . . . 83,538 78,009 Accrued Utility Revenues . . . . . . . . . . . . . . 28,183 37,277 Energy and Marketing Trading Contracts . . . . . . . 87,354 14,105 Prepayments. . . . . . . . . . . . . . . . . . . . . 8,572 4,848 TOTAL CURRENT ASSETS . . . . . . . . . . . . 389,749 298,307 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 493,496 421,475 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 40,737 32,573 TOTAL. . . . . . . . . . . . . . . . . . . $4,350,936 $4,148,523 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584 Paid-in Capital. . . . . . . . . . . . . . . . . . . 732,639 732,605 Retained Earnings. . . . . . . . . . . . . . . . . . 243,346 253,154 Total Common Shareholder's Equity. . . . . . 1,032,569 1,042,343 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 9,266 9,273 Subject to Mandatory Redemption. . . . . . . . . . 68,445 68,445 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,030,093 1,140,789 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,140,373 2,260,850 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning. . . . . . . . . . . . . . . 468,181 445,934 Other. . . . . . . . . . . . . . . . . . . . . . . . 243,836 240,320 TOTAL OTHER NONCURRENT LIABILITIES . . . . . 712,017 686,254 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 148,000 35,000 Short-term Debt. . . . . . . . . . . . . . . . . . . 110,295 108,700 Accounts Payable - General . . . . . . . . . . . . . 67,724 53,187 Accounts Payable - Affiliated Companies. . . . . . . 28,335 37,647 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 49,702 35,161 Interest Accrued . . . . . . . . . . . . . . . . . . 16,537 15,279 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963 Revenue Refunds Accrued . . . . . . . . . . . . . . 55,000 - Obligations Under Capital Leases . . . . . . . . . . 10,681 9,667 Energy and Marketing Trading Contracts . . . . . . . 87,838 15,228 Other. . . . . . . . . . . . . . . . . . . . . . . . 77,234 67,102 TOTAL CURRENT LIABILITIES. . . . . . . . . . 674,773 381,934 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 560,136 559,288 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 127,881 129,779 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 87,785 88,712 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 47,971 41,706 CONTINGENCIES (Note 4) TOTAL. . . . . . . . . . . . . . . . . . . $4,350,936 $4,148,523 See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 20,070 $ 33,744 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 37,995 36,889 Amortization of Incremental Nuclear Refueling Outage Expenses (net). . . . . . . . . . . . 2,347 4,777 Unrecovered Fuel and Purchased Power Costs . . . . . . . (52,664) (22,203) Deferred Nuclear Outage Costs (net). . . . . . . . . . . (30,000) - Deferred Federal Income Taxes. . . . . . . . . . . . . . 5,365 6,494 Deferred Investment Tax Credits. . . . . . . . . . . . . (1,898) (1,909) Deferred Property Taxes. . . . . . . . . . . . . . . . . (9,325) (8,185) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 5,977 96 Fuel, Materials and Supplies . . . . . . . . . . . . . . (15,154) (5,839) Accrued Utility Revenues . . . . . . . . . . . . . . . . 9,094 (964) Prepayments. . . . . . . . . . . . . . . . . . . . . . . (3,724) (1,223) Accounts Payable . . . . . . . . . . . . . . . . . . . . 5,225 10,571 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 14,541 17,551 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464 Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 55,000 - Other (net). . . . . . . . . . . . . . . . . . . . . . . . 10,540 (18,242) Net Cash Flows From Operating Activities . . . . . . 71,853 70,021 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (30,114) (25,290) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 903 698 Net Cash Flows Used For Investing Activities . . . . (29,211) (24,592) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . . 1,595 (9,125) Retirement of Cumulative Preferred Stock . . . . . . . . . (5) - Dividends Paid on Common Stock . . . . . . . . . . . . . . (28,664) (29,366) Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,182) (1,184) Net Cash Flows Used For Financing Activities . . . . (28,256) (39,675) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 14,386 5,754 Cash and Cash Equivalents at Beginning of Period . . . . . . 12,465 5,860 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 26,851 $ 11,614 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $18,527,000 and $14,412,000, respectively and for income taxes was $125,000 in 1998. Noncash acquisitions under capital leases were $3,783,000 and $16,630,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In April 1999 the Company called $65 million of first mortgage bonds, $20 million of 6.80% series due 2003, $20 million of 6.55% series due 2003 and $25 million of 6.55% series due 2004, for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. CONTINGENCIES Litigation As discussed in Note 3, of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of COLI interest deductions through March 31, 1999 would reduce earnings by approximately $66 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. Cook Plant Shutdown As discussed in Note 3 of the Notes to Consolidated Financial Statements in the 1998 Annual Report, both units of the Cook Plant were shut down in September 1997 due to questions regarding the operability of certain safety systems that arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. During 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In January 1999 the Company announced that additional engineering reviews will be conducted at the Cook Plant delaying the restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. 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. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The cost of electricity supplied to retail customers remained higher due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal based purchased power continue to be substituted for low cost nuclear generation. The Indiana and Michigan retail jurisdictional 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 these 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. Therefore, a regulatory asset has been recorded and revenues accrued in anticipation of the future reconciliation and billing under the fuel cost recovery mechanisms of the higher fuel costs to replace Cook energy during the extended outage. At March 31, 1999, the regulatory asset was $118 million. On March 30, 1999 the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement that resolves all matters related to the reasonableness of fuel costs and all outage issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a credit of $55 million, including interest, to Indiana retail customers; authorization to defer any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $52.3 million revenue portion of the $55 million credit; authorization to defer up to $150 million of incremental operation and maintenance costs for the Cook Plant above the amount included in base rates; amortization of the fuel recoveries and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit will be refunded through customers' bills during the months of July, August and September 1999. The incremental costs incurred in first quarter 1999 for restart of the Cook units were $45 million of which $30 million were deferred pursuant to the settlement agreement discussed above. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows, and possibly financial condition. Other The Company continues to be involved in other matters discussed in its 1998 Annual Report. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 1999 vs. FIRST QUARTER 1998 RESULTS OF OPERATIONS Although operating revenues increased $5.6 million or 2%, net income decreased $13.7 million or 41% due to increased operation and maintenance expense related to an extended outage of the Cook Nuclear Plant which was shut down in September 1997. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Operating Revenues. . . . . . . . . . . . $ 5.6 2 Fuel Expense. . . . . . . . . . . . . . . (3.1) (7) Purchased Power Expense . . . . . . . . . 4.2 7 Other Operation Expense . . . . . . . . . 15.1 20 Maintenance Expense . . . . . . . . . . . 4.1 15 Federal Income Taxes. . . . . . . . . . . (6.0) (33) Interest Charges. . . . . . . . . . . . . 3.9 23 Operating revenues increased due to increased capacity credits from the American Electric Power (AEP) System Power Pool (AEP Power Pool) and an increase in transmission and business development revenues. Under the terms of the AEP Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. The increase in capacity credits received can be attributed to a decrease in the Company's prior twelve month peak demand relative to the total peak demand of all Power Pool members. Fuel expense decreased as a result of a decline in generation reflecting reduced availability of coal-fired generation due to outages in the first quarter of 1999. The increase in purchased power expense resulted from increased purchases from the AEP Power Pool to replace power that would have been generated by the coal fired units which were unavailable. Other operation expense increased due to increased nuclear operation expenses for engineering costs incurred as a result of the extended shutdown. The extended shutdown of the Cook Plant also accounted for the increase in maintenance expense. Federal income taxes attributable to operations decreased due to a decrease in pre-tax operating income. Interest charges increased due to an accrual of interest for revenue refunds ordered by the Indiana commission as part of a settlement agreement and due to higher outstanding balances of long-term debt. FINANCIAL CONDITION Total plant and property additions including capital leases for the period were $34 million. During the first three months of 1999 short-term debt outstanding increased by $2 million. In April 1999 the Company called $65 million of first mortgage bonds, $20 million of 6.80% series due 2003, $20 million of 6.55% series due 2003 and $25 million of 6.55% series due 2004, for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. OTHER MATTERS Spent Nuclear Fuel (SNF) Litigation As discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition (MDA) in the 1998 Annual Report, as a result of the Department of Energy's (DOE) failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, the Company along with a number of unaffiliated utilities and states filed suit in the United States (US) Court of Appeals for the District of Columbia Circuit requesting, among other things, that the court order DOE to meet its obligations under the law. The court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until 2010. In June 1998, the Company filed a complaint in the US Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits have been filed by other utilities. On April 6, 1999, the court granted DOE's motion to dismiss a lawsuit filed by another utility. I&M's case has been suspended pending final resolution of the other utility's case. Cook Nuclear Plant Shutdown As discussed in MDA in the 1998 Annual Report, management shut down both units of the Cook Plant in September 1997 due to questions, which arose during a Nuclear Regulatory Commission (NRC) architect engineer design inspection, regarding the operability of certain safety systems. The NRC issued a Confirmatory Action Letter in September 1997 requiring the Company to address certain issues identified in the letter. During 1998 the NRC notified the Company that it had convened a Restart Panel for Cook Plant and provided a list of required restart activities. In order to identify and resolve all issues, including those in the letter, necessary to restart the Cook units, the Company is working with the NRC and will be meeting with the Panel on a regular basis, until the units are returned to service. In January 1999 the Company announced that additional engineering reviews will be conducted at the Cook Plant delaying the restart of the units. Previously, the units were scheduled to return to service at the end of the first and second quarters of 1999. The decision to delay restart resulted from internal assessments that indicated a need to conduct expanded system readiness reviews. A new restart schedule will be developed based on the results of the expanded reviews and should be available in June 1999. 