-----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, W2E5zlpwJ45hoDlFY9LndoZBgLs3KQ6WgGtBEvonjVKMQmdbngY1qvb5pt//V4Nh uz5gRv/Crzg3nA096iPJyg== 0000004904-96-000078.txt : 19960816 0000004904-96-000078.hdr.sgml : 19960816 ACCESSION NUMBER: 0000004904-96-000078 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19960630 FILED AS OF DATE: 19960814 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMERICAN ELECTRIC POWER COMPANY INC CENTRAL INDEX KEY: 0000004904 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 134922640 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03525 FILM NUMBER: 96613643 BUSINESS ADDRESS: STREET 1: 1 RIVERSIDE PLZ CITY: COLUMBUS STATE: OH ZIP: 43215 BUSINESS PHONE: 6142231000 FORMER COMPANY: FORMER CONFORMED NAME: KINGSPORT UTILITIES INC DATE OF NAME CHANGE: 19660906 10-Q 1 THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended June 30, 1996 [ ] 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 31-4154203 (An Ohio Corporation) 215 North Front Street, Columbus, Ohio 43215 Telephone (614) 464-7700 1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455 (An Indiana Corporation) One Summit Square P.O. Box 60, Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1701 Central Avenue, Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 301 Cleveland Avenue S.W., Canton, Ohio 44702 Telephone (330) 456-8173 AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at July 31, 1996 was 187,435,000. /TABLE AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 30, 1996 INDEX
Page Part I. FINANCIAL INFORMATION American Electric Power Company, Inc. and Subsidiary Companies: Consolidated Statements of Income and Consolidated 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-6 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . A-7 - A-9 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-6 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . C-7 - C-9 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 Management's Narrative Analysis of Results of Operations . . D-6 - 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 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . . E-6 - E-8 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 Management's Narrative Analysis of Results of Operations . . F-6 - F-7 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 30, 1996 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 Management's Discussion and Analysis of Results of Operations and Financial Condition . . . . . . . . . . . G-6 - G-8 Part II. OTHER INFORMATION Item 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 - II-3 Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 - II-4 Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4 SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-5 This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in thousands, except per-share amounts) (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 OPERATING REVENUES . . . . . . . . . .$1,400,941 $1,305,342 $2,918,722 $2,721,511 OPERATING EXPENSES: Fuel and Purchased Power . . . . . . 404,914 357,055 845,891 769,042 Other Operation. . . . . . . . . . . 300,723 289,865 604,431 551,817 Maintenance. . . . . . . . . . . . . 139,043 131,388 244,466 261,996 Depreciation and Amortization. . . . 149,414 147,243 298,528 294,420 Taxes Other Than Federal Income Taxes. . . . . . . . . . . . 120,990 116,757 248,616 246,230 Federal Income Taxes . . . . . . . . 65,232 51,750 164,043 129,166 TOTAL OPERATING EXPENSES . . 1,180,316 1,094,058 2,405,975 2,252,671 OPERATING INCOME . . . . . . . . . . . 220,625 211,284 512,747 468,840 NONOPERATING INCOME (LOSS) . . . . . . 1,030 83 (97) 4,881 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS . . . . . . . . . 221,655 211,367 512,650 473,721 INTEREST CHARGES . . . . . . . . . . . 98,363 100,782 198,388 201,256 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES . . . . . . . . . . . 10,626 14,107 21,584 28,137 NET INCOME . . . . . . . . . . . . . .$ 112,666 $ 96,478 $ 292,678 $ 244,328 AVERAGE NUMBER OF SHARES OUTSTANDING . 187,104 185,671 186,913 185,494 EARNINGS PER SHARE . . . . . . . . . . $0.60 $0.52 $1.57 $1.32 CASH DIVIDENDS PAID PER SHARE. . . . . $0.60 $0.60 $1.20 $1.20 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . .$1,477,852 $1,362,170 $1,409,645 $1,325,581 NET INCOME . . . . . . . . . . . . . . 112,666 96,478 292,678 244,328 DEDUCTIONS: Cash Dividends Declared. . . . . . . 112,205 111,352 224,188 222,495 Other. . . . . . . . . . . . . . . . 120 36 (58) 154 BALANCE AT END OF PERIOD . . . . . . .$1,478,193 $1,347,260 $1,478,193 $1,347,260 See Notes to Consolidated Financial Statements. /TABLE AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . . $ 9,266,447 $ 9,238,843 Transmission . . . . . . . . . . . . . . . . . . . . . 3,341,340 3,316,664 Distribution . . . . . . . . . . . . . . . . . . . . . 4,274,741 4,184,251 General (including mining assets and nuclear fuel) . . 1,495,849 1,442,086 Construction Work in Progress. . . . . . . . . . . . . 304,473 314,118 Total Electric Utility Plant . . . . . . . . . 18,682,850 18,495,962 Accumulated Depreciation and Amortization. . . . . . . 7,338,529 7,111,123 NET ELECTRIC UTILITY PLANT . . . . . . . . . . 11,344,321 11,384,839 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . 857,200 825,781 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . . 110,414 79,955 Accounts Receivable (net). . . . . . . . . . . . . . . 544,950 492,283 Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 272,925 271,933 Materials and Supplies . . . . . . . . . . . . . . . . 249,437 251,051 Accrued Utility Revenues . . . . . . . . . . . . . . . 171,650 207,919 Prepayments and Other. . . . . . . . . . . . . . . . . 143,619 98,717 TOTAL CURRENT ASSETS . . . . . . . . . . . . . 1,492,995 1,401,858 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . 1,917,335 1,979,446 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . 245,711 310,377 TOTAL. . . . . . . . . . . . . . . . . . . . $15,857,562 $15,902,301 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock-Par Value $6.50: 1996 1995 Shares Authorized . . . .300,000,000 300,000,000 Shares Issued . . . . . .196,434,992 195,634,992 (8,999,992 shares were held in treasury) . . . . . .$ 1,276,827 $ 1,271,627 Paid-in Capital. . . . . . . . . . . . . . . . . . . . 1,687,101 1,658,524 Retained Earnings. . . . . . . . . . . . . . . . . . . 1,478,193 1,409,645 Total Common Shareholders' Equity. . . . . . . 4,442,121 4,339,796 Cumulative Preferred Stocks of Subsidiaries: Not Subject to Mandatory Redemption. . . . . . . . . 118,240 148,240 Subject to Mandatory Redemption. . . . . . . . . . . 515,082 515,085 Long-term Debt . . . . . . . . . . . . . . . . . . . . 4,766,759 4,920,329 TOTAL CAPITALIZATION . . . . . . . . . . . . . 9,842,202 9,923,450 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . 927,744 884,707 CURRENT LIABILITIES: Preferred Stock and Long-term Debt Due Within One Year 55,824 144,597 Short-term Debt. . . . . . . . . . . . . . . . . . . . 526,471 365,125 Accounts Payable . . . . . . . . . . . . . . . . . . . 177,719 220,142 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 370,524 420,192 Interest Accrued . . . . . . . . . . . . . . . . . . . 81,018 80,848 Obligations Under Capital Leases . . . . . . . . . . . 97,597 89,692 Other. . . . . . . . . . . . . . . . . . . . . . . . . 284,709 304,466 TOTAL CURRENT LIABILITIES. . . . . . . . . . . 1,593,862 1,625,062 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . 2,631,704 2,656,651 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . 418,190 430,041 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . 245,236 249,875 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . 198,624 132,515 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . . . . . .$15,857,562 $15,902,301 See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . .$ 292,678 $ 244,328 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . . 294,865 285,933 Deferred Federal Income Taxes. . . . . . . . . . . . . . . (9,048) 622 Deferred Investment Tax Credits. . . . . . . . . . . . . . (11,760) (11,903) Amortization of Deferred Property Taxes. . . . . . . . . . 74,709 72,657 Amortization of Operating Expenses and Carrying Charges (net). . . . . . . . . . . . . . . . . 18,183 35,448 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . . (52,667) (21,648) Fuel, Materials and Supplies . . . . . . . . . . . . . . . 622 (39,309) Accrued Utility Revenues . . . . . . . . . . . . . . . . . 36,269 12,185 Prepayments and Other Current Assets . . . . . . . . . . . (44,902) (51,879) Accounts Payable . . . . . . . . . . . . . . . . . . . . . (42,423) (86,474) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . (49,668) (97,782) Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . 26,812 - Other (net). . . . . . . . . . . . . . . . . . . . . . . . . 20,615 (8,534) Net Cash Flows From Operating Activities . . . . . . . 554,285 333,644 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . . (215,227) (280,956) Proceeds from Sale of Property and Other . . . . . . . . . . 6,670 10,551 Net Cash Flows Used For Investing Activities . . . . . (208,557) (270,405) FINANCING ACTIVITIES: Issuance of Common Stock . . . . . . . . . . . . . . . . . . 33,121 23,371 Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 309,404 264,415 Change in Short-term Debt (net). . . . . . . . . . . . . . . 161,346 113,890 Retirement of Cumulative Preferred Stock . . . . . . . . . . (38,057) - Retirement of Long-term Debt . . . . . . . . . . . . . . . . (556,895) (176,088) Dividends Paid on Common Stock . . . . . . . . . . . . . . . (224,188) (222,495) Net Cash Flows From (Used For) Financing Activities. . (315,269) 3,093 Net Increase in Cash and Cash Equivalents. . . . . . . . . . . 30,459 66,332 Cash and Cash Equivalents at Beginning of Period . . . . . . . 79,955 62,866 Cash and Cash Equivalents at End of Period . . . . . . . . . .$ 110,414 $ 129,198 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $191,603,000 and $197,982,000 and for income taxes was $138,641,000 and $151,158,000 in 1996 and 1995, respectively. Noncash acquisitions under capital leases were $83,502,000 and $49,813,000 in 1996 and 1995, respectively. See Notes to Consolidated Financial Statements. /TABLE AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state-ments should be read in conjunction with the 1995 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. 2. FINANCING AND RELATED ACTIVITIES During the first six months of 1996, subsidiaries issued $310 million principal amount of long-term debt: two series of first mortgage bonds totaling $200 million at 6-3/8% and 6.8% due in 2001 and 2006, respectively; $40 million of junior subordinated deferrable interest debentures at 8% due in 2026; two 6.75% term loans totaling $20 million due 2001 and two term loans totaling $50 million at 6.42% and 6.57% due in 1999 and 2000, respectively. The proceeds were used during 1996 to redeem the outstanding shares of two series of $100 par value cumulative preferred stock: 75,000 shares at 9.5% and 300,000 shares at 7.08%; and to retire $551 million principal amount of long-term debt: $492 million of first mortgage bonds with interest rates ranging from 5% to 9-7/8% with due dates ranging from 1996 to 2022; $31 million of sinking fund debentures with interest rates ranging from 5-1/8% to 7-7/8% with due dates ranging from 1996 to 1999; and $28 million of term loans with interest rates ranging from 5.79% to 10.78% all at maturity. The redemption of three series of first mortgage bonds in 1996, a 7-7/8% series and a 7-1/2% series both due in 2002 and a 9-7/8% series due in 2020, reduced the restriction on subsidiaries use of retained earnings for the payment of cash dividends on their common stock from $230 million to $30 million. 3. CONTINGENCIES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and in 1996 as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. The Company continues to be involved in certain other matters discussed in the 1995 Annual Report. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 RESULTS OF OPERATIONS Net income increased 17% or $16.2 million in the comparative second quarter and 20% or $48.4 million in the comparative year-to-date period primarily due to an increase in energy sales in both periods as a result of growth in the number of customers, increased customer usage mainly due to weather, and increased weather-related wholesale sales to other utilities. Income statement items which changed significantly were: Increase (Decrease) Second Quarter Year-To-Date (in millions) % (in millions) % Operating Revenues . . . . . . $95.6 7 $197.2 7 Fuel and Purchased Power Expense. . . . . . . . 47.9 13 76.8 10 Other Operation Expense. . . . 10.9 4 52.6 10 Maintenance Expense. . . . . . 7.7 6 (17.5) (7) Federal Income Taxes . . . . . 13.5 26 34.9 27 Preferred Stock Dividend Requirements of Subsidiaries. (3.5) (25) (6.6) (23) Operating revenues increased in both periods as a result of increased energy sales to retail and wholesale customers and an increase in other service revenues. Retail energy sales increased 4% in the comparative second quarter period and 5% in the comparative year-to-date period reflecting increased energy sales in all major retail customer classes largely as a result of increased usage due to the weather and growth in the number of customers. Energy sales to wholesale customers were up 62% in the second quarter of 1996 and 53% in the year-to-date period largely as a result of weather. Higher transmission and other service revenues from wholesale customers contributed to the increased revenues in both comparative periods reflecting the increased demand. The increase in fuel and purchased power expense was mainly due to the increase in energy demand. Also contributing to the rise in fuel expense during both comparative periods was the increased use of higher cost coal-fired generation due to a reduction in the availability of low-cost nuclear generation resulting from a refueling outage at a nuclear unit in the second quarter of 1996. Other operation expense increased in the comparative second quarter reflecting an increase in the cost of pollution control emission allowances and increased rent expense. The increase in rent expense resulted from a favorable determination by the Indiana state tax department that resulted in the reversal in the second quarter of 1995 of a provision for state taxes applicable to the Rockport Plant Unit 2 operating lease. Also contributing to the rise in other operation expense during the first six months of this year were increased employee benefits expenses, rent and other operating costs of the recently installed Gavin Plant scrubbers and the amortization, commensurate with recovery in rates, of previously deferred Gavin scrubber expenses. Maintenance expense rose in the comparative second quarter mainly due to a 1996 maintenance outage at both of the Gavin units. In the year-to-date period, maintenance expense declined primarily due to the reversal in March 1996 of a loss contingency recorded in March 1995 for deferred Virginia retail incremental storm damage expenses, reductions in the number of employees performing maintenance on the Company's nuclear plant and lower payments for contract labor at the nuclear plant. The increase in both periods in federal income tax expense attributable to operations was due to an increase in pre-tax operating income and, in the comparative second quarter period, to changes in certain book/tax differences accounted for on a flow-through basis for ratemaking and financial reporting purposes. Preferred stock dividend requirements of the subsidiaries decreased in both comparative periods reflecting preferred stock redemptions in November 1995 and the first half of 1996. FINANCIAL CONDITION Total plant and property additions including capital leases for the first six months were $300 million. During the first six months of 1996 subsidiaries issued $310 million principal amount of long-term debt at interest rates ranging from 6-3/8% to 8%; retired $551 million principal amount of long-term debt with interest rates ranging from 5% to 10.78%; redeemed 375,000 shares of $100 par value cumulative preferred stock at 9.5% and 7.08% and increased short-term debt by $161 million. NEW FERC RULES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) OPERATING REVENUES . . . . . . . . . . . $55,313 $53,819 $112,797 $113,994 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 21,736 22,078 45,268 48,640 Rent - Rockport Plant Unit 2 . . . . . 17,071 15,474 34,148 32,619 Other Operation. . . . . . . . . . . . 2,962 3,005 6,111 5,677 Maintenance. . . . . . . . . . . . . . 3,883 3,458 7,376 6,341 Depreciation . . . . . . . . . . . . . 5,413 5,417 10,826 10,834 Taxes Other Than Federal Income Taxes. 907 299 1,882 1,278 Federal Income Taxes . . . . . . . . . 886 746 1,937 1,563 TOTAL OPERATING EXPENSES . . . 52,858 50,477 107,548 106,952 OPERATING INCOME . . . . . . . . . . . . 2,455 3,342 5,249 7,042 NONOPERATING INCOME. . . . . . . . . . . 834 992 1,624 1,821 INCOME BEFORE INTEREST CHARGES . . . . . 3,289 4,334 6,873 8,863 INTEREST CHARGES . . . . . . . . . . . . 1,058 2,400 2,144 4,810 NET INCOME . . . . . . . . . . . . . . . $ 2,231 $ 1,934 $ 4,729 $ 4,053 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $1,953 $4,387 $1,955 $4,268 NET INCOME . . . . . . . . . . . . . . . 2,231 1,934 4,729 4,053 CASH DIVIDENDS DECLARED. . . . . . . . . 2,000 2,000 4,500 4,000 BALANCE AT END OF PERIOD . . . . . . . . $2,184 $4,321 $2,184 $4,321 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Financial Statements. /TABLE AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production. . . . . . . . . . . . . . . . . . . . . . . $627,581 $627,298 General . . . . . . . . . . . . . . . . . . . . . . . . 2,910 2,919 Construction Work in Progress . . . . . . . . . . . . . 1,825 1,397 Total Electric Utility Plant. . . . . . . . . . 632,316 631,614 Accumulated Depreciation. . . . . . . . . . . . . . . . 228,273 218,055 NET ELECTRIC UTILITY PLANT. . . . . . . . . . . 404,043 413,559 CURRENT ASSETS: Cash and Cash Equivalents . . . . . . . . . . . . . . . 72 22 Accounts Receivable . . . . . . . . . . . . . . . . . . 19,637 19,028 Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . 20,914 19,008 Materials and Supplies. . . . . . . . . . . . . . . . . 4,745 4,820 Prepayments . . . . . . . . . . . . . . . . . . . . . . 521 673 TOTAL CURRENT ASSETS. . . . . . . . . . . . . . 45,889 43,551 REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . 5,967 6,076 DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . 3,229 1,693 TOTAL . . . . . . . . . . . . . . . . . . . . $459,128 $464,879 See Notes to Financial Statements.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (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 . . . . . . . . . . . . . . . . . . . . 47,235 47,735 Retained Earnings . . . . . . . . . . . . . . . . . . . 2,184 1,955 Total Common Shareholder's Equity . . . . . . . 50,419 50,690 Long-term Debt. . . . . . . . . . . . . . . . . . . . . 89,546 89,538 TOTAL CAPITALIZATION. . . . . . . . . . . . . . 139,965 140,228 OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . 1,814 1,830 CURRENT LIABILITIES: Short-term Debt - Notes Payable . . . . . . . . . . . . 17,325 21,725 Accounts Payable. . . . . . . . . . . . . . . . . . . . 8,510 9,094 Taxes Accrued . . . . . . . . . . . . . . . . . . . . . 6,384 2,997 Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . 4,963 4,963 Other . . . . . . . . . . . . . . . . . . . . . . . . . 2,631 4,508 TOTAL CURRENT LIABILITIES . . . . . . . . . . . 39,813 43,287 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . 147,257 150,043 REGULATORY LIABILITIES: Deferred Investment Tax Credits . . . . . . . . . . . . 75,262 76,949 Amounts Due to Customers for Income Taxes . . . . . . . 35,870 36,517 Other . . . . . . . . . . . . . . . . . . . . . . . . . 242 201 TOTAL REGULATORY LIABILITIES. . . . . . . . . . 111,374 113,667 DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . 18,905 15,824 TOTAL . . . . . . . . . . . . . . . . . . . . $459,128 $464,879 See Notes to Financial Statements. /TABLE AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 4,729 $ 4,053 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . 10,826 10,834 Deferred Federal Income Taxes. . . . . . . . . . . . . 2,434 3,006 Deferred Investment Tax Credits. . . . . . . . . . . . (1,687) (1,691) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2. . . . . . . . (2,786) (2,786) Deferred Property Taxes. . . . . . . . . . . . . . . . (1,562) (1,533) Changes in Certain Current Assets and Liabilities: Accounts Receivable. . . . . . . . . . . . . . . . . . (609) (842) Fuel, Materials and Supplies . . . . . . . . . . . . . (1,831) (1,017) Accounts Payable . . . . . . . . . . . . . . . . . . . (584) (3,157) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 3,387 789 Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . - (1,527) Other (net). . . . . . . . . . . . . . . . . . . . . . . (1,616) (2,067) Net Cash Flows From Operating Activities . . . . . 10,701 4,062 INVESTING ACTIVITIES - Construction Expenditures . . . . . (1,251) (2,566) FINANCING ACTIVITIES: Capital Contributions Returned to Parent Company . . . . (500) - Change in Short-term Debt (net). . . . . . . . . . . . . (4,400) 2,500 Dividends Paid . . . . . . . . . . . . . . . . . . . . . (4,500) (4,000) Net Cash Flows Used For Financing Activities . . . (9,400) (1,500) Net Increase (Decrease) in Cash and Cash Equivalents . . . 50 (4) Cash and Cash Equivalents at Beginning of Period . . . . . 22 7 Cash and Cash Equivalents at End of Period . . . . . . . . $ 72 $ 3 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $2,035,000 and $4,632,000 and for income taxes was $(764,000) and $(1,269,000) in 1996 and 1995, respectively. See Notes to Financial Statements.
AEP GENERATING COMPANY NOTES TO FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1995 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. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies and one unaffiliated utility pursuant to Federal Energy Regulatory Commission (FERC) approved long-term unit power agreements. The unit power agreements provide for recovery of costs including a FERC approved rate of return on common equity and a return on other capital net of temporary cash investments. Net income increased $0.3 million or 15% in the comparative second quarter and $0.7 million or 17% in the comparative year-to-date period resulting from the recovery of interest expense through the return on other capital component of the unit power bills compared to 1995 when the unit power agreement mechanism prevented the Company from recovering all interest costs in the unit power bills. Income statement items which changed significantly were as follows: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . . $ 1.5 3 $(1.2) (1) Fuel Expense . . . . . . . . (0.3) (2) (3.4) (7) Rent Expense-Rockport Plant Unit 2. . . . . . . . . . . 1.6 10 1.5 5 Other Operation Expense. . . 0.0 N.M. 0.4 8 Maintenance Expense. . . . . 0.4 12 1.0 16 Taxes Other Than Federal Income Taxes . . . . . . . 0.6 203 0.6 47 Federal Income Taxes . . . . 0.1 19 0.4 24 Nonoperating Income. . . . . (0.2) (16) (0.2) (11) Interest Charges . . . . . . (1.3) (56) (2.7) (55) N.M. = Not Meaningful The increase in operating revenues for the second quarter reflects increased recoverable operating expenses, primarily rent expense for Rockport Plant Unit 2, offset in part by a reduction in the return on other capital due to a decrease in long-term debt interest expense. The revenue decrease in the year-to-date period resulted from the reduction in the return on other capital, partially offset by an increase in recoverable operating expenses. The decline in fuel expense was attributable to a reduction in generation as Rockport Plant Unit 2 was out-of-service for planned general boiler inspection and repair during March and April 1996. Rent expense for Rockport Plant Unit 2 increased in both periods due to the effect of a favorable determination by the Indiana state tax department that resulted in a May 1995 reversal of a provision for Indiana gross income tax applicable to the lease. Other operation expense increased in the year-to-date period mainly due to increased AEP Service Corporation billings for managerial, engineering and other professional services; increased employee benefits expense caused primarily by a reduction in COLI death benefits; and the recording in 1996 of the expense of destroyed railroad coal cars. The increase in maintenance expense during the second quarter and year-to-date periods resulted from the general boiler inspection and repairs performed on Rockport Unit 2 in 1996. Taxes other than federal income taxes increased for both periods due to the effect of a favorable Indiana property tax accrual adjustment recorded in the second quarter of 1995. Federal income tax expense attributable to operations increased primarily due to an increase in pre-tax operating income. The decrease in nonoperating income for both periods reflects a decline in interest income earned on temporary cash investments as the amounts available for investment declined in 1996. Interest charges declined in both periods primarily due to refinancing of $90 million of long-term debt at lower variable rates and the retirement of $20 million of long-term debt in the third quarter of 1995. APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) OPERATING REVENUES . . . . . . . . . . . $379,887 $339,957 $820,859 $747,473 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 91,907 72,082 181,503 171,975 Purchased Power. . . . . . . . . . . . 76,510 72,894 167,637 136,852 Other Operation. . . . . . . . . . . . 61,066 55,942 123,809 105,915 Maintenance. . . . . . . . . . . . . . 36,225 32,962 59,376 69,426 Depreciation and Amortization. . . . . 33,168 33,338 66,041 66,428 Taxes Other Than Federal Income Taxes. 29,014 27,613 60,316 59,342 Federal Income Taxes . . . . . . . . . 8,778 6,287 35,321 29,552 TOTAL OPERATING EXPENSES . . . 336,668 301,118 694,003 639,490 OPERATING INCOME . . . . . . . . . . . . 43,219 38,839 126,856 107,983 NONOPERATING INCOME (LOSS) . . . . . . . (21) (3,804) 576 (4,639) INCOME BEFORE INTEREST CHARGES . . . . . 43,198 35,035 127,432 103,344 INTEREST CHARGES . . . . . . . . . . . . 27,092 26,549 55,702 52,921 NET INCOME . . . . . . . . . . . . . . . 16,106 8,486 71,730 50,423 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 4,100 4,097 8,201 8,201 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 12,006 $ 4,389 $ 63,529 $ 42,222 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $223,469 $217,485 $199,021 $206,361 NET INCOME . . . . . . . . . . . . . . . 16,106 8,486 71,730 50,423 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 27,075 26,709 54,150 53,418 Cumulative Preferred Stock . . . . . 3,917 3,919 7,834 7,838 Capital Stock Expense. . . . . . . . . 184 178 368 363 BALANCE AT END OF PERIOD . . . . . . . . $208,399 $195,165 $208,399 $195,165 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,863,422 $1,857,621 Transmission . . . . . . . . . . . . . . . . . . . . 1,045,165 1,041,415 Distribution . . . . . . . . . . . . . . . . . . . . 1,448,028 1,409,407 General. . . . . . . . . . . . . . . . . . . . . . . 182,296 169,602 Construction Work in Progress. . . . . . . . . . . . 74,856 80,391 Total Electric Utility Plant . . . . . . . . 4,613,767 4,558,436 Accumulated Depreciation and Amortization. . . . . . 1,741,060 1,694,746 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,872,707 2,863,690 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 30,111 31,523 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 15,310 8,664 Accounts Receivable (net). . . . . . . . . . . . . . 177,436 140,158 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 53,534 69,037 Materials and Supplies . . . . . . . . . . . . . . . 54,947 55,756 Accrued Utility Revenues . . . . . . . . . . . . . . 50,983 65,078 Prepayments. . . . . . . . . . . . . . . . . . . . . 19,371 8,579 TOTAL CURRENT ASSETS . . . . . . . . . . . . 371,581 347,272 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 430,754 435,352 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 55,159 57,541 TOTAL. . . . . . . . . . . . . . . . . . . $3,760,312 $3,735,378 See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (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. . . . . . . . . . . . . . . . . . . 550,419 525,051 Retained Earnings. . . . . . . . . . . . . . . . . . 208,399 199,021 Total Common Shareholder's Equity. . . . . . 1,019,276 984,530 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 55,000 55,000 Subject to Mandatory Redemption. . . . . . . . . . 190,082 190,085 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,299,447 1,278,433 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,563,805 2,508,048 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 94,768 102,178 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . - 7,251 Short-term Debt. . . . . . . . . . . . . . . . . . . 93,750 125,525 Accounts Payable . . . . . . . . . . . . . . . . . . 83,043 82,224 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 47,892 48,666 Customer Deposits. . . . . . . . . . . . . . . . . . 14,178 14,411 Interest Accrued . . . . . . . . . . . . . . . . . . 21,460 19,057 Revenue Refunds Accrued. . . . . . . . . . . . . . . 26,812 - Other. . . . . . . . . . . . . . . . . . . . . . . . 59,575 75,303 TOTAL CURRENT LIABILITIES. . . . . . . . . . 346,710 372,437 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 656,494 656,006 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 86,892 89,682 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 11,643 7,027 CONTINGENCIES (Note 4) TOTAL. . . . . . . . . . . . . . . . . . . $3,760,312 $3,735,378 See Notes to Consolidated Financial Statements. /TABLE APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 71,730 $ 50,423 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . . 66,694 67,262 Deferred Federal Income Taxes. . . . . . . . . . . . . . . 2,030 (3,365) Deferred Investment Tax Credits. . . . . . . . . . . . . . (2,409) (2,430) Storm Damage Expense Amortization (Deferrals). . . . . . . (2,003) 11,548 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . . (37,278) (2,793) Fuel, Materials and Supplies . . . . . . . . . . . . . . . 16,312 (16,826) Accrued Utility Revenues . . . . . . . . . . . . . . . . . 14,095 9,383 Prepayments. . . . . . . . . . . . . . . . . . . . . . . . (10,792) (11,076) Accounts Payable . . . . . . . . . . . . . . . . . . . . . 819 (16,172) Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . 26,812 - Other (net). . . . . . . . . . . . . . . . . . . . . . . . . (9,135) 11,214 Net Cash Flows From Operating Activities . . . . . . . 136,875 97,168 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . . (74,210) (101,704) Proceeds from Sale of Property . . . . . . . . . . . . . . . 1,079 7,050 Net Cash Flows Used For Investing Activities . . . . . (73,131) (94,654) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . . 25,000 15,000 Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 200,825 128,785 Change in Short-term Debt (net). . . . . . . . . . . . . . . (31,775) (10,350) Retirement of Long-term Debt . . . . . . . . . . . . . . . . (189,164) (74,950) Dividends Paid on Common Stock . . . . . . . . . . . . . . . (54,150) (53,418) Dividends Paid on Cumulative Preferred Stock . . . . . . . . (7,834) (7,837) Net Cash Flows Used For Financing Activities . . . . . (57,098) (2,770) Net Increase (Decrease) in Cash and Cash Equivalents . . . . . 6,646 (256) Cash and Cash Equivalents at Beginning of Period . . . . . . . 8,664 5,297 Cash and Cash Equivalents at End of Period . . . . . . . . . . $ 15,310 $ 5,041 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $51,719,000 and $51,472,000 and for income taxes was $29,226,000 and $32,665,000 in 1996 and 1995, respectively. Noncash acquisitions under capital leases were $5,584,000 and $8,827,000 in 1996 and 1995, respectively. See Notes to Consolidated Financial Statements.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1995 Annual Report as incorporated in and filed with the Form 10-K. 2. RATE MATTERS Virginia On May 24, 1996 the Virginia State Corporation Commission (Virginia SCC) issued a final order and concluded that the Company was not entitled to a rate increase. The Company had requested a base rate increase of $15.7 million annually in September 1994 which included, among other things, recovery over three years of $23.9 million of incremental storm damages expenses deferred in 1994. The Virginia SCC had authorized the Company to collect the rate increase subject to refund beginning in November 1994. The Order also concluded that the Company had recovered $11.9 million of the 1994 deferred incremental storm damage expenses through existing rates. In accordance with the Order, the net deferred storm damage expenses will be amortized commensurate with recovery over a five-year period effective July 1, 1996. Therefore, the Company wrote off $11.9 million of deferred storm damages which were not recoverable and reversed $6.9 million of previously amortized storm damage. As of June 30, 1996 the revenue refund liability of $26.8 million, including interest of $1.7 million, had been provided for and the refund is to be completed by September 3, 1996. 3. FINANCING ACTIVITIES In February 1996 the Company redeemed $16 million of first mortgage bonds with interest rates ranging from 8.75% to 9-7/8% due 2020 through 2022. In March 1996 the Company issued $100 million of 6-3/8% Series First Mortgage Bonds due in 2001 and $100 million of 6.80% Series First Mortgage Bonds due in 2006. The proceeds were used to reduce outstanding short-term debt and in April and May 1996 to redeem $165 million of first mortgage bonds with interest rates ranging from 7-1/2% to 9-7/8% due 1998 through 2022. The April redemption of these first mortgage bonds removed the restriction on the use of retained earnings for common stock dividends. In June 1996, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in capital. 4. CONTINGENCIES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. The Company continues to be involved in certain other matters discussed in its 1995 Annual Report. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 RESULTS OF OPERATIONS Net income increased $7.6 million or 90% in the comparative second quarter and $21.3 million or 42% in the comparative year-to-date period as a result of increased demand for energy by residential and wholesale customers and an increase in nonoperating income due to the effect of a loss in 1995 resulting from the sale of coal-mining assets owned by the Company. Income statement lines which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . . $39.9 12 $73.4 10 Fuel Expense . . . . . . . . 19.8 28 9.5 6 Purchased Power Expense. . . 3.6 5 30.8 22 Other Operation Expense. . . 5.1 9 17.9 17 Maintenance Expense. . . . . 3.3 10 (10.1) (14) Taxes Other Than Federal Income Taxes . . . . . . . 1.4 5 1.0 2 Federal Income Taxes . . . . 2.5 40 5.8 20 Nonoperating Income (Loss) . 3.8 N.M. 5.2 N.M. N.M. = Not Meaningful Substantial increases in wholesale and retail energy sales resulted in the increases in revenues for the quarter and year-to-date period. Wholesale energy sales increased 98% in the quarter and 84% in the year-to-date period primarily due to increased energy sales to unaffiliated utilities by the AEP System Power Pool (Power Pool) resulting from unseasonable weather in 1996 and increased amounts of energy supplied to the Power Pool to meet the weather related load requirements of other Power Pool members. Residential and commercial sales increased 9% and 5%, respectively, in the second quarter and 12% and 6%, respectively, in the year-to-date period. The sales increases were due to growth in the number of customers and customer usage due mainly to unseasonable weather in 1996. The increase in fuel and purchased power expenses reflected the rise in energy demand which resulted in increased generation and additional energy purchases from the Power Pool to meet the increase in demand. Other operation expense increased in the comparative quarter and year-to-date periods primarily due to the expensing of $3.9 million of previously deferred research costs, an increase in employee benefit costs and the expensing of $2.8 million of previously capitalized software costs as a result of a final rate order from the Virginia State Corporation Commission (Virginia SCC). Maintenance expense increased for the quarter largely due to an increase in engineering and other professional services billed by the AEP Service Corporation. In the year-to-date period, the reversal in March 1996 of a $7.9 million loss provision for deferred Virginia retail incremental storm damage expenses recorded in March 1995 accounted for the decrease in maintenance expense. The provision was reversed as a result of a Virginia SCC Hearing Examiner's Report which was not the same as the final order. Taxes other than federal income taxes increased primarily due to the West Virginia business and occupation (B&O) tax. Prior to June 1995 the B&O tax was computed on the basis of generation; subsequently the tax was based on generating capacity. In 1995 the Company's generation was at a reduced level. The increase in federal income tax expense was primarily due to an increase in pre-tax operating income. FINANCIAL CONDITION Total plant and property additions including capital leases for the first six months of 1996 were $80 million. In March 1996, the Company issued $100 million of 6-3/8% Series First Mortgage Bonds due in 2001 and $100 million of 6.80% Series First Mortgage Bonds due in 2006. The proceeds were used to reduce outstanding short-term debt and in April and May 1996 to redeem $165 million of first mortgage bonds with interest rates ranging from 7-1/2% to 9-7/8% due 1998 through 2022. The redemption of these first mortgage bonds eliminated the restriction on the use of retained earnings for common stock dividends. In June 1996, the Company received a $25 million cash capital contribution from its parent which was credited to paid-in-capital. NEW FERC RULES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) OPERATING REVENUES . . . . . . . . . . . $269,023 $246,165 $540,063 $503,170 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 45,169 36,748 92,675 88,054 Purchased Power. . . . . . . . . . . . 39,971 41,180 83,440 73,099 Other Operation. . . . . . . . . . . . 46,844 44,541 91,008 89,603 Maintenance. . . . . . . . . . . . . . 17,409 18,586 31,332 33,989 Depreciation . . . . . . . . . . . . . 21,966 21,307 43,757 42,454 Amortization of Zimmer Plant Phase-in Costs . . . . . . . . 7,965 7,472 16,413 15,523 Taxes Other Than Federal Income Taxes. 28,088 27,161 56,195 54,192 Federal Income Taxes . . . . . . . . . 14,438 9,991 29,644 22,640 TOTAL OPERATING EXPENSES . . . 221,850 206,986 444,464 419,554 OPERATING INCOME . . . . . . . . . . . . 47,173 39,179 95,599 83,616 NONOPERATING INCOME (LOSS) . . . . . . . 385 1,073 (2,520) 2,439 INCOME BEFORE INTEREST CHARGES . . . . . 47,558 40,252 93,079 86,055 INTEREST CHARGES . . . . . . . . . . . . 20,062 19,702 40,457 39,980 NET INCOME . . . . . . . . . . . . . . . 27,496 20,550 52,622 46,075 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,374 3,203 3,044 6,406 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 26,122 $ 17,347 $ 49,578 $ 39,669 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $78,984 $51,288 $74,320 $46,976 NET INCOME . . . . . . . . . . . . . . . 27,496 20,550 52,622 46,075 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 18,969 17,975 37,938 35,950 Cumulative Preferred Stock . . . . . 1,422 3,203 2,844 6,406 Capital Stock Expense. . . . . . . . . 70 35 141 70 BALANCE AT END OF PERIOD . . . . . . . . $86,019 $50,625 $86,019 $50,625 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $1,489,791 $1,481,309 Transmission . . . . . . . . . . . . . . . . . . . . 320,010 314,413 Distribution . . . . . . . . . . . . . . . . . . . . 864,380 843,228 General. . . . . . . . . . . . . . . . . . . . . . . 124,518 117,185 Construction Work in Progress. . . . . . . . . . . . 56,825 64,073 Total Electric Utility Plant . . . . . . . . 2,855,524 2,820,208 Accumulated Depreciation . . . . . . . . . . . . . . 987,842 953,170 NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,867,682 1,867,038 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 25,133 25,950 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 9,371 10,577 Accounts Receivable (net). . . . . . . . . . . . . . 64,667 65,853 Fuel . . . . . . . . . . . . . . . . . . . . . . . . 21,387 24,316 Materials and Supplies . . . . . . . . . . . . . . . 23,973 23,519 Accrued Utility Revenues . . . . . . . . . . . . . . 41,088 40,389 Prepayments and Other. . . . . . . . . . . . . . . . 42,956 32,116 TOTAL CURRENT ASSETS . . . . . . . . . . . . 