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. Until these additional reviews are completed, management is unable to determine when the units will be returned to service. In May 1999 the Company received a letter from the NRC indicating that NRC senior managers had identified Cook Plant as an "agency-focus plant." The senior managers concluded that continued agency-level oversight was appropriate; however, the NRC required no additional action to redirect Cook Plant activities. The letter states that the NRC staff will continue to monitor Cook Plant performance through the Restart Panel process and evaluate whether additional action may be necessary. The cost of electricity supplied to retail customers remained higher due to the outage of the two Cook Plant nuclear units since higher cost coal-fired generation and coal based purchased power continue to be substituted for low cost nuclear generation. The Indiana and Michigan retail jurisdictional 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 these 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. Therefore, a regulatory asset has been recorded and revenues accrued in anticipation of the future reconciliation and billing under the fuel cost recovery mechanisms of the higher fuel costs to replace Cook energy during the extended outage. At March 31, 1999, the regulatory asset was $118 million. On March 30, 1999 the Indiana Utility Regulatory Commission (IURC) approved a settlement agreement that resolves all matters related to the reasonableness of fuel costs and all outage issues during the extended outage of the Cook Plant. The settlement agreement provides for, among other things, a credit of $55 million, including interest, to Indiana retail customers; authorization to defer any unrecovered fuel revenues accrued between September 9, 1997 and December 31, 1999, including the $52.3 million revenue portion of the $55 million credit; authorization to defer up to $150 million of incremental operation and maintenance costs for the Cook Plant above the amount included in base rates; amortization of the fuel recoveries and non-fuel operation and maintenance cost deferrals over a five-year period ending December 31, 2003; a freeze in base rates through December 31, 2003; and a fixed fuel recovery charge through March 1, 2004. The $55 million credit will be refunded through customers' bills during the months of July, August and September 1999. The incremental costs incurred in first quarter 1999 for restart of the Cook units were $45 million of which $30 million were deferred pursuant to the settlement agreement discussed above. Unless the costs of the extended outage and restart efforts are recovered from customers, there would be a material adverse effect on results of operations, cash flows, and possibly financial condition. Market Risks The Company has certain market risks inherent in its business activities from changes in electricity commodity prices and interest rates. The Company's exposure to market risk from the trading of electricity and related financial derivative instruments, which are allocated to the Company through the AEP Power Pool, has not changed materially since December 31, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The Company, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reports summary information to the US DOE regarding the Y2K readiness of electric utilities. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The NERC report, dated April 30, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - - A Status Report and Work Plan, First Quarter 1999, states that: "With more than 75% of mission critical components tested through March 31, 1999, findings in the field continue to indicate that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The following chart shows our progress toward becoming ready for the Y2K as of March 31, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65% replacing or retiring 94% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 56% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. *The Company is upgrading its 800 MHZ trunked radio system, a mission critical non-IT system, for Y2K readiness and it is anticipated that the upgrade should be complete by September 30, 1999. The Company continues to make steady progress toward the June 30, 1999 target date andanticipates completing the remediation/testing work for mission critical and high-priority systems by the June 30, 1999 target date except as noted in the table. Costs to Address the Company's Year 2000 Issues - Through March 31, 1999, the Company has spent $5 million on the Year 2000 project and, estimates spending an additional $5 million to $7 million to achieve Y2K readiness. Most Y2K costs are for software modifications, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Y2K compliant is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restored. In addition, although relationships with third parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others who impact the AEP System's operations but are not affiliated with the AEP System, fail for critical applications, Y2K-related issues may materially adversely affect the Company. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a draft Y2K contingency plan and submitted it to the East Central Area Reliability Council in December 1998 as part of NERC's review of regional and individual electric utility contingency plans in 1999. NERC's target date is June 1999 for the completion of this contingency plan. In addition, the Company intends to establish contingency plans for its business units to address alternatives if Y2K related failures occur. Contingency plans will be developed by the end of 1999. The Company's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, with key employees on duty at those locations during the Y2K transition. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . $90,741 $87,345 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . 19,691 22,301 Purchased Power. . . . . . . . . . . . . . . . . . 24,427 21,211 Other Operation. . . . . . . . . . . . . . . . . . 12,351 10,994 Maintenance. . . . . . . . . . . . . . . . . . . . 4,791 9,166 Depreciation and Amortization. . . . . . . . . . . 7,190 6,910 Taxes Other Than Federal Income Taxes. . . . . . . 2,534 2,492 Federal Income Taxes . . . . . . . . . . . . . . . 4,397 2,180 TOTAL OPERATING EXPENSES . . . . . . . . . 75,381 75,254 OPERATING INCOME . . . . . . . . . . . . . . . . . . 15,360 12,091 NONOPERATING LOSS. . . . . . . . . . . . . . . . . . (114) (71) INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . 15,246 12,020 INTEREST CHARGES . . . . . . . . . . . . . . . . . . 7,037 7,003 NET INCOME . . . . . . . . . . . . . . . . . . . . . $ 8,209 $ 5,017 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . $71,452 $78,076 NET INCOME . . . . . . . . . . . . . . . . . . . . . 8,209 5,017 CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . 7,443 7,075 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . $72,218 $76,018 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . $ 267,282 $ 267,201 Transmission . . . . . . . . . . . . . . . . 327,989 326,989 Distribution . . . . . . . . . . . . . . . . 353,918 351,407 General. . . . . . . . . . . . . . . . . . . 68,259 68,038 Construction Work in Progress. . . . . . . . 31,954 30,076 Total Electric Utility Plant . . . . 1,049,402 1,043,711 Accumulated Depreciation and Amortization. . 322,483 315,546 NET ELECTRIC UTILITY PLANT . . . . . 726,919 728,165 OTHER PROPERTY AND INVESTMENTS . . . . . . . . 15,126 12,078 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . 4,251 1,935 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . 22,919 23,295 Affiliated Companies . . . . . . . . . . . 6,084 8,797 Miscellaneous. . . . . . . . . . . . . . . 3,151 4,019 Allowance for Uncollectible Accounts . . . (930) (848) Fuel . . . . . . . . . . . . . . . . . . . . 9,895 7,888 Materials and Supplies . . . . . . . . . . . 13,538 13,652 Accrued Utility Revenues . . . . . . . . . . 13,573 13,560 Energy Marketing and Trading Contracts . . . 32,257 4,726 Prepayments. . . . . . . . . . . . . . . . . 1,339 1,657 TOTAL CURRENT ASSETS . . . . . . . . 106,077 78,681 REGULATORY ASSETS. . . . . . . . . . . . . . . 91,785 92,447 DEFERRED CHARGES . . . . . . . . . . . . . . . 8,684 10,476 TOTAL. . . . . . . . . . . . . . . $ 948,591 $ 921,847 See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - Par Value $50: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares . . . . . . $ 50,450 $ 50,450 Paid-in Capital. . . . . . . . . . . . . . . 148,750 148,750 Retained Earnings. . . . . . . . . . . . . . 72,218 71,452 Total Common Shareholder's Equity. . 271,418 270,652 Long-term Debt . . . . . . . . . . . . . . . 296,089 308,838 TOTAL CAPITALIZATION . . . . . . . . 567,507 579,490 OTHER NONCURRENT LIABILITIES . . . . . . . . . 26,124 26,827 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . 72,797 60,000 Short-term Debt. . . . . . . . . . . . . . . 11,950 20,350 Accounts Payable - General . . . . . . . . . 9,919 12,917 Accounts Payable - Affiliated Companies. . . 13,270 11,814 Customer Deposits. . . . . . . . . . . . . . 3,961 4,038 Taxes Accrued. . . . . . . . . . . . . . . . 12,387 7,256 Interest Accrued . . . . . . . . . . . . . . 8,795 6,241 Energy Marketing and Trading Contracts . . . 32,431 5,089 Other. . . . . . . . . . . . . . . . . . . . 12,505 13,612 TOTAL CURRENT LIABILITIES. . . . . . 178,015 141,317 DEFERRED INCOME TAXES. . . . . . . . . . . . . 158,415 158,706 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . 13,900 14,200 DEFERRED CREDITS . . . . . . . . . . . . . . . 4,630 1,307 CONTINGENCIES (Note 4) TOTAL. . . . . . . . . . . . . . . $948,591 $921,847 See Notes to Financial Statements.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . $ 8,209 $ 5,017 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . 7,192 6,913 Deferred Federal Income Taxes. . . . . . . . . . (254) 32 Deferred Investment Tax Credits. . . . . . . . . (300) (305) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . 4,039 (5,100) Fuel, Materials and Supplies . . . . . . . . . . (1,893) 542 Accrued Utility Revenues . . . . . . . . . . . . (13) 2,726 Accounts Payable . . . . . . . . . . . . . . . . (1,542) (6,221) Taxes Accrued. . . . . . . . . . . . . . . . . . 5,131 2,695 Interest Accrued . . . . . . . . . . . . . . . . 2,554 1,971 Other (net). . . . . . . . . . . . . . . . . . . . 1,519 2,192 Net Cash Flows From Operating Activities . . 24,642 10,462 INVESTING ACTIVITIES - Construction Expenditures . . (6,483) (6,553) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . (8,400) 2,775 Dividends Paid . . . . . . . . . . . . . . . . . . (7,443) (7,075) Net Cash Flows Used For Financing Activities . . . . . . . . . . . (15,843) (4,300) Net Increase (Decrease) in Cash and Cash Equivalents 2,316 (391) Cash and Cash Equivalents at Beginning of Period . . 1,935 1,381 Cash and Cash Equivalents at End of Period . . . . . $ 4,251 $ 990 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $4,374,000 and $4,931,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $568,000 and $1,568,000 in 1999 and 1998, respectively. See Notes to Financial Statements. /TABLE KENTUCKY POWER COMPANY NOTES TO FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In April 1999 the Company called $13 million of 7.90% First Mortgage Bonds due 2023 for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Balance Sheets. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. CONTINGENCIES As discussed in Note 3, of the Notes to Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1992-1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of COLI interest deductions through March 31, 1999 would reduce earnings by approximately $8 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1992-1997 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Balance Sheets in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. The Company continues to be involved in certain other matters discussed in its 1998 Annual Report. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 1999 vs. FIRST QUARTER 1998 Net income increased $3.2 million or 64% due to an increase in sales to retail customers reflecting colder weather. Income statement line items which changed significantly were: Increase(Decrease) (in millions) % Operating Revenues. . . . . . . . . . . $ 3.4 4 Fuel Expense. . . . . . . . . . . . . . (2.6) (12) Purchased Power Expense . . . . . . . . 3.2 15 Other Operation Expense . . . . . . . . 1.4 12 Maintenance Expense . . . . . . . . . . (4.4) (48) Federal Income Taxes. . . . . . . . . . 2.2 102 Operating revenues increased due to a 7% increase in retail sales. Sales to residential and commercial customers increased 12% and 13%, respectively, due primarily to colder winter weather. The decrease in fuel expense is primarily attributable to a decrease in generation reflecting reduced availability of the Company's Big Sandy Plant in 1999 due to forced outages. Purchased power expense increased primarily due to increased energy purchases and capacity charges from the American Electric Power System Power Pool (AEP Power Pool). The increase in purchases from the AEP Power Pool were required to meet increased demand for energy and to replace power not available due to the Big Sandy Plant and an affiliate's plant outages. The affiliate, who is not a member of the AEP Power Pool, has an agreement with the Company to sell a percentage of its generation to the Company when the affiliate's generation is available. Under the terms of the AEP Power Pool, capacity credits and charges are designed to allocate the cost of the AEP System's capacity among the AEP Power Pool members based on their relative peak demands and generating reserves. The increase in capacity charges can be attributed to an increase in the Company's prior twelve month peak demand relative to the total peak demand of all AEP Power Pool members. The increase in other operation expense is due to accrual adjustments for employee pensions and benefits recorded in 1999 and 1998. The 1999 adjustment was unfavorable while the 1998 adjustment was favorable. The decrease in maintenance expense was primarily due to decreased overhead distribution line maintenance expenditures resulting from maintenance costs incurred in 1998 to repair and restore customers' service after winter storm damage. An increase in pre-tax operating income was the primary cause of the increase in federal income taxes attributable to operations. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . $518,221 $515,672 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189,163 193,275 Purchased Power. . . . . . . . . . . . . . . . . . . . . . . . 21,273 19,590 Other Operation. . . . . . . . . . . . . . . . . . . . . . . . 85,061 80,901 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . 25,490 30,593 Depreciation and Amortization. . . . . . . . . . . . . . . . . 36,785 35,863 Taxes Other Than Federal Income Taxes. . . . . . . . . . . . . 43,853 42,658 Federal Income Taxes . . . . . . . . . . . . . . . . . . . . . 37,640 33,723 TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . . 439,265 436,603 OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . 78,956 79,069 NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . 2,000 1,238 INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . 80,956 80,307 INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . 20,135 19,871 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,821 60,436 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . . . 367 370 EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . $ 60,454 $ 60,066 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 1999 1998 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . . $587,500 $590,151 NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,821 60,436 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . . . . . . . . . . . 57,703 52,775 Cumulative Preferred Stock . . . . . . . . . . . . . . . . . 367 370 BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . $590,251 $597,442 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,677,630 $2,646,597 Transmission . . . . . . . . . . . . . . . . . . . . 845,755 842,318 Distribution . . . . . . . . . . . . . . . . . . . . 954,198 949,224 General (including mining assets). . . . . . . . . . 680,173 689,815 Construction Work in Progress. . . . . . . . . . . . 115,146 129,887 Total Electric Utility Plant . . . . . . . . 5,272,902 5,257,841 Accumulated Depreciation and Amortization. . . . . . 2,493,936 2,461,376 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,778,966 2,796,465 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 230,832 218,311 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 114,785 89,652 Accounts Receivable: Customers. . . . . . . . . . . . . . . . . . . . . 255,995 215,665 Affiliated Companies . . . . . . . . . . . . . . . 118,333 63,922 Miscellaneous. . . . . . . . . . . . . . . . . . . 41,063 28,139 Allowance for Uncollectible Accounts . . . . . . . (2,290) (1,678) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 117,956 94,914 Materials and Supplies . . . . . . . . . . . . . . . 84,237 86,870 Accrued Utility Revenues . . . . . . . . . . . . . . 39,419 43,501 Energy Marketing and Trading Contracts . . . . . . . 125,927 19,790 Prepayments. . . . . . . . . . . . . . . . . . . . . 47,536 34,523 TOTAL CURRENT ASSETS . . . . . . . . . . . . 942,961 675,298 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 549,597 551,776 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 88,536 102,830 TOTAL. . . . . . . . . . . . . . . . . . . $4,590,892 $4,344,680 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
March 31, December 31, 1999 1998 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 40,000,000 Shares Outstanding - 27,952,473 Shares. . . . . . . . . . $ 321,201 $ 321,201 Paid-in Capital. . . . . . . . . . . . . . . . . . . 462,338 462,335 Retained Earnings. . . . . . . . . . . . . . . . . . 590,251 587,500 Total Common Shareholder's Equity. . . . . . 1,373,790 1,371,036 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 17,357 17,370 Subject to Mandatory Redemption. . . . . . . . . . 11,850 11,850 Long-term Debt . . . . . . . . . . . . . . . . . . . 975,452 1,073,456 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,378,449 2,473,712 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 374,244 360,330 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . 98,958 11,472 Short-term Debt. . . . . . . . . . . . . . . . . . . 219,700 123,005 Accounts Payable . . . . . . . . . . . . . . . . . . 242,161 235,787 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 164,425 161,406 Interest Accrued . . . . . . . . . . . . . . . . . . 23,212 14,187 Obligations Under Capital Leases . . . . . . . . . . 28,283 28,310 Energy Marketing and Trading Contracts . . . . . . . 126,567 22,480 Other. . . . . . . . . . . . . . . . . . . . . . . . 92,614 97,916 TOTAL CURRENT LIABILITIES. . . . . . . . . . 995,920 694,563 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 702,248 711,913 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 38,458 39,296 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 101,573 64,866 CONTINGENCIES (Note 4) TOTAL. . . . . . . . . . . . . . . . . . . $4,590,892 $4,344,680 See Notes to Consolidated Financial Statements. /TABLE OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Three Months Ended March 31, 1999 1998 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 60,821 $ 60,436 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . 45,129 43,259 Deferred Federal Income Taxes. . . . . . . . . . . . . . (3,601) 3,466 Deferred Fuel Costs (net). . . . . . . . . . . . . . . . (7,227) (11,000) Amortization of Deferred Property Taxes. . . . . . . . . 19,426 19,344 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (107,053) (36,126) Fuel, Materials and Supplies . . . . . . . . . . . . . . (20,409) 21,530 Accrued Utility Revenues . . . . . . . . . . . . . . . . 4,082 2,491 Prepayments. . . . . . . . . . . . . . . . . . . . . . . (13,013) (4,930) Accounts Payable . . . . . . . . . . . . . . . . . . . . 6,374 (7,222) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 3,019 (3,917) Interest Accrued . . . . . . . . . . . . . . . . . . . . 9,025 8,771 Operating Reserves . . . . . . . . . . . . . . . . . . . . 17,519 9,548 Other (net). . . . . . . . . . . . . . . . . . . . . . . . 24,364 6,164 Net Cash Flows From Operating Activities . . . . . . 38,456 111,814 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (41,888) (35,186) Proceeds from Sale of Property and Other . . . . . . . . . 629 2,413 Net Cash Flows Used For Investing Activities . . . . (41,259) (32,773) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . . 96,695 88,800 Retirement of Cumulative Preferred Stock . . . . . . . . . (10) - Retirement of Long-term Debt . . . . . . . . . . . . . . . (10,679) (75,237) Dividends Paid on Common Stock . . . . . . . . . . . . . . (57,703) (52,775) Dividends Paid on Cumulative Preferred Stock . . . . . . . (367) (370) Net Cash Flows From (Used For) Financing Activities. 