203,442 196,770 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 418,834 438,005 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 34,368 66,363 TOTAL. . . . . . . . . . . . . . . . . . . $2,549,459 $2,594,126 See Notes to Consolidated Financial Statements. /TABLE COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (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. . . . . . . . . . . . . . . . . . . 574,568 574,427 Retained Earnings. . . . . . . . . . . . . . . . . . 86,019 74,320 Total Common Shareholder's Equity. . . . . . 701,613 689,773 Cumulative Preferred Stock - Subject to Mandatory Redemption . . . . . . . . . . . . . . . 75,000 75,000 Long-term Debt . . . . . . . . . . . . . . . . . . . 896,953 990,796 TOTAL CAPITALIZATION . . . . . . . . . . . . 1,673,566 1,755,569 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 34,342 34,571 CURRENT LIABILITIES: Preferred Stock Due Within One Year. . . . . . . . . - 7,500 Long-term Debt Due Within One Year . . . . . . . . . 30,000 - Short-term Debt. . . . . . . . . . . . . . . . . . . 98,550 34,325 Accounts Payable . . . . . . . . . . . . . . . . . . 43,220 52,029 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 90,900 120,093 Interest Accrued . . . . . . . . . . . . . . . . . . 16,339 17,016 Other. . . . . . . . . . . . . . . . . . . . . . . . 24,542 30,955 TOTAL CURRENT LIABILITIES. . . . . . . . . . 303,551 261,918 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 457,038 464,413 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 59,186 61,010 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 21,776 16,645 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . . . . . $2,549,459 $2,594,126 See Notes to Consolidated Financial Statements.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 52,622 $ 46,075 Adjustments for Noncash Items: Depreciation . . . . . . . . . . . . . . . . . . . . . . 43,571 42,264 Deferred Federal Income Taxes. . . . . . . . . . . . . . (3,789) (2,804) Deferred Investment Tax Credits. . . . . . . . . . . . . (1,824) (1,834) Amortization of Deferred Property Taxes. . . . . . . . . 30,446 28,872 Amortization of Zimmer Plant Operating Expenses and Carrying Charges . . . . . . . . . . . . . . . . . . . 15,211 13,180 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 1,186 4,541 Fuel, Materials and Supplies . . . . . . . . . . . . . . 2,475 2,383 Accrued Utility Revenues . . . . . . . . . . . . . . . . (699) (3,665) Prepayments and Other Current Assets . . . . . . . . . . (10,840) (11,443) Accounts Payable . . . . . . . . . . . . . . . . . . . . (8,809) (6,366) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (29,193) (47,403) Other (net). . . . . . . . . . . . . . . . . . . . . . . . (2,732) (2,235) Net Cash Flows From Operating Activities . . . . . . 87,625 61,565 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (38,642) (47,067) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,301 2,262 Net Cash Flows Used For Investing Activities . . . . (36,341) (44,805) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . . 64,225 72,175 Retirement of Cumulative Preferred Stock . . . . . . . . . (7,500) - Retirement of Long-term Debt . . . . . . . . . . . . . . . (68,255) (50,000) Dividends Paid on Common Stock . . . . . . . . . . . . . . (37,938) (35,950) Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,022) (6,406) Net Cash Flows Used For Financing Activities . . . . (52,490) (20,181) Net Decrease in Cash and Cash Equivalents. . . . . . . . . . (1,206) (3,421) Cash and Cash Equivalents at Beginning of Period . . . . . . 10,577 14,065 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 9,371 $ 10,644 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $39,244,000 and $38,666,000 and for income taxes was $18,674,000 and $32,312,000 in 1996 and 1995, respectively. Noncash acquisitions under capital leases were $6,941,000 and $5,416,000 in 1996 and 1995, respectively. See Notes to Consolidated Financial Statements. /TABLE COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial statements should be read in conjunction with the 1995 Annual Report as incorporated in and filed with the Form 10-K. 2. FINANCING ACTIVITIES On June 12, 1996, the Company redeemed the entire $50 million outstanding principal amount of its 9.625% Series First Mortgage Bonds Due 2021 at the regular redemption price of 107.22%. The Company redeemed on August 1, 1996 the entire $30 million outstanding principal amount of the 9.31% Series First Mortgage Bonds Due 2001 at the regular redemption price of 102.66%. Therefore at June 30, 1996 this debt is classified as a current liability. 3. CONTINGENCIES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. The Company continues to be involved in certain other matters discussed in its 1995 Annual Report. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 Net income increased 34% in the second quarter and 14% on a year-to-date basis mainly due to increased energy sales. In the year-to-date period, the effect of the sales increase was partly offset by decreased nonoperating income due to provisions recorded in the first quarter for certain demand side management programs and for environmental remediation costs. Income statement lines which changed significantly were as follows: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . . $22.9 9 $36.9 7 Fuel Expense. . . . . . . . 8.4 23 4.6 5 Purchased Power Expense . . (1.2) (3) 10.3 14 Other Operation Expense . . 2.3 5 1.4 2 Maintenance Expense . . . . (1.2) (6) (2.7) (8) Amortization of Zimmer Plant Phase-in Costs . . . 0.5 7 0.9 6 Federal Income Taxes. . . . 4.4 45 7.0 31 Nonoperating Income (Loss). (0.7) (64) (5.0) N.M. N.M. = Not Meaningful The operating revenues increased in both comparative periods due to increased energy sales to both retail and wholesale customers. Energy sales to retail customers increased due mainly to unseasonable weather in 1996 and growth in the number of residential and commercial customers. Energy sales to wholesale customers doubled in both periods primarily due to an increase in sales made by the AEP System Power Pool (Power Pool) to unaffiliated utilities largely as a result of the unseasonable weather. The increase in fuel expense was due to increased generation resulting from the additional sales and an increased availability of generating capacity. In 1996 all generating units were in-service while in the second quarter of 1995 several Conesville Plant units and the Picway Plant were out of service for scheduled repairs to the boiler facilities. Purchased power expense increased significantly in the year-to-date period due to increased energy purchases from the Power Pool to supply the increased energy demands of retail and wholesale customers. The increase in other operation expense was mostly due to certain demand side management program expenses and rents for new customer service center equipment. Maintenance expense decreased due to a staffing reduction at the Company's power plants in the fourth quarter of 1995 as part of an AEP restructuring program to functionally realign operations and a reduction in plant maintenance work. Last year's maintenance expense included expenditures associated with the outages at the Conesville and Picway plants. The amortization of Zimmer Plant phase-in costs increased due to the increase in sales. In accordance with a 1994 rate order the Company is collecting deferred Zimmer Plant costs under a phase-in plan through a temporary rate surcharge. The amount of recovery and related amortization is a function of retail sales volume. The increase in federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income. Nonoperating income declined in the year-to-date period due to after tax provisions of $2.2 million for certain demand side management program costs and $0.9 million for the clean-up of underground fuel storage tanks at one of the Company's facilities. Also contributing to the year-to-date decline in nonoperating income and the primary cause of the decline in the comparative quarter was a decrease in the return on unrecovered Zimmer Plant deferrals due to the declining balance of unamortized phase-in plan deferrals. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) OPERATING REVENUES . . . . . . . . . . . $323,494 $307,820 $653,377 $634,997 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . 56,532 56,863 116,555 119,617 Purchased Power. . . . . . . . . . . . 34,653 25,782 69,316 53,411 Other Operation. . . . . . . . . . . . 78,686 74,003 157,496 147,636 Maintenance. . . . . . . . . . . . . . 30,107 32,102 56,549 64,574 Depreciation and Amortization. . . . . 35,086 34,652 69,978 69,083 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals. . . . . . . 3,911 3,911 7,822 7,822 Taxes Other Than Federal Income Taxes. 18,440 16,233 38,361 35,833 Federal Income Taxes . . . . . . . . . 15,649 12,888 33,852 29,324 TOTAL OPERATING EXPENSES . . . 273,064 256,434 549,929 527,300 OPERATING INCOME . . . . . . . . . . . . 50,430 51,386 103,448 107,697 NONOPERATING INCOME (LOSS) . . . . . . . 272 550 (365) 651 INCOME BEFORE INTEREST CHARGES . . . . . 50,702 51,936 103,083 108,348 INTEREST CHARGES . . . . . . . . . . . . 17,195 18,156 33,809 36,180 NET INCOME . . . . . . . . . . . . . . . 33,507 33,780 69,274 72,168 PREFERRED STOCK DIVIDEND REQUIREMENTS. . 2,910 2,914 5,858 5,812 EARNINGS APPLICABLE TO COMMON STOCK. . . $ 30,597 $ 30,866 $ 63,416 $ 66,356 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . $239,799 $224,385 $235,107 $216,658 NET INCOME . . . . . . . . . . . . . . . 33,507 33,780 69,274 72,168 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . 28,127 27,713 56,254 55,426 Cumulative Preferred Stock . . . . . 2,359 2,890 5,249 5,780 Capital Stock Expense. . . . . . . . . 551 57 609 115 BALANCE AT END OF PERIOD . . . . . . . . $242,269 $227,505 $242,269 $227,505 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)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $2,516,995 $2,507,667 Transmission . . . . . . . . . . . . . . . . . . . . 873,515 867,541 Distribution . . . . . . . . . . . . . . . . . . . . 683,154 666,810 General (including nuclear fuel) . . . . . . . . . . 210,781 186,959 Construction Work in Progress. . . . . . . . . . . . 71,630 90,587 Total Electric Utility Plant . . . . . . . . 4,356,075 4,319,564 Accumulated Depreciation and Amortization. . . . . . 1,802,986 1,751,965 NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,553,089 2,567,599 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . 453,260 433,619 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 164,683 150,994 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 6,236 13,723 Accounts Receivable. . . . . . . . . . . . . . . . . 125,051 115,765 Allowance for Uncollectible Accounts . . . . . . . . (448) (334) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 30,316 29,093 Materials and Supplies . . . . . . . . . . . . . . . 74,234 72,861 Accrued Utility Revenues . . . . . . . . . . . . . . 32,534 43,937 Prepayments. . . . . . . . . . . . . . . . . . . . . 13,404 10,191 TOTAL CURRENT ASSETS . . . . . . . . . . . . 281,327 285,236 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 436,689 458,525 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 35,798 32,364 TOTAL. . . . . . . . . . . . . . . . . . . $3,924,846 $3,928,337 See Notes to Consolidated Financial Statements. /TABLE INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (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. . . . . . . . . . . . . . . . . . . 731,157 731,102 Retained Earnings. . . . . . . . . . . . . . . . . . 242,269 235,107 Total Common Shareholder's Equity. . . . . . 1,030,010 1,022,793 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . 22,000 52,000 Subject to Mandatory Redemption. . . . . . . . . . 135,000 135,000 Long-term Debt . . . . . . . . . . . . . . . . . . . 1,037,512 1,034,048 TOTAL CAPITALIZATION . . . . . . . . . . . . 2,224,522 2,243,841 OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning. . . . . . . . . . . . . . . 285,797 269,392 Other. . . . . . . . . . . . . . . . . . . . . . . . 195,142 184,103 TOTAL OTHER NONCURRENT LIABILITIES . . . . . 480,939 453,495 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . - 6,053 Short-term Debt. . . . . . . . . . . . . . . . . . . 86,725 89,975 Accounts Payable . . . . . . . . . . . . . . . . . . 51,027 60,706 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 74,182 71,696 Interest Accrued . . . . . . . . . . . . . . . . . . 16,090 16,158 Obligations Under Capital Leases . . . . . . . . . . 37,197 31,776 Other. . . . . . . . . . . . . . . . . . . . . . . . 66,430 74,463 TOTAL CURRENT LIABILITIES. . . . . . . . . . 331,651 350,827 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 599,210 612,147 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 151,239 155,202 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 97,979 99,832 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 39,306 12,993 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . . . . . $3,924,846 $3,928,337 See Notes to Consolidated Financial Statements. /TABLE INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 69,274 $ 72,168 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 73,820 73,979 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals. . . . . . . . . . . . . . . . 7,822 7,822 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net). . . . . . . . . . . . (4,850) 14,446 Deferred Federal Income Taxes. . . . . . . . . . . . . . (7,712) (12,973) Deferred Investment Tax Credits. . . . . . . . . . . . . (3,963) (3,993) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . (9,172) 6,082 Fuel, Materials and Supplies . . . . . . . . . . . . . . (2,596) 44 Accrued Utility Revenues . . . . . . . . . . . . . . . . 11,403 (2,620) Accounts Payable . . . . . . . . . . . . . . . . . . . . (9,679) (28,072) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,486 (7,933) Other (net). . . . . . . . . . . . . . . . . . . . . . . . 5,306 (26,222) Net Cash Flows From Operating Activities . . . . . . 132,139 92,728 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (37,128) (51,710) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 853 964 Net Cash Flows Used For Investing Activities . . . . (36,275) (50,746) FINANCING ACTIVITIES: Issuance of Long-term Debt . . . . . . . . . . . . . . . . 38,579 96,819 Change in Short-term Debt (net). . . . . . . . . . . . . . (3,250) 18,650 Retirement of Cumulative Preferred Stock . . . . . . . . . (30,555) - Retirement of Long-term Debt . . . . . . . . . . . . . . . (46,091) (50,736) Dividends Paid on Common Stock . . . . . . . . . . . . . . (56,254) (55,426) Dividends Paid on Cumulative Preferred Stock . . . . . . . (5,780) (5,780) Net Cash Flows From (Used For) Financing Activities. (103,351) 3,527 Net Increase (Decrease) in Cash and Cash Equivalents. . . . (7,487) 45,509 Cash and Cash Equivalents at Beginning of Period . . . . . . 13,723 9,907 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 6,236 $ 55,416 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $32,516,000 and $36,542,000 and for income taxes was $44,183,000 and $50,575,000 in 1996 and 1995, respectively. Noncash acquisitions under capital leases were $42,290,000 and $9,254,000 in 1996 and 1995, respectively. In connection with the early termination of a western coal land sublease the Company will receive cash payments from the lessee of $30.8 million over a ten year period which has been recorded at a net present value of $22.8 million. See Notes to Consolidated Financial Statements. /TABLE INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state-ments should be read in conjunction with the 1995 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. 2. FINANCING ACTIVITIES In the first six months of 1996, the Company issued $40 million of 8% Junior Subordinated Deferrable Interest Debentures and retired $6 million of Sinking Fund Debentures, $40 million of 9.50% First Mortgage Bonds and 300,000 shares of 7.08% Cumulative Preferred Stock, par value $100. 3. CONTINGENCIES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides for the recovery of stranded costs under certain conditions from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. The Company continues to be involved in certain matters discussed in its 1995 Annual Report. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 RESULTS OF OPERATIONS Net income decreased 1% or $0.3 million for the quarter and 4% or $2.9 million for the year-to-date comparative period, as increased revenues were more than offset by increased operating expenses. Income statement line items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues. . . . $15.7 5 $18.4 3 Purchased Power Expense . 8.9 34 15.9 30 Other Operation Expense . 4.7 6 9.9 7 Maintenance Expense . . . (2.0) (6) (8.0) (12) Taxes Other Than Federal Income Taxes . . 2.2 14 2.5 7 Federal Income Taxes. . . 2.8 21 4.5 15 Interest Charges. . . . . (1.0) (5) (2.4) (7) Operating revenues increased primarily due to increased retail sales in both periods. Weather-sensitive residential customers' demand for electricity rose by 6% in the quarter and 4% in the year-to-date period reflecting unseasonable spring weather and colder winter weather. Also, contributing to the increase in retail sales was a 12% quarterly and 10% year-to-date increase in industrial sales primarily resulting from the addition of a major new customer. Although wholesale revenue changes had little effect on operating revenues, there were large fluctuations within the two major components of wholesale revenues. Wholesale sales to affiliates declined reflecting lower deliveries to the AEP System Power Pool (Power Pool) primarily due to a reduction in the availability of nuclear generation as a result of a refueling outage in the second quarter at one unit of the Company's two unit Cook Nuclear Plant. Sales to the Company's non-affiliated municipal and cooperative wholesale customers and sales by the Power Pool to unaffiliated utilities allocated to the Company increased mainly due to the unseasonable spring and colder winter weather largely offsetting the decline in sales to the Power Pool. Purchased power expense increased significantly primarily due to increased purchases from the Power Pool, to replace the unavailable nuclear generating capacity and to support the Company's allocated share of Power Pool wholesale transactions with unaffiliated utilities; increased purchases from unaffiliated utilities for pass-through sales to other unaffiliated companies; and increased purchases under an agreement with the Ohio Valley Electric Corporation, an affiliated company which is not a member of the Power Pool. The increase in other operation expense reflects an increased cost of pollution control emission allowances, increased rent expense, reduced transmission investment equalization credits from affiliates and increased engineering and other professional services billed from AEP Service Corporation. The increase in rent expense resulted from a favorable determination by the Indiana state tax department that resulted in the reversal in the second quarter of 1995 of a provision for state taxes applicable to the Rockport Plant Unit 2 operating lease. Transmission equalization credits decreased due to an increase in the Company's peak demand relative to the peak demands of the other Power Pool members. Under the AEP transmission equalization agreement the costs of ownership of certain transmission facilities are shared by the Power Pool members based on their relative peak demands. Maintenance expense decreased in both periods as a result of reductions in the number of employees performing maintenance on the Company's nuclear plant and lower payments for contract labor. The increase in taxes other than federal income taxes in both periods was the result of a favorable accrual adjustment for Indiana real and personal property taxes recorded in 1995. Federal income taxes attributable to operations increased in both periods due to changes in certain book/tax timing differences accounted for on a flow-through basis for ratemaking and financial reporting purposes and an increase in pre-tax operating income. In both periods interest charges decreased primarily due to the refinancing of certain fixed rate long-term debt at lower variable and fixed rates during the third quarter of 1995. FINANCIAL CONDITION Total plant and property additions including capital leases for the year-to-date period were $80 million. During the first six months of 1996 short-term debt outstanding declined by $3.3 million. During the first half of 1996 the Company redeemed 300,000 shares of 7.08% Cumulative Preferred Stock, par value $100, at $101.85, $40 million of 9.50% First Mortgage Bonds due 2021 and $6,053,000 of Sinking Fund Debentures. The Company also issued $40 million of 8% Junior Subordinated Debentures due 2026. On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides for the recovery under certain conditions of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) OPERATING REVENUES . . . . . . . . . . . . $78,730 $72,699 $167,319 $158,001 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . 20,110 18,375 41,790 39,736 Purchased Power. . . . . . . . . . . . . 22,102 20,337 44,621 42,627 Other Operation. . . . . . . . . . . . . 11,974 11,988 24,330 22,281 Maintenance. . . . . . . . . . . . . . . 7,634 6,508 15,354 13,659 Depreciation and Amortization. . . . . . 6,267 6,087 12,521 12,119 Taxes Other Than Federal Income Taxes. . 1,744 1,526 4,118 4,020 Federal Income Tax Expense (Credit). . . 598 (684) 3,126 1,354 TOTAL OPERATING EXPENSES. . . . . 70,429 64,137 145,860 135,796 OPERATING INCOME . . . . . . . . . . . . . 8,301 8,562 21,459 22,205 NONOPERATING LOSS. . . . . . . . . . . . . (95) (32) (429) (100) INCOME BEFORE INTEREST CHARGES . . . . . . 8,206 8,530 21,030 22,105 INTEREST CHARGES . . . . . . . . . . . . . 5,837 5,983 11,905 11,743 NET INCOME . . . . . . . . . . . . . . . . $ 2,369 $ 2,547 $ 9,125 $ 10,362 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . $92,071 $91,258 $91,381 $89,173 NET INCOME . . . . . . . . . . . . . . . . 2,369 2,547 9,125 10,362 CASH DIVIDENDS DECLARED. . . . . . . . . . 6,066 5,730 12,132 11,460 BALANCE AT END OF PERIOD . . . . . . . . . $88,374 $88,075 $88,374 $88,075 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Financial Statements. /TABLE KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . $230,829 $230,054 Transmission . . . . . . . . . . . . . . . . . . . . 263,172 261,619 Distribution . . . . . . . . . . . . . . . . . . . . 316,060 313,783 General. . . . . . . . . . . . . . . . . . . . . . . 60,973 59,611 Construction Work in Progress. . . . . . . . . . . . 24,667 14,590 Total Electric Utility Plant . . . . . . . . 895,701 879,657 Accumulated Depreciation and Amortization. . . . . . 279,631 270,590 NET ELECTRIC UTILITY PLANT . . . . . . . . . 616,070 609,067 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 6,411 6,438 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . 2,847 1,031 Accounts Receivable. . . . . . . . . . . . . . . . . 30,002 30,172 Allowance for Uncollectible Accounts . . . . . . . . (149) (259) Fuel . . . . . . . . . . . . . . . . . . . . . . . . 8,747 3,526 Materials and Supplies . . . . . . . . . . . . . . . 12,389 12,481 Accrued Utility Revenues . . . . . . . . . . . . . . 6,253 13,500 Prepayments. . . . . . . . . . . . . . . . . . . . . 2,263 1,701 TOTAL CURRENT ASSETS . . . . . . . . . . . . 62,352 62,152 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 82,946 82,388 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 9,395 12,153 TOTAL. . . . . . . . . . . . . . . . . . . $777,174 $772,198 See Notes to Financial Statements.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $50 Par Value: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares . . . . . . . . . . $ 50,450 $ 50,450 Paid-in Capital. . . . . . . . . . . . . . . . . . . 88,750 78,750 Retained Earnings. . . . . . . . . . . . . . . . . . 88,374 91,381 Total Common Shareholder's Equity. . . . . . 227,574 220,581 First Mortgage Bonds . . . . . . . . . . . . . . . . 179,252 224,235 Notes Payable. . . . . . . . . . . . . . . . . . . . 50,000 - Subordinated Debentures. . . . . . . . . . . . . . . 38,874 38,854 TOTAL CAPITALIZATION . . . . . . . . . . . . 495,700 483,670 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 16,640 15,031 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . - 29,436 Short-term Debt. . . . . . . . . . . . . . . . . . . 57,025 27,050 Accounts Payable . . . . . . . . . . . . . . . . . . 16,675 21,766 Customer Deposits. . . . . . . . . . . . . . . . . . 3,520 3,704 Taxes Accrued. . . . . . . . . . . . . . . . . . . . 6,175 7,972 Interest Accrued . . . . . . . . . . . . . . . . . . 5,483 5,853 Other. . . . . . . . . . . . . . . . . . . . . . . . 7,706 13,283 TOTAL CURRENT LIABILITIES. . . . . . . . . . 96,584 109,064 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 146,363 145,005 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 17,775 18,397 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 4,112 1,031 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . . . . . $777,174 $772,198 See Notes to Financial Statements.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 9,125 $ 10,362 Adjustments for Noncash Items: Depreciation and Amortization. . . . . . . . . . . . . . 12,557 12,155 Deferred Federal Income Taxes. . . . . . . . . . . . . . 415 (1,041) Deferred Investment Tax Credits. . . . . . . . . . . . . (622) (629) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . 60 (835) Fuel, Materials and Supplies . . . . . . . . . . . . . . (5,129) 501 Accrued Utility Revenues . . . . . . . . . . . . . . . . 7,247 4,218 Accounts Payable . . . . . . . . . . . . . . . . . . . . (5,091) (3,726) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (1,797) (519) Other (net). . . . . . . . . . . . . . . . . . . . . . . . (123) (2,624) Net Cash Flows From Operating Activities . . . . . . 16,642 17,862 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . (18,181) (16,827) Proceeds from Sales of Property. . . . . . . . . . . . . . 250 - Net Cash Flows Used For Investing Activities . . . . (17,931) (16,827) FINANCING ACTIVITIES: Capital Contributions from Parent Company. . . . . . . . . 10,000 - Issuance of Long-term Debt . . . . . . . . . . . . . . . . 50,000 38,647 Change in Short-term Debt (net). . . . . . . . . . . . . . 29,975 (28,250) Retirement of Long-term Debt . . . . . . . . . . . . . . . (74,738) - Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (12,132) (11,460) Net Cash Flows From (Used For) Financing Activities. 3,105 (1,063) Net Increase (Decrease) in Cash and Cash Equivalents . . . . 1,816 (28) Cash and Cash Equivalents at Beginning of Period . . . . . . 1,031 879 Cash and Cash Equivalents at End of Period . . . . . . . . . $ 2,847 $ 851 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $12,114,000 and $11,646,000 and for income taxes was $4,505,000 and $2,027,000 in 1996 and 1995, respectively. Noncash acquisitions under capital leases were $2,831,000 and $1,857,000 in 1996 and 1995, respectively. See Notes to Financial Statements.
KENTUCKY POWER COMPANY NOTES TO FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) 1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 1995 Annual Report as incorporated in and filed with the Form 10-K. 2. FINANCING ACTIVITIES The Company received from its parent a cash capital contribution of $10 million in March 1996 which was credited to paid-in capital. In April 1996 the Company refinanced $45 million of 7-7/8% first mortgage bonds due in 2002 with the proceeds of two $25 million term loan agreements due in 1999 and 2000 at 6.42% and 6.57% annual interest rates, respectively. The redemption of this series of first mortgage bonds removed the restriction on the use of retained earnings for common stock dividends. 3. CONTINGENCIES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. The Company continues to be involved in certain other matters discussed in its 1995 Annual Report. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 Although revenues increased $6 million or 8% in the comparative second quarter period and $9.3 million or 6% in the comparative year-to-date period, net income decreased 7% or $0.2 million for the quarter and 12% or $1.2 million for the year-to-date period. The net income decrease for the quarter was attributable to increased maintenance and federal income taxes. The net income decrease for the year-to-date period was caused by increased operation expenses, maintenance and federal income taxes and a write-down of certain demand side management program equipment to estimated market value recorded in nonoperating income. Income statement items which changed significantly were: Increase Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . . $ 6.0 8 $ 9.3 6 Fuel Expense . . . . . . . . 1.7 9 2.1 5 Purchased Power Expense. . . 1.8 9 2.0 5 Other Operation Expense. . . - - 2.0 9 Maintenance Expense. . . . . 1.1 17 1.7 12 Federal Income Taxes . . . . 1.3 N.M. 1.8 131 N.M. - Not Meaningful The increase in operating revenues was due to increased energy sales, increased transmission services and the recovery of demand side management costs from retail customers. Energy sales to retail customers rose as customer usage increased in response to colder winter weather and cooler April and warmer May weather. Wholesale energy sales rose mainly due to an increase in energy sales by the AEP System Power Pool (Power Pool) to unaffiliated utilities reflecting the increased weather-related demand for energy. Transmission services provided to an unaffiliated utility under a one year contract that began in January 1996 accounted for the increase in transmission service revenues. Fuel expense rose as a result of increased generation reflecting additional availability in 1996 of the Company's Big Sandy Plant and the increased demand. The increase in purchased power expense in the second quarter and year-to-date periods resulted from increased purchases from unaffiliated utilities for pass-through sales to other unaffiliated utilities, reflecting the unseasonable weather; additional purchases to meet the increased demand from an affiliated company which is not a member of the AEP Power Pool; and increased purchases from the AEP Power Pool to meet increased wholesale energy sales demand. In the year-to-date period other operation expense increased mainly due to increased accruals for incentive pay, demand side program expenses and increased AEP Service Corporation billings for engineering and other professional services. Maintenance expense rose in both comparative periods as a result of an increased level of scheduled steam plant maintenance work at the Big Sandy Plant. The increase in federal income tax expense attributable to operations in both periods was primarily due to increases in pre-tax operating income, changes in certain book/tax differences accounted for on a flow-through basis for ratemaking and financial reporting purposes and the completion of the amortization of deferred federal income taxes in excess of the statutory tax rate as ordered by the Kentucky Public Service Commission. OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) OPERATING REVENUES . . . . . . . . . . . . . $449,383 $435,976 $954,124 $852,803 OPERATING EXPENSES: Fuel . . . . . . . . . . . . . . . . . . . 144,426 141,301 322,752 272,979 Purchased Power. . . . . . . . . . . . . . 16,175 9,561 31,240 29,803 Other Operation. . . . . . . . . . . . . . 78,985 82,106 161,876 141,806 Maintenance. . . . . . . . . . . . . . . . 42,083 36,302 71,150 71,200 Depreciation and Amortization. . . . . . . 34,369 33,839 68,643 67,729 Taxes Other Than Federal Income Taxes. . . 40,532 41,817 82,735 87,154 Federal Income Taxes . . . . . . . . . . . 25,530 23,180 60,601 46,933 TOTAL OPERATING EXPENSES . . . . . 382,100 368,106 798,997 717,604 OPERATING INCOME . . . . . . . . . . . . . . 67,283 67,870 155,127 135,199 NONOPERATING INCOME. . . . . . . . . . . . . 128 1,702 2,262 5,409 INCOME BEFORE INTEREST CHARGES . . . . . . . 67,411 69,572 157,389 140,608 INTEREST CHARGES . . . . . . . . . . . . . . 23,462 23,774 46,904 47,068 NET INCOME . . . . . . . . . . . . . . . . . 43,949 45,798 110,485 93,540 PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . 2,240 3,893 4,480 7,718 EARNINGS APPLICABLE TO COMMON STOCK. . . . . $ 41,709 $ 41,905 $106,005 $ 85,822 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 1996 1995 1996 1995 (in thousands) BALANCE AT BEGINNING OF PERIOD . . . . . . . $546,611 $492,248 $518,029 $483,222 NET INCOME . . . . . . . . . . . . . . . . . 43,949 45,798 110,485 93,540 DEDUCTIONS: Cash Dividends Declared: Common Stock . . . . . . . . . . . . . . 35,714 34,857 71,428 69,714 Cumulative Preferred Stock . . . . . . . 2,194 3,825 4,388 7,650 Capital Stock Expense. . . . . . . . . . . 47 34 93 68 BALANCE AT END OF PERIOD . . . . . . . . . . $552,605 $499,330 $552,605 $499,330 The common stock of the Company is wholly owned by American Electric Power Company, Inc. See Notes to Consolidated Financial Statements. /TABLE OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production . . . . . . . . . . . . . . . . . . . . . . . . $2,537,828 $2,534,893 Transmission . . . . . . . . . . . . . . . . . . . . . . . 806,518 798,854 Distribution . . . . . . . . . . . . . . . . . . . . . . . 844,410 833,944 General (including mining assets). . . . . . . . . . . . . 689,601 688,253 Construction Work in Progress. . . . . . . . . . . . . . . 69,682 59,278 Total Electric Utility Plant . . . . . . . . . . . 4,948,039 4,915,222 Accumulated Depreciation and Amortization. . . . . . . . . 2,160,821 2,091,148 NET ELECTRIC UTILITY PLANT . . . . . . . . . . . . 2,787,218 2,824,074 OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 107,439 107,510 CURRENT ASSETS: Cash and Cash Equivalents. . . . . . . . . . . . . . . . . 74,385 44,000 Accounts Receivable (net). . . . . . . . . . . . . . . . . 198,284 199,293 Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 138,027 126,952 Materials and Supplies . . . . . . . . . . . . . . . . . . 78,084 80,468 Accrued Utility Revenues . . . . . . . . . . . . . . . . . 36,948 40,100 Prepayments. . . . . . . . . . . . . . . . . . . . . . . . 58,755 42,286 TOTAL CURRENT ASSETS . . . . . . . . . . . . . . . 584,483 533,099 REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . . 547,796 562,329 DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . . 89,066 129,552 TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,116,002 $4,156,564 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED)
June 30, December 31, 1996 1995 (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. . . . . . . . . . . . . . . . . . . . . . 459,567 459,474 Retained Earnings. . . . . . . . . . . . . . . . . . . . . 552,605 518,029 Total Common Shareholder's Equity. . . . . . . . . 1,333,373 1,298,704 Cumulative Preferred Stock: Not Subject to Mandatory Redemption. . . . . . . . . . . 41,240 41,240 Subject to Mandatory Redemption. . . . . . . . . . . . . 115,000 115,000 Long-term Debt . . . . . . . . . . . . . . . . . . . . . . 1,049,175 1,138,425 TOTAL CAPITALIZATION . . . . . . . . . . . . . . . 2,538,788 2,593,369 OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . . 225,818 214,726 CURRENT LIABILITIES: Long-term Debt Due Within One Year . . . . . . . . . . . . 20,673 89,207 Short-term Debt. . . . . . . . . . . . . . . . . . . . . . 117,921 9,400 Accounts Payable . . . . . . . . . . . . . . . . . . . . . 77,215 102,580 Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . 138,227 161,430 Interest Accrued . . . . . . . . . . . . . . . . . . . . . 19,668 20,807 Obligations Under Capital Leases . . . . . . . . . . . . . 24,665 25,172 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 72,305 80,507 TOTAL CURRENT LIABILITIES. . . . . . . . . . . . . 470,674 489,103 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . 726,701 731,959 DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . 48,166 49,860 DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . . 105,855 77,547 CONTINGENCIES (Note 3) TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,116,002 $4,156,564 See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Six Months Ended June 30, 1996 1995 (in thousands) OPERATING ACTIVITIES: Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 110,485 $ 93,540 Adjustments for Noncash Items: Depreciation, Depletion and Amortization . . . . . . . . . . 82,863 75,004 Deferred Federal Income Taxes. . . . . . . . . . . . . . . . 1,180 19,058 Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . . (2,368) (10,006) Amortization of Deferred Property Taxes. . . . . . . . . . . 39,099 38,682 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net). . . . . . . . . . . . . . . . . . 1,009 (18,205) Fuel, Materials and Supplies . . . . . . . . . . . . . . . . (8,691) (24,309) Accrued Utility Revenues . . . . . . . . . . . . . . . . . . 3,152 3,547 Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . (16,469) (18,371) Accounts Payable . . . . . . . . . . . . . . . . . . . . . . (25,365) (41,599) Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . (23,203) (45,811) Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . 33,939 11,763 Net Cash Flows From Operating Activities . . . . . . . . 195,631 83,293 INVESTING ACTIVITIES: Construction Expenditures. . . . . . . . . . . . . . . . . . . (44,831) (56,777) Proceeds from Sale of Property and Other . . . . . . . . . . . 5,529 1,601 Net Cash Flows Used For Investing Activities . . . . . . (39,302) (55,176) FINANCING ACTIVITIES: Change in Short-term Debt (net). . . . . . . . . . . . . . . . 108,521 74,115 Retirement of Long-term Debt . . . . . . . . . . . . . . . . . (158,649) - Dividends Paid on Common Stock . . . . . . . . . . . . . . . . (71,428) (69,714) Dividends Paid on Cumulative Preferred Stock . . . . . . . . . (4,388) (7,650) Net Cash Flows Used For Financing Activities . . . . . . (125,944) (3,249) Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . 30,385 24,868 Cash and Cash Equivalents at Beginning of Period . . . . . . . . 44,000 30,700 Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 74,385 $ 55,568 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $46,627,000 and $45,880,000 and for income taxes was $39,244,000 and $34,447,000 in 1996 and 1995, respectively. Noncash acquisitions under capital leases were $14,108,000 and $17,504,000 in 1996 and 1995, respectively. See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) 1. GENERAL The accompanying unaudited consolidated financial state-ments should be read in conjunction with the 1995 Annual Report as incorporated in and filed with the Form 10-K. 2. FINANCING ACTIVITY During the first six months of 1996, the Company and a subsidiary retired three series of long-term debt at maturity: $8 million of 5-1/8% Series Sinking Fund Debentures, $39 million of 5% Series First Mortgage Bonds and $8 million of 5.79% Notes Payable. The Company also retired six series of long-term debt before maturity in 1996: four series of first mortgage bonds totaling $94 million with rates ranging from 7-5/8% to 9-7/8% and two series of sinking fund debentures totaling $9 million with rates of 6-5/8% and 7-7/8%. As a result of the early redemption of the 9-7/8% Series First Mortgage Bonds due in 2020, the restriction on the use of retained earnings for common stock dividends was reduced from $156.5 million to $23.9 million. 3. CONTINGENCIES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. The Company continues to be involved in certain other matters discussed in the 1995 Annual Report. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SECOND QUARTER 1996 vs. SECOND QUARTER 1995 AND YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995 RESULTS OF OPERATIONS Although energy sales increased 16% in the comparative second quarter, net income decreased 4% or $1.8 million due to the effect on comparable net income of an $8.3 million after tax adjustment to revenues recorded in June 1995 under a major industrial contract. Net income increased 18% or $16.9 million in the comparative year-to-date period primarily due to a 27% increase in energy sales. Income statement items which changed significantly were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % Operating Revenues . . . . $ 13.4 3 $101.3 12 Fuel Expense . . . . . . . 3.1 2 49.8 18 Purchased Power Expense. . 6.6 69 1.4 5 Other Operation Expense. . (3.1) (4) 20.1 14 Maintenance Expense. . . . 5.8 16 (0.1) - Federal Income Taxes . . . 2.3 10 13.7 29 Operating revenues increased in both periods as a result of increased energy sales, which more than offset the effect of the 1995 adjustment to industrial revenues, and a retail rate increase in the year-to-date period. Sales volume to wholesale customers was up 52% in the second quarter of 1996 and 98% in the year-to-date period primarily due to an increase in energy supplied to the AEP System Power Pool (Power Pool) reflecting increased weather-related demand of affiliated members of the Power Pool and, in the year-to-date period, the increased availability of the Company's two Gavin Plant generating units. The Gavin units had been out-of-service for extended periods during the first three months of 1995 for maintenance and the installation of flue gas desulfurization systems (scrubbers). Wholesale energy sales by the Power Pool to unaffiliated utilities also increased in both comparative periods largely as a result of unseasonable weather. Retail energy sales increased 2% in the comparative second quarter period and 3% in the comparative year-to-date period reflecting increased energy sales in all major retail customer classes largely as a result of increased usage due to unseasonable weather and growth in the number of customers. A retail base rate increase in March 1995 also contributed to the higher revenues in the comparative year-to-date period. The increase in fuel expense in both periods was mainly due to increased generation resulting from the higher demand for energy and, in the year-to-date period, the increased availability of the Gavin Plant units. Increased energy purchases from unaffiliated utilities for pass-through sales to other unaffiliated utilities as a result of the unseasonable weather in 1996 was the major reason for the substantial increase in purchased power expense in the comparative second quarter period. Other operation expense declined in the second quarter of 1996 reflecting reduced steam generation expenses as a result of a scheduled outage in 1996 at both of the Gavin units for inspection and repairs. The increase in other operation expense during the first six months of this year was primarily due to rent and other operating costs of the recently installed Gavin Plant scrubbers and the amortization, commensurate with recovery in rates, of previously deferred Gavin scrubber expenses. The increase in maintenance expense in the comparative second quarter period was due to the 1996 maintenance outage at both of the Gavin units. The increase in both periods in federal income tax expense attributable to operations was due to an increase in pre-tax operating income and in the comparative second quarter period due to changes in certain book/tax differences accounted for on a flow-through basis for ratemaking and financial reporting purposes. FINANCIAL CONDITION Total plant and property additions including capital leases for the first six months of 1996 were $59 million. During the first six months of 1996, the Company and a subsidiary retired $158 million principal amount of long-term debt with interest rates ranging from 5% to 9-7/8% and increased short-term debt by $109 million. As a result of the early redemption of the remaining $2.5 million outstanding balance of the 9-7/8% Series First Mortgage Bonds due in 2020, the restriction on the use of retained earnings for common stock dividends was reduced from $156.5 million to $23.9 million. NEW FERC RULES On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued two Final Rules regarding open access transmission and stranded cost recovery in the wholesale market. In the open access final rule, all public utilities with transmission lines are required to file non-discriminatory open access tariffs that offer non-affiliated wholesale customers the same transmission service at the same terms and costs as they provide to themselves and their affiliates. The Company adopted with FERC approval a non-discriminatory open access transmission tariff in 1995 under the provisions of a proposed FERC rule and as required by the new open access rule filed a new non-discriminatory open access transmission tariff that is basically the same as the previously filed open access transmission tariff. The open access final rule also provides under certain conditions for the recovery of stranded costs from a utility's departing wholesale customers -- that is costs that were prudently incurred to serve departing wholesale customers that would go unrecovered if these customers use open access to move to another supplier. The other final rule provides for the manner in which the open access rule will be administered. Management does not expect these final rules to adversely impact financial condition. PART II. OTHER INFORMATION Item 1. Legal Proceedings. Indiana Michigan Power Company ("I&M") Reference is made to page 20 of the Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K") for a discussion of a petition for review filed by I&M and other unaffiliated utilities in the U.S. Court of Appeals for the District of Columbia Circuit regarding nuclear waste disposal. On July 23, 1996, the court ruled that the Nuclear Waste Policy Act of 1982 imposes on the U.S. Department of Energy ("DOE") an unconditional obligation to begin acceptance of spent nuclear fuel and high level radioactive waste by January 31, 1998. The court did not determine an appropriate remedy, holding that DOE has not yet defaulted upon either its statutory or contractual obligations. American Electric Power Company, Inc. ("AEP") and Ohio Power Company ("OPCo") Reference is made to pages 25, 26 and 34 of the 1995 10-K and page II-1 of the Quarterly Report on Form 10-Q for the quarter ended March 31, 1996 for a discussion of proceedings instituted by the U.S. Environmental Protection Agency ("Federal EPA"), and the settlement thereof, which alleged that OPCo's Kammer Plant was operating in violation of applicable federally enforceable air pollution control requirements for sulfur dioxide since January 1, 1989. On May 20, 1996, the U.S. District Court for the Northern District of West Virginia entered an order approving the consent decree. Appalachian Power Company ("APCo") Reference is made to page 33 of the 1995 10-K for a discus- sion of a complaint filed against APCo and Global Power Company, an independent contractor retained by APCo, by Federal EPA related to an asbestos abatement project at APCo's Kanawha River Plant. APCo and Global have entered into a Consent Agreement, dated July 30, 1996, with Federal EPA to settle this matter by paying a civil penalty of $58,000, which shall be shared by APCo and Global. Item 4. Submission of Matters to a Vote of Security Holders. AEP The annual meeting of shareholders was held in Columbus, Ohio on April 24, 1996. The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following two matters, as indicated below: 1. Election of 12 directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director was elected by a vote of the shareholders as follows: II-1 Number of Shares Number of Nominee Voted For Votes Withheld Peter J. DeMaria 142,522,136 2,086,655 E. Linn Draper, Jr. 142,496,525 2,112,266 Robert M. Duncan 142,377,695 2,231,096 Robert W. Fri 142,359,083 2,249,708 Arthur G. Hansen 142,312,097 2,296,694 Lester A. Hudson, Jr. 142,491,624 2,117,167 Gerald P. Maloney 142,534,248 2,074,543 Angus E. Peyton 142,435,230 2,173,561 Donald G. Smith 142,496,778 2,112,013 Linda Gillespie Stuntz 142,009,723 2,599,068 Morris Tanenbaum 142,406,307 2,202,484 Ann Haymond Zwinger 142,300,604 2,308,187 2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as independent auditors of AEP for the year 1996. The proposal was approved by a vote of the shareholders as follows: Votes FOR 142,603,261 Votes AGAINST 870,975 Votes ABSTAINED 1,134,555 Broker NON-VOTES* 0 *A non-vote occurs when a nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. APCo The annual meeting of stockholders was held on April 23, 1996 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each of the following seven persons for election as directors and there were no votes with- held and such persons were elected directors to hold office for one year or until their successors are elected and qualify: Peter J. DeMaria Gerald P. Maloney E. Linn Draper, Jr. James J. Markowsky Henry W. Fayne Joseph H. Vipperman William J. Lhota No other business was transacted at the meeting. I&M The annual meeting of stockholders was held on April 23, 1996 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 1,400,000 votes were cast FOR each of the following thirteen persons for election as directors and there were no votes with- held and such persons were elected directors to hold office for one year or until their successors are elected and qualify: C. R. Boyle, III James J. Markowsky G. A. Clark Albert H. Potter Peter J. DeMaria David B. Synowiec William N. D'Onofrio Dale M. Trenary E. Linn Draper, Jr. Joseph H. Vipperman William J. Lhota William E. Walters Gerald P. Maloney No other business was transacted at the meeting. II-2 OPCo The annual meeting of shareholders was held on May 7, 1996 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,478 votes were cast FOR each of the following seven persons for elec- tion as directors and there were no votes withheld and such per- sons were elected directors to hold office for one year or until their successors are elected and qualify: Peter J. DeMaria Gerald P. Maloney E. Linn Draper, Jr. James J. Markowsky Henry W. Fayne Joseph H. Vipperman William J. Lhota No other business was transacted at the meeting. Item 5. Other Information. APCo Reference is made to pages 9 and 10 of the 1995 10-K for a discussion of competition and restructuring in the electric utility industry and an order by the Virginia State Corporation Commission ("Virginia SCC") directing its staff to conduct an investigation in this regard. On July 31, 1996, the staff issued its report which concludes that "it is unnecessary and inadvis- able to implement a massive restructuring of the industry at this juncture." The staff indicated that "because Virginia is a low cost state, the staff believes there may be little to gain and much to lose by being on the leading edge of a restructuring movement." Reference is made to pages 11 and 12 of the 1995 10-K for a discussion of APCo's proposed new transmission facilities. On June 18, 1996, the U.S. Forest Service ("Forest Service") re- leased a Draft Environmental Impact Statement ("EIS"). The Forest Service preliminarily identified a "No Action Alternative" as its preferred alternative. If this alternative is incorpo- rated in the Final EIS, APCo would not be authorized to cross the federally-administered lands of the Forest Service with the pro- posed transmission line. Given the findings set forth in the Draft EIS and the preliminary position of the Forest Service, APCo cannot presently predict the schedule for completion of the state and federal permitting process. On July 25, 1996, the Virginia SCC issued an order extending indefinitely the date for filing comments and suspending its pro- ceeding on the transmission line due to the findings of the Draft EIS. However, the Virginia SCC ordered APCo to file, on or be- fore December 1, 1996, a proposal detailing its intentions with regard to meeting the need for major additional transmission capacity identified in the Virginia SCC's interim order of December 13, 1995. APCo and Kentucky Power Company ("KEPCo") Reference is made to page 12 of the 1995 10-K for a discus- sion of APCo's and KEPCo's proposed transmission system improve- ment project. The Kentucky Public Service Commission approved the project in its order dated June 11, 1996. Construction is scheduled to begin in October 1996. II-3 Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo and OPCo Exhibit 10 - American Electric Power System Manage- ment Incentive Compensation Plan - 1996. APCo, Columbus Southern Power Company ("CSPCo"), I&M, KEPCo and OPCo Exhibit 12 - Statement re: Computation of Ratios. AEP, AEP Generating Company ("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 June 30, 1996. II-4 In the opinion of the companies, the financial statements contained herein reflect all adjustments (consisting of only normal recurring accruals) which are necessary to a fair presentation of the results of operations for the interim periods. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signatures 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. G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Controller and Secretary AEP GENERATING COMPANY G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Vice President and Controller APPALACHIAN POWER COMPANY G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Vice President and Controller COLUMBUS SOUTHERN POWER COMPANY G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Vice President and Controller INDIANA MICHIGAN POWER COMPANY G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Vice President and Controller KENTUCKY POWER COMPANY G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Vice President and Controller OHIO POWER COMPANY G.P. Maloney P.J. DeMaria G.P. Maloney, Vice President P.J. DeMaria, Vice President and Controller Date: August 13, 1996 II-5 EX-10 2 AMERICAN ELECTRIC POWER SYSTEM MANAGEMENT INCENTIVE COMPENSATION PLAN 1996 TABLE OF CONTENTS Page ---- INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . iv 1.0 OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.1 Participation in MICP . . . . . . . . . . . . . . 1 1.2 MICP Award Limitation . . . . . . . . . . . . . . 2 2.0 TARGET AWARD ALLOCATIONS . . . . . . . . . . . . . . . . . 3 3.0 AEP CORPORATE PERFORMANCE CRITERIA . . . . . . . . . . . . 5 3.1 Average Annual ROE . . . . . . . . . . . . . . . 5 3.2 Total Investor Return . . . . . . . . . . . . . . 6 3.3 Realization Ratio . . . . . . . . . . . . . . . . 7 4.0 T&D ENERGY DELIVERY PERFORMANCE CRITERIA . . . . . . . . . 8 4.1 Customer Satisfaction & Loyalty . . . . . . . . . 8 4.2 Safety Performance . . . . . . . . . . . . . . . 10 4.3 O&M Expense vs. Budget. . . . . . . . . . . . . . 11 4.4 Customer Service Reliability Index . . . . . . . 13 4.5 Material & Supply Inventory Reduction . . . . . . 13 4.6 Marketing Performance . . . . . . . . . . . . . . 14 5.0 MARKETING BUSINESS UNIT PERFORMANCE CRITERIA . . . . . . . 17 5.1 Annual Marketing Objective . . . . . . . . . . . 17 5.2 Annual Account Management Objective . . . . . . . 18 5.3 Market Share of Electricity . . . . . . . . . . . 19 5.4 Market Share of Energy . . . . . . . . . . . . . 20 5.5 Loyalty Objective . . . . . . . . . . . . . . . . 20 6.0 POWER PLANT MANAGERS . . . . . . . . . . . . . . . . . . . 22 7.0 REGION PLANT SERVICES . . . . . . . . . . . . . . . . . . 22 8.0 CENTRAL MACHINE SHOP MANAGER . . . . . . . . . . . . . . . 22 9.0 FUEL SUPPLY PERFORMANCE CRITERIA . . . . . . . . . . . . . 23 9.1 Adjusted Cost of Coal Produced from Affiliated Mines . . . . . . . . . . . . . . . 23 9.2 PUCO Cap Performance . . . . . . . . . . . . . . 24 9.3 Safety Performance . . . . . . . . . . . . . . . 24 9.4 Senior Vice President and Senior Staff-Fuel Supply - Delivered Fuel Prices . . . . . . . . 25 9.5 Vice President - Fuel Procurement Measures . . . 25 9.6 General Mine Manager/General Superintendent Measures . . . . . . . . . . . . . . . . . . . 26 9.7 Manager-River Transportation Measures . . . . . . 26 9.8 Manager-Cook Coal Terminal Measures . . . . . . . 27 9.9 Managing Director-Transportation Measures . . . . 28 9.10 Senior Vice President, Vice Presidents, Senior Staff-Fuel Supply & Managing Director- Transportation. . . . . . . . . . . . . . . . . 28 10.0 POWER GENERATION PERFORMANCE CRITERIA . . . . . . . . . 29 11.0 DEPARTMENT/BUSINESS UNIT OBJECTIVES . . . . . . . . . . 29 12.0 THE MICP IN ACTION . . . . . . . . . . . . . . . . . . . 30 13.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT . . . 33 13.1 Termination After Completion of Plan Year. . . 33 13.2 Termination Due to Death, Retirement, or Disability . . . . . . . . . . . . . . . . . 33 13.3 Involuntary Termination During Plan Year . . . 34 14.0 CHANGES IN SALARY/POSITION/PARTICIPATION . . . . . . . . 35 15.0 PLAN ADMINISTRATION . . . . . . . . . . . . . . . . . . 36 16.0 MICP AWARD DISTRIBUTIONS AND DEFERRALS . . . . . . . . . A-1 17.