27,936 (39,582) Net Increase in Cash and Cash Equivalents. . . . . . . . . . 25,133 39,459 Cash and Cash Equivalents at Beginning of Period . . . . . . 89,652 44,203 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 114,785 $ 83,662 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $10,562,000 and $10,377,000 and for income taxes was $2,219,000 and $539,000 in 1999 and 1998, respectively. Noncash acquisitions under capital leases were $5,634,000 and $10,294,000 in 1999 and 1998, respectively. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 1999 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1998 Annual Report as incorporated in and filed with the Form 10-K. Certain prior-period amounts have been reclassified to conform to current-period presentation. In the opinion of management, the financial statements reflect all adjustments (consisting of only normal recurring accruals) which are necessary for a fair presentation of the results of operations for interim periods. 2. FINANCING ACTIVITIES In April 1999 the Company called $88 million of first mortgage bonds, $40 million of 7.85% series due 2023, $40 million of 6.875% series due 2003 and $8 million of 6.55% series due 2003, for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. 3. NEW ACCOUNTING STANDARDS In the first quarter of 1999 the Company adopted the Financial Accounting Standards Board's Emerging Issues Task Force Consensus (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The EITF requires that all energy trading contracts be marked-to-market. The effect on the Consolidated Statements of Income of marking open trading contracts to market is deferred as regulatory assets or liabilities for those open trading transactions that are included in cost of service on a settlement basis for ratemaking purposes. The adoption of the EITF did not have a material effect on results of operations, cash flows or financial condition. 4. CONTINGENCIES As discussed in Note 4, of the Notes to Consolidated Financial Statements in the 1998 Annual Report, the deductibility of certain interest deductions related to American Electric Power's corporate owned life insurance (COLI) program for taxable years 1991-1996 is under review by the Internal Revenue Service (IRS). Adjustments have been or will be proposed by the IRS disallowing COLI interest deductions. A disallowance of COLI interest deductions through March 31, 1999 would reduce earnings by approximately $117 million (including interest). The Company has made no provision for any possible earnings impact from this matter. In 1998 the Company made payments of taxes and interest attributable to COLI interest deductions for taxable years 1991-1997 to avoid the potential assessment by the IRS of any additional above market rate interest on the contested amount. These payments to the IRS are included on the Consolidated Balance Sheets in other property and investments pending the resolution of this matter. The Company will seek refund, either administratively or through litigation, of all amounts paid plus interest. In order to resolve this issue, the Company filed suit against the United States in the US District Court for the Southern District of Ohio in March 1998. Management believes that it has a meritorious position and will vigorously pursue this lawsuit. In the event the resolution of this matter is unfavorable, it will have a material adverse impact on results of operations. The Company continues to be involved in certain other matters discussed in the 1998 Annual Report. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION FIRST QUARTER 1999 vs. FIRST QUARTER 1998 RESULTS OF OPERATIONS Net income was virtually unchanged as operating income was static reflecting flat operating revenues and steady operating expenses. Income statement line items which changed significantly were: Increase (Decrease) (in millions) % Fuel Expense . . . . . . . . . . . . . $(4.1) (2) Other Operation Expense. . . . . . . . 4.2 5 Maintenance Expense. . . . . . . . . . (5.1) (17) Federal Income Taxes . . . . . . . . . 3.9 12 The decrease in fuel expense is primarily due to a decrease in the average cost of fuel consumed. Other operation expense increased due to accrual adjustments related to incentive compensation payments made in the first quarter. The 1999 adjustment was unfavorable and the 1998 adjustment was favorable. The decrease in maintenance expense was primarily due to a reduction in scheduled boiler plant maintenance at the Company's generating plants in 1999. The increase in federal income taxes attributable to operations is primarily due to an increase in pre-tax operating income and changes in certain book/tax differences accounted for on a flow-through basis. FINANCIAL CONDITION Total plant and property additions including capital leases for the current period were $48 million. Short-term debt increased by $97 million from the beginning of 1999. In April 1999 the Company called $88 million of first mortgage bonds, $40 million of 7.85% series due 2023, $40 million of 6.875% series due 2003 and $8 million of 6.55% series due 2003, for early redemption in May. Consequently, the bonds were reclassified as a current liability on the Consolidated Balance Sheets. OTHER MATTERS Market Risks The Company has certain market risks inherent in its business activities from changes in electricity commodity prices and interest rates. The Company's exposure to market risk from the trading of electricity and related financial derivative instruments, which are allocated to the Company through the American Electric Power System Power Pool, has not changed materially since December 31, 1998. Market risk represents the risk of loss that may impact the Company due to adverse changes in commodity market prices and interest rates. The exposure to changes in interest rates from the Company's short-term and long-term borrowings at March 31, 1999 is not materially different than at December 31, 1998. Year 2000 (Y2K) Readiness Disclosure On or about midnight on December 31, 1999, digital computing systems may begin to produce erroneous results or fail, unless these systems are modified or replaced, because such systems may be programmed incorrectly and interpret the date of January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems may fail to detect that the year 2000 is a leap year. Problems can also arise earlier than January 1, 2000, as dates in the next millennium are entered into non-Y2K ready programs. Readiness Program - Internally, the Company, through