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA . . . A-3 18.0 FUEL SUPPLY PAYMENT SCHEDULES . . . . . . . . . . . . . A-4 18.1 Senior Vice President-Fuel Supply. . . . . . . A-4 18.2 Delivered Fuel Prices. . . . . . . . . . . . . A-4 18.3 Vice President-Fuel Procurement. . . . . . . . A-5 18.4 Delivered Fuel Prices. . . . . . . . . . . . . A-5 18.5 Power Generation Production Cost . . . . . . . A-6 18.6 General Mine Managers/General Super- intendent (Meigs). . . . . . . . . . . . . . A-6 18.7 Southern Ohio Coal Company - Meigs . . . . . . A-6 18.8 Central Ohio Coal Company. . . . . . . . . . . A-7 18.9 Windsor Coal Company . . . . . . . . . . . . . A-7 18.10 All Coal Mines - Safety Incidence Rate . . . . A-8 18.11 Manager - River Transportation . . . . . . . . A-9 18.12 River Transportation Operating Cost Per Ton Mile . . . . . . . . . . . . . . . . . . A-9 18.13 River Transportation Safety Incidence Rate . . A-9 18.14 Manager-Cook Coal Terminal . . . . . . . . . . A-10 18.15 Cook Coal Terminal Adjusted Cost Per Ton . . . A-10 18.16 Cook Coal Terminal Safety Incidence Rate . . . A-10 18.17 Managing Director-Transportation . . . . . . . A-11 18.18 Cook Coal Terminal Adjusted Cost Per Ton . . . A-11 18.19 River Transportation Operating Cost Per Ton Mile . . . . . . . . . . . . . . . . A-11 18.20 Delivered Fuel Prices. . . . . . . . . . . . . A-12 18.21 River Transportation and Cook Coal Terminal Safety Incidence Rate. . . . . . . . . . . . A-12 19.0 POWER GENERATION DEPARTMENT/BUSINESS UNIT PAYMENT SCHEDULES . . . . . . . . . . . . . . . . . . A-13 19.1 O & M Expenditure . . . . . . . . . . . . . . A-13 19.2 Power Generation Production Cost . . . . . . . A-13 19.3 Capital Expenditures . . . . . . . . . . . . . A-14 19.4 Equivalent Availability. . . . . . . . . . . . A-14 19.5 Heat Rate. . . . . . . . . . . . . . . . . . . A-15 INTRODUCTION The American Electric Power System is continuing the Management Incentive Compensation Plan (MICP) during 1996, with revisions from the 1995 Plan. The Plan's purpose is to bring together the interests of key managers with those of the AEP System's customers and shareholders by providing performance incentives to serve customers' needs and meet shareholders' financial expectations at the highest possible levels. Through the MICP, a key manager can receive an annual monetary award in addition to base salary, if certain performance levels are met. The Plan is designed to help motivate a consistent level of superior Company performance by rewarding those principally accountable for achieving it. This Plan provides an element of compensation which will vary directly with Company performance. It will ensure that key managers are compensated competitively and consistent with the AEP System's financial and operating performance. Any questions about the Plan should be directed to the Director- Compensation and Benefits through the respective business unit head. 1.0 OVERVIEW OF THE MANAGEMENT INCENTIVE COMPENSATION PLAN A participant's MICP annual target award is expressed as a percentage of annual base earnings. Actual awards can vary from 0% to 150% of the target award, based on performance. Performance criteria are established annually for the following organizational units: - AEP Corporate - Energy Delivery T&D Business Group - Power Generation - Marketing - Fuel Supply - Individual Units Each participant's target award is allocated by organizational unit. The organization's success in meeting the year's established performance criteria determines the participant's actual award. During the first part of the year following each performance year a participant will receive 80% of any actual award in cash unless a deferral election had been made in accordance with Section 16.2. The remaining 20% is deferred in the form of AEP common stock units payable 3 years later (see Addendum page A-1) unless a deferral election had been made in accordance with Section 16.2. 1.1 PARTICIPATION IN MICP - A select group of key managers and executives whose performance most significantly affects the Company's success participate in the MICP. Positions eligible and individual executives were approved for participation in the 1996 Plan by the Chief Executive Officer. The following procedures apply to the addition of any other positions or executives: A. NEW PARTICIPANTS - Participation is generally automatic for employees promoted or transferred to a position that has been previously approved as eligible for participation in the Plan, effective on the promotion or transfer date. However, if an employee is demoted to a position normally covered by the MICP, approval of the Chief Executive Officer is required for the demoted employee to be eligible to continue as a participant. Prior to becoming a participant in the Plan, specific approval of the Chief Executive Officer is required for all employees or positions not previously eligible to participate in the Plan. Requests for approval by the Chief Executive Officer should be submitted through the Director-Compensation & Benefits. An executive who is not currently a Plan participant and who is entering an eligible position for the first time, will generally be eligible to participate in that year's Plan if the promotion or transfer date is prior to October 1. If it is after this date, the executive will be eligible to participate in the following year's Plan. 1.2 MICP AWARD LIMITATION - No award is payable unless AEP's dividends remain at prevailing levels and net income is greater than dividend payments in the current year. 2.0 TARGET AWARD ALLOCATIONS Target awards of MICP participants are allocated to AEP Corporate and other organization units, as follows:
Target Award* as Percent of Percent of Awards Allocated Participant Base Salary to Organizational Units - ----------------------- ------------- ------------------------------------------ Office of the Chairman 30 100 Corporate Performance EVP-Energy Delivery 25 75 Corporate Performance Group, Controller, VPs, 25 Department/Business Unit Performance SVPs and State Presidents or 60 Corporate 40 Department/Business Unit Performance or 100 Corporate Performance Fuel Supply SVP and VPs 25 25 Corporate Performance 45 Fuel Supply Performance 25 Delivered Fuel Prices 5 Power Generation Production Cost AEP Division Managers 20 75 Corporate Performance and Others as Designated 25 Department/Business Unit Performance or 60 Corporate Performance 40 Department/Business Unit Performance or 50 Corporate 50 Department/Business Unit Performance or 100 Corporate Region Managers 20 50 Corporate Performance 50 Region/Business Unit Performance Power Plant Managers 20 25 Corporate Performance (including Cook) 75 Plant Incentive Plan Site VP (Cook) 25 25 Corporate Performance 75 Plant Incentive Plan Region Plant Services 20 25 Corporate Performance Managers and Production 75 Region Plant Services Performance Services Manager Central Machine Shop 20 25 Corporate Performance Manager 75 Central Machine Shop Performance Fuel Supply Lancaster 20 25 Corporate Performance Senior Staff 45 Fuel Supply Performance 25 Delivered Fuel Prices 5 Power Generation Production Cost Vice President-Fuel 25 25 Corporate Performance Procurement 20 Fuel Supply Performance 50 Department Performance 5 Power Generation Production Cost Managing Director- 20 25 Corporate Performance Transportation 20 Fuel Supply Performance 50 Department Performance 5 Power Generation Production Cost Fuel Supply General Mine 20 25 Corporate Performance Managers/General Super- 25 Fuel Supply Performance intendent (Meigs) 50 Division/Mine Performance Manager-Cook Coal 20 25 Corporate Performance Terminal 75 Cook Coal Terminal Performance Manager-River Trans- 20 25 Corporate Performance portation 75 River Transportation Performance VP & General Manager 25 25 Corporate Performance (Meigs) 25 Fuel Supply Performance 50 Division/Mine Performance
3.0 AEP CORPORATE PERFORMANCE CRITERIA There are three AEP Corporate performance criteria which are weighted to determine a single Corporate performance factor. The three are as follows: - - A two-component measure of Annual Return on Average Stockholder Equity (ROE) for the current year - weighted at 25%; - - A component measuring the Three-Year Average Total Investor Return (TIR) - weighted at 25%; and - - A component comparing the Realization Ratio (Average Price of Power Sold to Retail Customers vs. Other Utilities) for the current year - weighted at 50%. The following describes each in greater detail. 3.1 RETURN ON EQUITY (ROE) is corporate annual after-tax income as a percentage of average annual stockholder equity. It is an indication of how profitably AEP manages its investors' capital. For purposes of the MICP, ROE is measured in the following two ways, each of which is weighted 12.5%: - In terms of absolute performance; and - Relative to the ranking of the AEP ROE among the 20 other electric utilities that together with AEP make up the Standard & Poor's Utility Index. The results of these two measures are averaged to determine performance on this component. The following chart indicates both of these ROE measurements and the performance factors for each.
AVERAGE ANNUAL ROE Performance S&P Utility Performance Absolute ROE Factor* ROE Ranking** Factor ------------ ----------- ------------- ----------- 16 or more 1.50 1-6 1.50 15 1.25 7 1.40 14 1.00 8 1.30 13 .80 9 1.20 12 .60 10 1.10 11 .40 11 1.00 10 or less 0 12 .80 13 .60 14 .40 15 .20 16 or more 0 *Interpolate at intermediate performance. **Highest ROE is ranked first. Example: If AEP's annual ROE is 14%, and AEP achieves an S&P Utility Index rank of seventh out of 21, the average performance factor will be calculated this way: (1.00 + 1.40) / 2 = 1.20. 3.2 TOTAL INVESTOR RETURN (TIR) is an indicator of the increase in value of AEP shareholders' investment. It measures the annual percentage increase in stock price as well as dividends paid over a three-year period (the current and two prior years). AEP System results are then compared with the other 20 companies in the Standard & Poor's Utility Index and are ranked for each of the three years. Performance factors are determined based on the average of the TIR rankings for the three years, as follows: THREE-YEAR AVERAGE TOTAL INVESTOR RETURN AEP TIR Ranking* Performance Factor ---------------- ------------------ 6 or higher 1.50 7 1.40 8 1.30 9 1.20 10 1.10 11 1.00 12 .80 13 .60 14 .40 15 .20 16 0 *Highest TIR is ranked first. Example: If the three-year average rank of AEP is 12 out of 21, the performance factor is .80. 3.3 REALIZATION RATIO is a measure of relative cost efficiency and productivity -- from AEP customers' perspective. It compares the AEP System's average price of power sold to ultimate customers with other utilities' corresponding average price. The realization ratio is based on average realization for sales to ultimate customers by other investor-owned utilities in the seven states in which AEP operates, weighted by the respective proportions of AEP's corresponding sales in those states. (Because Kingsport Power is the only investor-owned electric utility in Tennessee, the realization ratio for that state is based on retail rates of TVA Tennessee distributors.) Performance factors are then derived, as follows: AEP REALIZATION RATIO AEP Ratio Performance Factor* --------- ------------------- .75 or less 1.50 .80 1.25 .85 1.00 .90 .75 .95 .50 1.00 .25 above 1.00 0 *Interpolate at intermediate performance. Example: If AEP's average realization is 20% below the seven-state average, its ratio will be .80 and the performance factor will be 1.25. 4.0 TRANSMISSION AND DISTRIBUTION ENERGY DELIVERY PERFORMANCE CRITERIA There are six T&D Energy Delivery performance criteria that are individually weighed to determine a single performance factor for the T&D Energy Delivery Group, Energy Distribution, Energy Transmission and each Region. The six are as follows: - - Customer Satisfaction and Loyalty - weighted at 20%; - - Safety - weighted at 20%; - - O&M Expense vs. Budget - weighted at 20%; - - Customer Service Reliability Index - weighted at 20%; - - Material and Supply Inventory Reduction - weighted at 10%; - - Marketing - weighted at 10%. The following describes each measure in more detail. 4.1 CUSTOMER SATISFACTION AND LOYALTY is based on a weighted average of the performance factors of the National Key Account Benchmark study by TQS Research (TQS), the Commercial and Industrial Customer Satisfaction Study by RKS Research and Consulting (RKS) and the Corporate Positioning and Communication Tracking Study by Market Strategies, Inc. (MSI) survey instruments in proportions of 61.3%, 28.5%, and 10.2% respectively. The TQS, RKS, and MSI represent the key accounts, major accounts, and residential segments, respectively. The "Customer Loyalty-Electric" score will be utilized from the TQS study, the "Customer Assessment Score" will be utilized from the RKS study, and the "Overall Satisfaction" score will be utilized form the MSI study. The performance factor for each instrument will be computed in accordance with the following payment schedule. Note that while a percentile approach is preferred in the computation of a performance factor with all three of the instruments, a raw score is utilized in the RKS instrument as the timing of the study is not anticipated to permit comparison to other utilities' scores. The award will not be distinguishable between Transmission and Distribution. Targets and results will be system-wide. The 1996 targets and performance factors are: ENERGY DISTRIBUTION BUSINESS UNIT AND REGION TARGET AWARD PAYMENT SCHEDULE TQS AND MSI TARGETS Ranking Result (percentile) Performance Factor* --------------------------- ------------------- Top 10% 1.50 15% 1.25 20% 1.00 25% 0.50 Bottom 70% 0.00 *Interpolate at intermediate performance. ENERGY DISTRIBUTION BUSINESS UNIT AND REGION TARGET AWARD PAYMENT SCHEDULE RKS TARGETS Customer Acceptance Score Performance Factor* ------------------------- ------------------- Over 3.2 1.50 3.1 1.25 3.0 1.00 2.9 0.50 Below 2.85 0.00 *Interpolate at intermediate performance. The use of the RKS instrument is dependent on receiving survey results prior to computation of the annual MICP results. In the event this information is unavailable, the performance measures of the TQS and MSI will be computed as a weighted average in the proportions 85%.7% and 14.3% respectively. 4.2 SAFETY PERFORMANCE of the T&D Energy Delivery Business Group, the Energy Distribution Business Unit, the Energy Transmission Business Unit and the transmission and distribution Regions is measured by two equally weighted indices. The indices are combined to determine a single performance factor for each organizational unit. - RECORDABLE CASE INCIDENCE RATE - Number of recordable cases per 200,000 work hours. - LOST AND RESTRICTED WORKDAY (SEVERITY) RATE - Number of days away from work AND restricted activity days per 200,000 work hours. The rate for the group and the appropriate Units and Regions will be compared to the most recently published EEI rate calculated for each measure. The related performance factors are determined from the following schedule and averaged to yield a single performance factor for safety performance. T&D ENERGY DELIVERY SAFETY PERFORMANCE TARGET AWARD PAYMENT SCHEDULE RATIO TO THE LATEST EEI RATE Ratio to EEI Performance Performance Factor* ------------------------ ------------------- 0.70 1.50 0.85 1.00 0.93 0.50 1.000 or more 0.00 *Interpolate at intermediate performance. Example: If a Transmission Region achieves a ratio of .9250 to the EEI recordable case incidence rate and a ratio of .6500 to the EEI lost and restricted workday (severity) rate, the respective performance factors are .50 and 1.50. Averaging the two yields a single performance factor of 1.00 The performance factor shall be zero for any Region whose recordable injuries include a fatality or a permanent total disability case. SOURCE OF DATA - EEI Rate and AEP Data The EEI rates will be taken from the latest EEI Safety Statistical Survey Report at the time the awards are calculated. The data for T&D Energy Delivery is taken from the year-end AEP System Report of Employee Injuries and Illnesses. This information is compiled by the Safety & Health Section of System Human Resources. The following data for the December cumulative year-to-date report is to be compiled by the AEP Corporate Safety & Health Division on or before January 15 of the following year for the T&D Energy Delivery Group/Unit/Region. - Total Hours Worked - Lost Workdays (LWD Case - days away from work) - Restricted Activity Days - Lost and Restricted Workday (Severity) Rate - Recordable Cases - Recordable Case Incidence Rate DATA AVAILABILITY, CALCULATIONS AND AWARD DETERMINATIONS The AEP Corporate Safety & Health Section will calculate the performance factors for the T&D Energy Delivery Group, and each Business Unit and Region. The calculations will be completed by January 30 and approved by the SVP-Human Resources. 4.3 O&M EXPENSE PERFORMANCE VS. BUDGET is measured by comparing controllable operating and maintenance expenses against budget for the current year. Performance factors are designed to provide increased awards for expense performance which is below budget. However, because some O&M budgets are developed based primarily upon historical expenses and not upon need to complete specific projects, close monitoring of expenses is required. The EVP-Energy Delivery Group is responsible for monitoring expenses in each budgeting organization to ensure that projects that should have been accomplished are not delayed or omitted in order to achieve a higher performance factor score. If this is judged to occur, the approved budget will be commensurately reduced by an amount equal to the estimated cost of the project, and a revised performance factor determined. T&D ENERGY DELIVERY GROUP BUSINESS UNIT AND REGION CONTROLLABLE O&M EXPENSES VS. BUDGET Expenses as Percent of Budget* Performance Factor ------------------------------ ------------------ Less than 91% 1.50 91% but less than 96% 1.25 96% but less than 101% 1.00 101% but less than 103% 0.50 103% but less than 105% 0.25 105% or higher 0.00 *All numbers to be rounded to nearest whole numbers. Example: If Distribution Region's actual result is 93% of budget, the Region has placed between the 91% and 96% bracket, achieving a performance factor of 1.25. 4.4 CUSTOMER SERVICE RELIABILITY INDEX is measured by comparing the current year annual interruption frequency index and the interruption duration index against prior five-year average indices. The reliability index is determined by the following formula: [(Cur. Interpt. Freq. Index/5-Year Avg. Intm. Freq. Index) + (Cur. Interpt. Dur. Index/5-Year Avg. Intm. Dur. Index)] x 100/2 Resulting performance factors are determined as follows: T&D ENERGY DELIVERY GROUP, UNITS AND REGIONS TARGET AWARD PAYMENT SCHEDULE CUSTOMER SERVICE RELIABILITY INDEX VS. PRIOR FIVE-YEAR AVERAGE Service Reliability Index Performance Factor* ------------------------- ------------------- 85% or lower 1.50 92.5% 1.25 100% 1.00 105% 0.50 110% or higher 0.00 *Interpolate at intermediate performance. Example: If a Region's current reliability index is 97%, 3% better than its five-year average of 100%, the performance factor is: [(100%-97%)/(100%-92.5%) x .25] + 1 = 1.10 Special adjustments may be considered for catastrophic situations. 