the AEP System, is modifying or replacing its computer hardware and software programs to minimize Y2K-related failures and repair such failures if they occur. This includes both information technology (IT) systems, which are mainframe and client server applications, and embedded logic (non-IT) systems, such as process controls for energy production and delivery. Externally, the problem is being addressed with entities that interact with the Company, including suppliers, customers, creditors, financial service organizations and other parties essential to the Company's operations. In the course of the external evaluation, the Company has sought written assurances from third parties regarding their state of Y2K readiness. Another issue we are addressing is the impact of electric power grid problems that may occur outside of our transmission system. The Company, along with other electric utilities in North America, regularly submits information to the North American Electric Reliability Council (NERC) as part of NERC's Y2K readiness program. NERC then publicly reports summary information to the U.S. Department of Energy (DOE) regarding the Y2K readiness of electric utilities. AEP participated in an industry-wide NERC-sponsored drill on April 9, 1999 simulating the partial loss of voice and data communications. There were no major problems encountered with relaying information with the use of backup telecommunications systems. AEP and other utilities plan to participate in a more comprehensive second NERC-sponsored drill on September 8-9, 1999, to prepare for operations under Y2K conditions. The NERC report, dated April 30, 1999 and entitled: Preparing the Electric Power Systems of North America for Transition to the Year 2000 - A Status Report and Work Plan, First Quarter 1999, states that: "With more than 75% of mission critical components tested through March 31, 1999, findings in the field continue to indicate that the transition through critical Y2K dates is expected to have minimal impact on electric system operations in North America." The report also indicates that, "the risk of electrical outages by Y2K appears to be no higher than the risks we already experience" from incidents such as severe wind, ice, floods, equipment failures and power shortages during an extremely hot or cold period. Through the Electric Power Research Institute, an electric utility industry-wide effort has been established to deal with Y2K problems affecting embedded systems. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. The state regulatory commissions in the Company's service territory are also reviewing the Y2K readiness of the Company. Company's State of Readiness - Work has been prioritized in accordance with business risk. The highest priority has been assigned to activities that potentially affect safety, the physical generation and delivery of energy, and communications; followed by back office activities such as customer service/billing, regulatory reporting, internal reporting and administrative activities (e.g., payroll, procurement, accounts payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations. The following chart shows our progress toward becoming ready for the Y2K as of March 31, 1999: IT SYSTEMS NON-IT SYSTEMS COMPLETION COMPLETION DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE Launch: Initiation of 2/24/1998 100% 5/31/1998 100% the Year 2000 activities within the organization. Establishment of organizational structure, personnel assignments and budget for the workgroup. Continuous management update and awareness program. Inventory and Assessment: Identifying all Company 7/31/1998 100% 2/15/1999 100% computer systems that could be affected by the millennium change. Prioritize repair efforts based upon criticality to maintaining ongoing operations. Remediation/Testing: The process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65% replacing or retiring 94% those mission critical and high priority digital-based systems with problems Client processing dates in the Server: Year 2000. Testing these 56% systems to ensure that after modifications have been implemented correct date processing occurs and full functionality has been maintained. *The Company is upgrading its 800 MHz trunked radio system, a mission critical non-IT system, for Y2K readiness and it is anticipated that the upgrade should be complete by September 30, 1999. The Company continues to make steady progress toward the June 30, 1999 target date and anticipates completing the remediation/testing work for mission critical and high-priority systems by the June 30, 1999 target date except as noted in the table. Costs to Address the Company's Year 2000 Issues - Through March 31, 1999, the Company has spent $8 million on the Year 2000 project and, estimates spending an additional $9 million to $12 million to achieve Y2K readiness. Most Y2K costs are for software modifications, IT consultants and salaries and are expensed; however, in certain cases the Company has acquired hardware that was capitalized. The Company intends to fund these expenditures through internal sources. Although significant, the cost of becoming Y2K compliant is not expected to have a material impact on the Company's results of operations, cash flows or financial condition. Risks of the Company's Y2K Issues - The applications posing the greatest business risk to the Company's operations should they experience Y2K problems are: Automated power generation, transmission and distribution systems Telecommunications systems Energy trading systems Time-in-use, demand and remote metering systems for commercial and industrial customers and Work management and billing systems. The potential problems related to erroneous processing by, or failure of, these systems are: Power service interruptions to customers Interrupted revenue data gathering and collection Poor customer relations resulting from delayed billing and settlement. Although it is difficult to hypothesize a most reasonably likely worst case Y2K scenario with any degree of certainty, management believes that such a scenario would be small, localized interruptions of service, which would be restored. In addition, although relationships with third parties, such as suppliers, customers and other electric utilities, are being monitored, these third parties nonetheless represent a risk that cannot be assessed with precision or controlled with certainty. Due to the complexity of the problem and the interdependent nature of computer systems, if our corrective actions, and/or the actions of others who impact the AEP System's operations but are not affiliated with the AEP System, fail for critical applications, Y2K-related