4.5 MATERIAL AND SUPPLY INVENTORY REDUCTION is based on attainment of a dollar inventory reduction goal established for 1996. The goals will be adjusted to accommodate the Capital Spare Parts transfer to Materials & Supplies that began last year. Energy Delivery Support participants will have a $4 million meter inventory reduction goal in lieu of the M&S inventory reduction goal. The 1996 targets are: T&D ENERGY DELIVERY GROUP DELIVERY BUSINESS GROUP, UNITS AND REGIONS TARGET AWARD PAYMENT SCHEDULE MATERIAL & SUPPLY INVENTORY REDUCTION Results as Percent of Goal Performance Factor* -------------------------- ------------------- 150% 1.50 100% 1.00 50% 0.50 0% 0.00 *Interpolate at intermediate performance. Example: If a region's results as a percent of goal were 125%, the performance factor is 1.25. 4.6 MARKETING performance is measured by two indices that are weight-averaged to yield a single performance factor. The target, results, and award are the same for both the Transmission and Distribution groups. The indices are further defined below. MARKETING results constitute 70% of the marketing performance factor. The results are measured by comparing actual performance against marketing objectives for the current year. Marketing objectives are expressed as a collection of product goals which are weighted in value through the assignment of Smart Point equivalents. Marketing objective performance is computed by dividing the total Smart points earned by the Smart Point goals assigned. The total assigned 1996 Smart Points are 6,496,398. The 1996 performance factors are: ENERGY DELIVERY BUSINESS GROUP, UNITS AND REGIONS TARGET AWARD PAYMENT SCHEDULE MARKETING RESULTS Percent of Goal Performance Factor* --------------- ------------------- 110% 1.50 105% 1.25 100% 1.00 95% 0.50 90% 0.00 *Interpolate at intermediate results. MARKETING ACCOUNT MANAGEMENT OBJECTIVES constitute 30% of the marketing performance factor. Achievement is measured by comparing actual performance with account objectives for the year. Account management objectives are expressed as a collection of loyalty enhancing activities, including identification of decision groups, development of business plans, customer presentation and agreements, and implementation of two or more business plan items with designated customers. These activities are weighted in value through the assignment of point equivalents as a function of assigned customers. Account management objective performance is computed in accordance with the following tables which are preset to result in a 100 point base for easy conversion to percentage attainment. NATIONAL ACCOUNT MANAGEMENT Maximum Actual Measurement Goal Accomplishment Score Score* ----------- ---- -------------- ------- ------ Compl. Interv. 70 20 Meter Maps 50 10 ID Decision Groups 50 20 Business Plans 25 35 Cust. Pres. & Agree. 25 15 Bus Plan Impl. 15 10 Total 110 *(Accomplishment/Goal) x Maximum Score = Actual Score (not to exceed maximum score) KEY ACCOUNT MANAGEMENT Maximum Actual Measurement Goal Accomplishment Score Score* ----------- ---- -------------- ------- ------ ID Decision Groups 170 20 Business Plans 136 50 Cust. Pres & Agree. 110 30 Business Plans 50 10 Total 110 *(Accomplishment/Goal) x Maximum Score = Actual Score (not to exceed maximum score) The results for key and national accounts are then weighted 3:1, respectively. The resulting percentage achievement is utilized in the following payment schedule to determine the composite account management performance measure for this index. ENERGY DELIVERY BUSINESS GROUP, UNITS AND REGIONS TARGET AWARD PAYMENT SCHEDULE ACCOUNT MANAGEMENT OBJECTIVES Results as % of Goal Performance Factor* -------------------- ------------------- Over 110% 1.50 105% 1.25 100% 1.00 95% 0.50 Below 90% 0.00 *Interpolate at intermediate results. 5.0 MARKETING BUSINESS UNIT PERFORMANCE CRITERIA The MARKETING PERFORMANCE of the marketing organization is measured by five indices which are weighted to yield a single performance factor. These five indices are the annual marketing objective, the annual account management objective, the electric market share objective, the energy market share objective, and the loyalty objective. These indices are weighted at 50%, 25%, 5%, 5%, and 15%, respectively, for computation of a single performance factor. The description of each of these indices and the performance factor computation methodology is as follows: 5.1 ACHIEVEMENT OF THE ANNUAL MARKETING OBJECTIVE is measured by comparing actual performance against marketing objectives for the current year. Marketing objectives are expressed as a collection of product goals which are weighted in value through the assignment of Smart Point equivalents. Marketing objective performance is computed by dividing the total Smart Points earned by the Smart Point goals assigned. The total Smart Points assigned for 1996 is 6,496,398. The performance factor is calculated in accordance with the following payment schedule. MARKETING BUSINESS UNIT TARGET AWARD PAYMENT SCHEDULE ANNUAL MARKETING OBJECTIVE Results as % of Goal Performance Factor* -------------------- ------------------- Over 110% 1.50 105% 1.25 100% 1.00 95% 0.50 Below 90% 0.00 *Interpolate at intermediate results. Example: If 105% of the marketing goals has been achieved, the performance factor is 1.25. If 108% has been attained, the performance factor would be calculated as follows: [(108%-105%)/(110%-105%) x 0.25] + 1.25 = 1.40 5.2 ACHIEVEMENT OF THE ANNUAL ACCOUNT MANAGEMENT OBJECTIVE is measured by comparing actual performance with account objectives for the current year. Account management objectives are expressed as a collection of loyalty- enhancing activities, including identification of decisions groups, development of business plans, customer presentation and agreements, and implementation of two or more business plan items with designated customers. These activities are weighted in value through the assignment of point equivalents as function of assigned customers. Account management objective performance is computed as per the following tables, which are preset to result in a 100 point base for easy conversion to percentage attainment. NATIONAL ACCOUNT MANAGEMENT Maximum Actual Measurement Goal Accomplishment Score Score* ----------- ---- -------------- ------- ------ Compl. Interv. 70 20 Meter Maps 50 10 ID Decision Groups 50 20 Business Plans 25 35 Cust. Pres. & Agree. 25 15 Bus Plan Impl. 15 10 Total 110 *(Accomplishment/Goal) x Maximum Score = Actual Score (not to exceed maximum score) KEY ACCOUNT MANAGEMENT Maximum Actual Measurement Goal Accomplishment Score Score* ----------- ---- -------------- ------- ------ ID Decision Groups 170 20 Business Plans 136 50 Cust. Pres & Agree. 110 30 Business Plans 50 10 Total 110 *(Accomplishment/Goal) x Maximum Score = Actual Score (not to exceed maximum score) The results for key and national accounts are then weighted 3:1, respectively. The resulting percentage achievement is utilized in the following payment schedule to determine the composite account management performance measure for this index. MARKETING BUSINESS UNIT TARGET AWARD PAYMENT SCHEDULE ACCOUNT MANAGEMENT OBJECTIVE Results as % of Goal Performance Factor* -------------------- ------------------- Over 110% 1.50 105% 1.25 100% 1.00 95% 0.50 Below 90% 0.00 *Interpolate at intermediate performance 5.3 ACHIEVEMENT OF THE MARKET SHARE OF ELECTRICITY OBJECTIVE is measured by comparing the actual market share performance of retail electricity sales against the market share of electricity objectives for the current year. Market share of electricity is computed by dividing the AEP total retail electricity sales by the electricity consumed by ultimate consumers in the 15 state regional market with both values expressed in kWh units. The performance measure for this index will be computed in accordance with the following payment schedule. MARKETING BUSINESS UNIT TARGET AWARD PAYMENT SCHEDULE MARKET SHARE OF ELECTRICITY Results (market share %) Performance Factor* ------------------------ ------------------- Over 8.25% 1.50 8.20% 1.25 8.15% 1.00 8.00% 0.50 Below 7.90% 0.00 *Interpolate at intermediate performance 5.4 ACHIEVEMENT OF THE MARKET SHARE OF ENERGY OBJECTIVE is measured by comparing the actual market share performance of retail energy sales against the market share of electricity objectives for the current year. Market share of energy is computed by dividing the AEP total retail energy sales by the energy consumed in the 15 state regional market with both values expressed in Btu equivalents. The performance measure for this index will be computed in accordance with the following payment schedule. MARKETING BUSINESS UNIT TARGET AWARD PAYMENT SCHEDULE MARKET SHARE OF ENERGY Results (market share %) Performance Factor* ------------------------ ------------------- Over 3.25% 1.50 3.20% 1.25 3.15% 1.00 3.05% 0.50 Below 3.00% 0.00 *Interpolate at intermediate performance 5.5 ACHIEVEMENT OF THE LOYALTY OBJECTIVE is measured by comparing the actual performance against loyalty objectives for the current year. The loyalty objective performance will be based on a weighted average of the performance factors of the National Key Account Benchmark study by TQS Research (TQS), the Commercial and Industrial Customer Satisfaction Study by RKS Research and Consulting (RKS), and the Corporate Positioning and Communication Tracking Study by Market Strategies, Inc. (MSI) survey instruments in proportions of 61.3%, 28.5%, and 10.2%, respectively. The TQS, RKS, and MSI represent the key accounts, major accounts, and residential segments, respectively. The "Customer Loyalty - Electric" score will be utilized from the TQS study, the "Customer Assessment Score" will be utilized from the RKS study and the "Overall Satisfaction" score will utilized from the MSI study. The performance factor for each instrument will be computed in accordance with the following payment schedules. Note that while a percentile approach is preferred in the computation of a performance factor with all three of the instruments, a raw score is utilized in the RKS instrument as the timing of the study is not anticipated to permit comparison to other utilities' scores. MARKETING BUSINESS UNIT QS AND MSI TARGET AWARD PAYMENT SCHEDULE TQS AND MSI SCORE Results (market share %) Performance Factor* ------------------------ ------------------- Top 10% 1.50 15% 1.25 20% 1.00 25% 0.50 Bottom 70% 0.00 *Interpolate at intermediate performance MARKETING BUSINESS UNIT RKS TARGET AWARD PAYMENT SCHEDULE RKS SCORE Customer Acceptance Score Performance Factor* ------------------------- ------------------- Over 3.2% 1.50 3.1% 1.25 3.0% 1.00 2.9% 0.50 Below 2.85% 0.00 *Interpolate at intermediate performance The use of the RKS instrument is dependent on receiving results prior to computation of the annual MICP results. In the event this information is unavailable, the performance measures of the TQS and MSI will be computed as a weighed average in the proportions 85.7% and 14.3%, respectively. 6.0 POWER PLANT MANAGERS Incentive awards for Power Plant managers are from two sources: - - AEP Corporate performance - weighted 25%; and - - Performance as determined by Power Plant Incentive Compensation Plan - weighted 75%. 7.0 REGION PLANT SERVICES MANAGERS AND PRODUCTIONS SERVICES MANAGERS Incentive awards for the managers of the Northern and Southern Region Plant Services are from two sources: - - AEP Corporate performance - weighted 25%; and - - Performance as determined by the Region Plant Services Incentive Compensation Plan - weighted 75%. 8.0 CENTRAL MACHINE SHOP MANAGER Incentive awards for the Central Machine Shop Manager are from two sources: - - AEP Corporate performance - weighted 25%; and - - Performance as determined by the Central Machine Shop Incentive Compensation Plan - weighted 75%. 9.0 FUEL SUPPLY PERFORMANCE CRITERIA There are three overall Fuel Supply performance measures, which are weighted to determine a single Fuel Supply performance factor. These are as follows: - - Adjusted cost of coal produced from affiliated mines, measured by cents per million BTU (cents/MM BTU) for the current year as reduced to reflect extraordinary costs due to downsizing and/or other special expenses and a volume adjustment of 55cents/MM BTU for variance from budgeted tons - weighted at 50%; and - - Performance relative to the PUCO negotiated EFC cap - weighted at 25%; and - - Safety incidence rate as a percent of the industry incidence rate for the current year - weighted at 25%. The following describes each in greater detail. 9.1 ADJUSTED COST OF COAL PRODUCED FROM AFFILIATED MINES - The adjusted cost of coal produced as measured by cents/MM BTU is a measure of how efficiently affiliated mines produce clean coal for use in the System's power plants. Performance factors relate to achievement as follows: FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE AFFILIATED MINE COSTS Cents/MM BTU Performance Factor* ------------ ------------------- 154.3 or lower 1.50 156.3 1.25 158.3 1.00 160.3 0.75 162.3 0.50 164.3 0.25 166.3 or higher 0.00 *Interpolate at intermediate performance. 9.2 PUCO CAP PERFORMANCE - The PUCO cap performance measures the amount of operating loss as defined in the Settlement Agreement dated February 28, 1995. FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE PUCO CAP PERFORMANCE Cap Performance Performance Factor* --------------- ------------------- $5.0 million 1.50 $7.5 million 1.25 $10.0 million 1.00 $12.5 million 0.75 $15.0 million 0.50 $17.5 million 0.25 More than $20 million 0.00 *Interpolate at intermediate performance 9.3 SAFETY PERFORMANCE - Achievement of the safety objective is measured by comparing the incidence rate for the current year with the comparable coal industry incidence rate (including Fuel Supply). Performance factors relate to achievement as follows: FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE SAFETY - INCIDENCE RATE VS. COAL INDUSTRY Incidence Rate - Percent Industry Rate Performance Factor* --------------------- ------------------- 55 or lower 1.50 65 1.25 75 1.00 85 .75 90 .50 95 .25 higher than 95 0 *Interpolate at intermediate performance. Example: If Fuel Supply's incidence rate were 92% of the coal industry rate, the performance factor is: [(95%-92%)/(95%-90%) x 0.25] + .25 = .40 9.4 SENIOR VICE PRESIDENT AND SENIOR STAFF-FUEL SUPPLY - DELIVERED FUEL PRICES In addition to the awards allocated to Corporate performance and Fuel Supply performance, the Senior Vice President and Senior Staff-Fuel Supply are assigned a 25% award allocated to delivered fuel prices. (See Page A-4 for the target award payment schedule.) 9.5 VICE PRESIDENT - FUEL PROCUREMENT In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measure weighted 20%, the Vice President - Fuel Procurement has a single Department performance weighing of 50% for delivered fuel prices. Tables showing the performance factors and how they relate to achievement begin on page A-5 of the Addendum. 9.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS) MEASURES In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measures weighted 25%, the Fuel Supply General Mine Managers and General Superintendent (Meigs) have two Division/Mine performance measures which are weighted to determine a single Division/Mine performance award weighing of 50% for the mines for which they are responsible. These are as follows: - Adjusted cost of coal produced from affiliated mines, measured by cents per million BTU (cents/MM BTU) for the current year as reduced to reflect extraordinary costs due to downsizing and/or other special expenses, and a +/- volume adjustment of $.55/MM BTU for variance from budgeted tons - weighted at 75%; and - Safety incidence rate for the current year as a percent of the comparable industry incidence rate for either underground or surface mines (whichever is applicable) - weighted at 25%. Tables showing the performance factors and how they relate to achievement begin on page A-6 of the Addendum. The performance factor shall be zero for any mine whose lost workdays charged for any single occurrence total 6,000 days or higher. 9.7 MANAGER - RIVER TRANSPORTATION MEASURES - The Manager-River Transportation has, in addition to the overall Corporate performance measures weighted 25%, two Department perform- ance measures which are weighted to determine a single Department performance weighing of 75% for River Transportation. These are: - Operating costs measured by adjusted mils per ton mile (mils/ton mile - $0.00x) for the current year, excluding cost for fuel, associated taxes and other fixed and special expenses, as approved by the SVP-Fuel Supply, with a +/- volume adjustment of 1.55 mils/ton mile for variance from budgeted mils per ton mile - weighted 75%; and - Safety incidence rate for the current year as a percent of the most recently published incidence rate for the water transportation industry - weighted 25%. The performance factor shall be zero for any operation whose lost workdays charged for any single occurrence total 6,000 days or higher. Tables showing the performance factors and how they relate to achievement are on page A-9 of the Addendum. 9.8 MANAGER - COOK COAL TERMINAL MEASURES - The Manager-Cook Coal Terminal (CCT) has, in addition to the overall Corporate performance measures weighted 25%, two Department performance measures which are weighted to determine a single Department performance weighing of 75% for Cook Coal Terminal. These are: - Operating costs measured by adjusted cost per ton of affiliated coal transloaded less other fixed and special expenses (e.g., harbor dredging), as approved by the SVP- Fuel Supply, +/- adjustment volumes times $.28/ton - weighted 75%; and - Safety incidence rate at CCT for the current year as a percent of the most recently published incidence rate for the coal preparation plants - weighted 25%. The performance factor shall be zero for any operation whose lost workdays charged for any single occurrence total 6,000 days or higher. Tables showing the performance factors and how they relate to achievement are on page A-10. 9.9 MANAGING DIRECTOR - TRANSPORTATION - In addition to the Corporate performance measures weighted 25% and the overall Fuel Supply performance measure weighted 20%, there are two overall transportation department performance criteria which are weighted to determine a single department performance factor. These are: - Transportation cost of fuel delivered comprised of performance at Cook Coal Terminal (adjusted cost per ton), River Transportation (adjusted cost per ton mile) and delivered fuel prices - each weighted 25%; and - Safety incidence rate at River Transportation and Cook Coal for the current year as a percent of the most recently published comparable industry rate for each location (RTD vs water transportation industry; CCT vs coal preparation plants) - each weighted 12.5%. Tables showing the performance factors and how they relate to achievement are on page A-11. 9.10 SENIOR VICE PRESIDENT, VICE PRESIDENTS, SENIOR STAFF-FUEL SUPPLY, AND MANAGING DIRECTOR-TRANSPORTATION In addition to other measures, the Lancaster based participants are assigned a 5% award allocated to Power Generation Production Costs. The Power Generation Production Cost measures the cost of fuel consumed and the operating and maintenance costs at the fossil power plants. (See page A-6 for the target award payment schedule.) 10.0 POWER GENERATION PERFORMANCE CRITERIA There are five performance criteria that are used as part of the power plant and power plant technical support portion of the performance for Power Generation Group. The participant's function within the organization determines the performance criteria weighting. Tables showing the performance factors and how they relate to achievement begin on page A-13 of the Addendum. 11.0 DEPARTMENT/BUSINESS UNIT OBJECTIVES Performance criteria, with appropriate weightings, may be established each year based on agreed objectives in each department/business unit. The performance rating scale is similar to those used in other measures, with ratings from 0 to 1.5, and 1.0 as target performance. Department/Business Unit Heads who set objectives which are subjective in nature will determine the degree of accomplishment in accordance with the 0 to 1.5 scale, taking into consideration such factors as timeliness, degree of accomplishment, acceptability of results, etc. In situations where a participant who has been assigned objectives leaves the position during a Plan year, his successor will generally assume the same objectives and both participants will share the final performance factor score. 12.0 THE MICP IN ACTION Following is an illustration to demonstrate the mechanics of the MICP. For purposes of this example, assume that an Energy Distribution Region Manager with annual base salary earnings of $100,000 has a target award of 20%, or $20,000. This individual's target award is allocated among the following performance criteria: - AEP Corporate Performance: 50%, or $10,000 - Energy Distribution Region: 50%, or $10,000 12.1 In determining the AEP Corporate portion of the MICP award, results are measured for three separate Corporate performance criteria to arrive at a single Corporate performance factor. ROE is measured in two ways, averaged, and given a 25% weighing; Total Investor Return (TIR) is given a 25% weighing; and Realization Ratio is given a 50% weighing. ROE 14% actual ROE = 1.00 S&P ranking (7th) = 1.40 -------------------------- Average 1.20 x 25% = .30 TIR S&P ranking (12th) = .80 x 25% = .20 Realization Ratio AEP ratio (.80) = 1.25 x 50% = .625 Corporate Performance Factor = 1.125 The AEP Corporate award, then, is 1.125 x $10,000, or $11,250. 12.2 In determining the Energy Distribution Region's portion of the MICP award, results are measured against six Energy Distribution performance criteria to arrive at the Region's performance factor. Customer Result Satisfaction TQS/MSI = 15% (1.25) = 1.20 x 20% = 0.24 & Loyalty RSK = 2.95 (0.75) Safety Performance Result = 0.70 = 1.50 x 20% = 0.30 O&M Expense Performance vs. Budget Result = 93% = 1.25 x 20% = 0.25 M&S Inventory Reduction Result = 75% = 0.75 x 10% = 0.075 Customer Service Reliability Result = 105% = 0.50 x 20% = 0.10 Index Marketing Performance Result = 100% = 1.00 x 10% = 0.10 ====== Energy Distribution Performance Factor = 1.065 The Energy Distribution Business Unit Award, then, is 1.065 x $10,000 or $10,650. 12.3 The Energy Distribution Region Manager in our example earned a total award of $20,700, as follows: - AEP Corporate $11,250.00 - Energy Distribution Business Unit 10,650.00 $21,900.00 Of that amount, 80%, or $17,520.00 is paid during the first part of the following year, assuming the participant has not elected to defer receipt of that payment under Section 16.2. The balance, $4,380.00, is deferred in AEP common stock units for three years. (No actual shares of stock are purchased--the amount deferred is merely treated as if shares had been purchased with these funds.) During that time dividends, which are credited on the deferred stock units, are used to "purchase" additional deferred stock units. After three years, the individual will receive a cash payment in the amount of the deferred units' value, which shall be equal to the average daily high and low market price of AEP common stock for the quarter preceding the payment date.(See page A-1 in the Addendum for further details.) A participant may elect to defer the 20% award beyond the mandatory three years in accordance with Section 16.2. 13.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT 13.1 TERMINATION AFTER COMPLETION OF PLAN YEAR - A participant who is actively employed on December 31 of the Plan year is entitled to receive the regular cash award (80%) for that year and, if applicable, the value of his prior deferred award that has met the three calendar year requirement. For example, an employee who is actively employed on 12/31/96, and subsequently terminates is entitled to the 80% cash award for Plan year 1996, and if applicable, the value of any 1993 Plan year deferred amount. Alternatively, a participant may elect to defer receipt of awards in accordance with Section 16.2. 13.2 TERMINATION DUE TO DEATH, RETIREMENT, OR DISABILITY - If a participant should leave active employment during a Plan year because of death, retirement, or disability, the award will be pro-rated based on the time the participant was actively employed in positions covered by the Plan during that year. Full payment of 100% of the pro-rated award will be made as soon as practicable in the following year. The mandatory deferrals of the 20% portions of any awards are normally paid as soon as practicable after the participant's death, retirement, or disability. For purposes of this Plan, disability shall mean the employee meets the definition of permanent and total disability under the AEP System Retirement Plan. For purposes of this Section 13.2 and Section 13.4, "retirement" occurs on the date an employee who is at least age 55 and who has five or more years of vesting service, ceases active employment with the company. In situations where a participant retires, plan participation ends on the date that full control and responsibility for the function ceased. The manager who is on vacation prior to and extending immediately into retirement has effectively ended his responsibility for managing the unit. Upon the death of an active or terminated participant, all deferred awards are immediately payable to the participant's surviving spouse. If the participant's spouse is not living, the deferred awards are immediately payable to the participant's estate. 13.3 INVOLUNTARY TERMINATION DURING PLAN YEAR - If a participant is involuntarily terminated from employment during a Plan year because of (1) the permanent closing of an office, plant or other facility, or (2) as a direct result of restructuring, consolidation, change in control of the corporation or downsizing, the award will be pro-rated based on the time the participant was actively employed in positions covered by the Plan during that year. Full payment of 100% of the pro-rated award will be made as soon as practicable in the following year. Deferred awards are payable as soon as practicable after the participant's involuntary termination. 13.4 Any potential award for the current Plan year, and all mandatory deferrals of the 20% portions of any awards that have not met the three calendar year requirement pursuant to Section 16.1, are forfeited when a participant terminates active employment during the Plan year for reasons other than (1) death, retirement, disability, or (2) involuntary termination as described in Section 13.3. 14.0 CHANGES IN SALARY/POSITION/PARTICIPATION Awards are paid as a percentage of the performance year's annual base earnings, including merit and promotional increases. In situations where participation changes as a result of job assignment, the employee will be entitled to a pro-rata share of any incentive award earned during the period he or she is employed in a position covered by the Plan. In the event an MICP participant is transferred from a position covered by the Plan to another such covered position within the AEP System, the participant will be entitled to a pro-rata share of any incentive award earned during the period he or she is employed in each of the positions. If the participant is subject to different target awards as a percent of base salary in the same performance year, each target award percentage will be applied to the base salary earned during the period employed in the related position. 15.0 PLAN ADMINISTRATION The MICP is administered by the Human Resources Committee of the American Electric Power Company, Inc. Board of Directors through the Executive Compensation Committee of AEPSC. Subject to the approval of the Chief Executive Officer, the Executive Compensation Committee's interpretation of the Plan's provisions are conclusive and binding on all participants. Participation in the MICP in any Plan year shall not be viewed as conferring any right to continued employment, or to continued participation in the MICP. Subject to the approval of the Chief Executive Officer, the Executive Compensation Committee of AEPSC may vary performance criteria, weights, and/or performance factor schedules from time to time when appropriate, enlarge or diminish the number of participants, or make other adjustments or amendments to improve the workings of the Plan. The Board of Directors reserves a right to amend or terminate the MICP. Amendment or termination of the Plan will not adversely affect any funds deferred into stock unit accounts prior to the amendment or termination. For good and sufficient cause, on petition by a senior officer of the Company, and with the approval of the Chief Executive Officer, any performance factor(s) for any participant(s) may be varied not more than plus or minus 25% to reflect exceptional circumstance. 16.0 MICP AWARD DISTRIBUTIONS AND DEFERRALS 16.1 When all of the necessary data are available after the end of the Plan year, performance results will be calculated and awards made as soon as practicable. Unless the participant has made an election to defer receipt of an additional portion of the entire award in accordance with Section 16.2, eighty percent of the award earned will be paid in cash. Twenty percent of any awards made under the MICP will be deferred. All deferrals are invested in AEP stock unit accounts. No AEP stock is actually purchased -- the amount deferred is treated as if actual shares had been purchased. The number of stock units is determined by dividing the amount deferred by the average of the daily high and low AEP common stock prices during the Plan year in which the incentive award was earned. An amount equal to AEP common stock dividends is credited on the date payable each calendar quarter commencing with the first quarter of the year following the year in which the award was earned. Those amounts are "reinvested" to "purchase" additional deferred stock units at the average of the daily high and low market price for the quarter in which the stock dividend applies. Amounts deferred in stock units are payable in cash to participants after the end of three calendar years following the end of the year for which the 80% portion of the award was scheduled to be paid. However, a participant may elect to defer receipt as outlined in Section 16.2. The value of stock units paid is based on the average daily high and low market price of AEP common stock for the quarter immediately preceding the date of payment. Because amounts held in deferred stock unit accounts do not involve the actual purchase of stock, Plan participants are not entitled to voting or certain other rights applicable to an actual shareholder. Amounts held in deferred stock unit accounts may not be assigned, transferred, or pledged by a Plan participant nor will they be subject to execution, attachment or other similar process. If the Executive Compensation Committee determines that the occurrence of any merger, reclassification, consolidation, recapitalization, stock dividend or stock split requires an adjustment in order to preserve the benefits intended under the Plan, then the Committee may, in its discretion, make equitable proportionate adjustments in the number of deferred stock units held by participants. 16.2 Elections to defer receipt of a portion of the Plan's 80% cash award (up to the full amount) or any previously deferred 20% awards must be executed one year prior to the date each award would otherwise be payable. The initial elective deferral period is one 3-year term for the 80% cash award. Subsequent deferrals, following the initial deferral period, shall apply to the aggregate amounts initially deferred and shall be for periods of not less than one year; however, if the participant's elective deferral period extends beyond the participant's employment termination date and the participant's termination occurred under circumstances other than those described in Section 13.3, payment will be made no later than five years after the participant's termination of employment. All amounts deferred in accordance with the preceding are reinvested in AEP stock unit accounts described in Section 16.1. 17.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA If estimated data are required to calculate corporate performance awards, or if corrections are made to data previously reported as final, adjustments to awards may be made when final data are available. 18.0 FUEL SUPPLY PAYMENT SCHEDULES 18.1 SENIOR VICE PRESIDENT - FUEL SUPPLY 18.2 FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE DELIVERED FUEL PRICES Cents/MM BTU Performance Factor* ------------ ------------------- 135.0 1.50 136.5 1.25 138.0 1.00 139.5 0.75 141.0 0.50 142.5 0.25 144.0 0.00 *Interpolate at intermediate performance. 18.3 VICE PRESIDENT - FUEL PROCUREMENT 18.4 Fuel Supply Target Award Payment Schedule DELIVERED FUEL PRICES Cents/MM BTU Performance Factor* ------------ ------------------- 135.0 1.50 136.5 1.25 138.0 1.00 139.5 0.75 141.0 0.50 142.5 0.25 144.0 0.00 *Interpolate at intermediate performance. 18.5 FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE POWER GENERATION PRODUCTION COST mils/KWH Performance Factor* -------- ------------------- 16.78 or lower 1.50 16.98 1.25 17.18 1.00 17.38 0.50 17.58 0.00 *Interpolate at intermediate performance. 18.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS) 18.7 SOUTHERN OHIO COAL COMPANY - MEIGS ADJUSTED COST OF COAL PRODUCED Cents/MM BTU Performance Factor* ------------ ------------------- 150.4 or lower 1.50 152.4 1.25 154.4 1.00 156.4 0.75 158.4 0.50 160.4 0.25 162.4 or higher 0.00 *Interpolate at intermediate performance. 18.8 CENTRAL OHIO COAL COMPANY ADJUSTED COST OF COAL PRODUCED Cents/MM BTU Performance Factor* ------------ ------------------- 226.4 or lower 1.50 228.4 1.25 230.4 1.00 232.4 0.75 234.4 0.50 236.4 0.25 238.4 or higher 0.00 *Interpolate at intermediate performance. 18.9 WINDSOR COAL COMPANY ADJUSTED COST OF COAL PRODUCED Cents/MM BTU Performance Factor* ------------ ------------------- 127.2 or lower 1.50 129.2 1.25 131.2 1.00 133.2 0.75 135.5 0.50 137.2 0.25 139.2 or higher 0.00 *Interpolate at intermediate performance. 18.10 ALL COAL MINES SAFETY INCIDENCE RATE Incidence Rate - Percent Industry Rate Performance Factor* --------------------- ------------------- 55 or lower 1.50 65 1.25 75 1.00 85 0.75 90 0.50 95 0.25 Higher than 95 0.00 *Interpolate at intermediate performance. 18.11 MANAGER - RIVER TRANSPORTATION 18.12 RIVER TRANSPORTATION OPERATING COST PER TON MILE Mils/Ton Mile ($.00x) Performance Factor* ------------- ------------------- 4.07 or lower 1.50 4.12 1.25 4.17 1.00 4.22 0.75 4.27 0.50 4.32 0.25 4.37 or higher 0.00 *Interpolate at intermediate performance. 18.13 RIVER TRANSPORTATION SAFETY INCIDENCE RATE Incidence Rate - % Industry Rate Performance Factor* ---------------- ------------------- 55 or lower 1.50 65 1.25 75 1.00 85 0.75 90 0.50 95 0.25 Higher than 95 0.00 *Interpolate at intermediate performance. 18.14 MANAGER - COOK COAL TERMINAL 18.15 COOK COAL TERMINAL ADJUSTED COST PER TON Adjusted Cost per Ton Performance Factor* --------------------- ------------------- $1.47 or better 1.50 $1.49 1.25 $1.51 1.00 $1.53 0.75 $1.55 0.50 $1.57 0.25 $1.59 or higher 0.00 *Interpolate at intermediate performance. 18.16 COOK COAL TERMINAL SAFETY INCIDENCE RATE Incidence Rate - % Industry Rate Performance Factor* ---------------- ------------------- 55 or better 1.50 65 1.25 75 1.00 85 0.75 90 0.50 95 0.25 Higher than 95 0.00 *Interpolate at intermediate performance. 18.17 MANAGING DIRECTOR - TRANSPORTATION 18.18 COOK COAL TERMINAL ADJUSTED COST PER TON Adjusted Cost Ton Performance Factor* ----------------- ------------------- $1.47 or better 1.50 $1.49 1.25 $1.51 1.00 $1.53 0.75 $1.55 0.50 $1.57 0.25 $1.59 or higher 0.00 *Interpolate at intermediate performance. 18.19 RIVER TRANSPORTATION OPERATING COST PER TON MILE Mils/Ton Mile ($.00x) Performance Factor* --------------------- ------------------- 4.07 or lower 1.50 4.12 1.25 4.17 1.00 4.22 0.75 4.27 0.50 4.32 0.25 4.37 or higher 0.00 *Interpolate at intermediate performance. 18.20 DELIVERED FUEL PRICES Cents/MM BTU Performance Factor* ------------ ------------------- 135.0 1.50 136.5 1.25 138.0 1.00 139.5 0.75 141.0 0.50 142.5 0.25 Higher than 144.0 0.00 *Interpolate at intermediate performance 18.21 RIVER TRANSPORTATION AND COOK COAL TERMINAL SAFETY INCIDENCE RATE Incidence Rate - % Industry Rate Performance Factor* ---------------- ------------------- 55 or lower 1.50 65 1.25 75 1.00 85 0.75 90 0.50 95 0.25 Higher than 95 0.00 *Interpolate at intermediate performance 19.0 POWER GENERATION DEPARTMENT/ BUSINESS UNIT PAYMENT SCHEDULES 19.1 O&M EXPENDITURE Actual O&M (Mils/KWH) Performance Factor* --------------------- ------------------- 3.29 or lower 1.50 3.34 1.25 3.39 1.00 3.44 0.50 3.49 or higher 0.00 *Interpolate at intermediate performance 19.2 POWER GENERATION PRODUCTION COST Actual O&M (Mils/KWH) Performance Factor* --------------------- ------------------- 16.78 or lower 1.50 16.98 1.25 17.18 1.00 17.38 0.50 17.59 or higher 0.00 *Interpolate at intermediate performance. 19.3 CAPITAL EXPENDITURES Actual Capital Exenditures ($ Million) Performance Factor* ----------------------- ------------------- 135.5 or lower 1.50 140.3 1.25 145.3 1.00 150.3 0.50 155.4 or higher 0.00 *Interpolate at intermediate performance 19.4 EQUIVALENT AVAILABILITY Equivalent Availability (%) Performance Factor* --------------------------- ------------------- 84.0 1.50 82.0 1.25 80.0 1.00 78.0 0.75 76.0 0.50 74.0 or lower 0.00 *Interpolate at intermediate performance 19.5 HEAT RATE Heat Rate (BTU/KWH) Performance Factor* ------------------- ------------------- 9,655 1.50 9,663 1.25 9,670 1.00 9,677 0.75 9,685 0.50 9,700 or Higher 0.00 *Interpolate at intermediate performance.
EX-27 3 ARTICLE UT FIN. DATA SCH. FOR 10-Q
UT 0000004904 AMERICAN ELECTRIC POWER COMPANY, INC. 1,000 6-MOS DEC-31-1995 JUN-30-1996 PER-BOOK 11,344,321 857,200 1,492,995 245,711 1,917,335 15,857,562 1,276,827 1,687,101 1,478,193 4,442,121 515,082 118,240 4,766,759 72,650 0 453,821 55,674 150 332,407 97,597 5,003,061 15,857,562 2,918,722 173,427 2,232,548 2,405,975 512,747 (97) 512,650 198,388 292,678 21,584 292,678 224,188 130,507 554,285 $1.57 $1.57 Represents preferred stock dividend requirements of subsidiaries; deducted before computation of net income.
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