issues may materially adversely affect the Company. Company's Contingency Plans - To address possible failures of electric generation and delivery of electrical energy due to Y2K related failures, we have established a draft Y2K contingency plan and submitted it to the East Central Area Reliability Council in December 1998 as part of NERC's review of regional and individual electric utility contingency plans in 1999. NERC's target date is June 1999 for the completion of this contingency plan. In addition, the Company intends to establish contingency plans for its business units to address alternatives if Y2K related failures occur. Contingency plans will be developed by the end of 1999. The Company's plans build upon the disaster recovery, system restoration, and contingency planning that we have had in place and include: Availability of additional power generation reserves. Coal inventory of approximately 45 days of normal usage. Identifying critical operational locations, with key employees on duty at those locations during the Y2K transition. PART II. OTHER INFORMATION Item 5. Other Information. American Electric Power Company, Inc. ("AEP") and Appalachian Power Company ("APCo") Reference is made to pages 17 and 18 of the Annual Report on Form 10-K for the year ended December 31, 1998 ("1998 10-K") for a discussion of APCo's proposed transmission facilities. On May 7, 1999, APCo filed its report on the Wyoming-Jacksons Ferry 765kV line with the State Corporation Commission of Virginia as requested by the Hearing Examiner in September 1998. The report states that the Wyoming-Jacksons Ferry line would cost approximately $232,000,000 and recommends the use of a 90-mile long corridor. The revised estimated cost for the Wyoming-Cloverdale line is $283,000,000. 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 pages 30 and 31 of the 1998 10-K for a discussion of the NOx SIP Call issued by the U.S. Environmental Protection Agency ("Federal EPA") and the Section 126 petitions filed by eight northeastern states. In April 1999, the states of Maryland and New Jersey also filed Section 126 petitions. On April 30, 1999, Federal EPA took final action with respect to the Section 126 petitions filed by the eight northeastern states. Federal EPA determined that six of the eight petitions were partially approvable, thus triggering a determination that the coal-fired generating plants in upwind states (including those of the AEP System) would be subject to a 0.15 lbs. of NOx per million Btu of heat input emission rate. This emission rate will become effective if the states in which the sources are located do not submit an approvable State Implementation Plan by September 30, 1999 and if Federal EPA elects not to adopt a Federal Implementation Plan by November 30, 1999. Reference is made to pages 31 and 32 of the 1998 10-K for a discussion of global climate change. As of April 9, 1999, 84 countries have signed the Kyoto Protocol and 8 countries have ratified it. Reference is made to page 33 of the 1998 10-K for a discussion of a request issued to AEP under Section 114 of the Clean Air Act focused on assessing compliance with the New Source Review and Performance Standard provisions. In April 1999, Federal EPA, Regions III and V, issued additional requests seeking identification of personnel at Sporn, Mitchell and Muskingum River plants having knowledge of plant operations, including production, maintenance and staff functions. Federal EPA has also requested information regarding projects at Tanners Creek Plant. AEP and OPCo Reference is made to page 42 of the 1998 10-K for a discussion of litigation with Ormet Corporation involving the ownership of sulfur dioxide allowances. On March 25, 1999, Ormet appealed the March 1999 District Court's decision to the U.S. Court of Appeals for the Fourth Circuit. The District Court decision had granted summary judgment to OPCo and the AEP Service Corporation. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 12 - Statement re: Computation of Ratios. AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo Exhibit 27 - Financial Data Schedule. (b) Reports on Form 8-K: AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo No reports on Form 8-K were filed during the quarter ended March 31, 1999. Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/ Armando A. Pena By: /s/ Leonard V. Assante Armando A. Pena Leonard V. Assante Treasurer Controller and Chief Accounting Officer (Duly Authorized Officer) (Chief Accounting Officer) AEP GENERATING COMPANY APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY By: /s/ Armando A. Pena By: /s/ Leonard V. Assante Armando A. Pena Leonard V. Assante Vice President, Treasurer, Controller and and Chief Financial Officer Chief Accounting Officer (Duly Authorized Officer) (Chief Accounting Officer) Date: May 12, 1999 II-3 EX-12 2 EXHIBIT 12 APPALACHIAN POWER COMPANY Computation of Consolidated Ratio of Earnings to Fixed Charges (in thousands except ratio data)
Twelve Months Year Ended December 31, Ended 1994 1995 1996 1997 1998 3/31/99 Fixed Charges: Interest on First Mortgage Bonds. . . . . . . . $ 75,815 $ 80,777 $ 82,082 $ 81,009 $ 72,057 $ 69,886 Interest on Other Long-term Debt. . . . . . . . 16,415 16,404 18,025 28,163 40,642 43,597 Interest on Short-term Debt . . . . . . . . . . 3,366 5,119 3,639 4,569 4,245 3,514 Miscellaneous Interest Charges. . . . . . . . . 3,913 5,323 7,327 6,857 11,470 12,061 Estimated Interest Element in Lease Rentals . . 7,700 7,000 6,600 6,000 5,900 5,900 Total Fixed Charges. . . . . . . . . . . . $107,209 $114,623 $117,673 $126,598 $134,314 $134,958 Earnings: Net Income. . . . . . . . . . . . . . . . . . . $102,345 $115,900 $133,689 $120,514 $ 93,330 $ 99,392 Plus Federal Income Taxes . . . . . . . . . . . 39,599 53,355 65,801 54,835 43,941 50,064 Plus State Income Taxes . . . . . . . . . . . . 5,910 7,273 10,180 8,109 6,845 6,368 Plus Fixed Charges (as above) . . . . . . . . . 107,209 114,623 117,673 126,598 134,314 134,958 Total Earnings . . . . . . . . . . . . . . $255,063 $291,151 $327,343 $310,056 $278,430 $290,782 Ratio of Earnings to Fixed Charges. . . . . . . . 2.37 2.54 2.78 2.44 2.07 2.15
EX-27 3 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000006879 APPALACHIAN POWER COMPANY 1,000 3-MOS DEC-31-1998 MAR-31-1999 PER-BOOK 3,103,102 120,748 458,301 43,529 424,314 4,149,994 260,458 663,743 187,699 1,111,900 22,310 19,353 1,395,477 0 0 57,275 157,239 0 51,200 12,860 1,322,380 4,149,994 427,702 25,804 330,291 356,095 71,607 (1,088) 70,519 31,258 39,261 675 38,586 30,348 17,473 116,389 0 0 All common stock owned by parent company; no EPS required.
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