10-Q 1 xq201mod.txt COMBINED 10Q 6/30/01 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, 2001 [ ] 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 0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600 539 North Carancahua Street, Corpus Christi, Texas 78401-2802 Telephone (361)881-5300 1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203 1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455 One Summit Square P.O. Box 60, Fort Wayne, Indiana 46801 Telephone (219) 425-2111 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1701 Central Avenue, Ashland, Kentucky 41101 Telephone (800) 572-1141 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 301 Cleveland Avenue S.W., Canton, Ohio 44701 Telephone (330) 456-8173 0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895 (An Oklahoma Corporation) 212 East 6th Street, Tulsa, Oklahoma 74119-1212 Telephone (918) 599-2000 1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455 (A Delaware Corporation) 428 Travis Street, Shreveport, Louisiana 71156-0001 Telephone (318) 673-3000 0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790 301 Cypress Street, Abilene, Texas 79601-5820 Telephone (915) 674-7000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities 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, 2001 was 322,201,830. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 30, 2001 CONTENTS
Page Glossary of Terms i - iii Forward-Looking Information iv Part I. FINANCIAL INFORMATION Items 1 and 2 Financial Statements and Management's Discussion and Analysis of Results of Operations: American Electric Power Company, Inc. and Subsidiary Companies: Management's Discussion and Analysis of Results of Operations A-1 - A-2 Consolidated Financial Statements A-3 - A-7 AEP Generating Company: Management's Narrative Analysis of Results of Operations B-1 Financial Statements B-2 - B-5 Appalachian Power Company, Inc. and Subsidiaries: Management's Discussion and Analysis of Results of Operations C-1 - C-2 Consolidated Financial Statements C-3 - C-7 Central Power and Light Company and Subsidiary: Management's Discussion and Analysis of Results of Operations D-1 - D-2 Consolidated Financial Statements D-3 - D-6 Columbus Southern Power Company and Subsidiaries: Management's Narrative Analysis of Results of Operations E-1 - E-2 Consolidated Financial Statements E-3 - E-6 Indiana Michigan Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations F-1 - F-2 Consolidated Financial Statements F-3 - F-7 Kentucky Power Company Management's Narrative Analysis of Results of Operations G-1 - G-2 Financial Statements G-3 - G-7 Ohio Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations H-1 - H-2 Consolidated Financial Statements H-3 - H-7 Public Service Company of Oklahoma and Subsidiaries: Management's Narrative Analysis of Results of Operations I-1 - I-2 Consolidated Financial Statements I-3 - I-6 Southwestern Electric Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations J-1 - J-2 Consolidated Financial Statements J-3 - J-6 West Texas Utilities Company: Management's Narrative Analysis of Results of Operations K-1 - K-2 Financial Statements K-3 - K-6 Footnotes to Financial Statements L-1 - L-12 Item 2. Registrants' Combined Management Discussion and Analysis of Financial Condition, Contingencies and Other Matters M-1 - M-8 Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1 - N-2 Part II. OTHER INFORMATION Item 1. Legal Proceedings O-1 Item 4. Submission of Matters to a Vote of Security Holders O-1 - O-3 Item 5. Other Information O-3 Item 6. Exhibits and Reports on Form 8-K O-4 (a) Exhibits Exhibit 12 (b) Reports on Form 8-K SIGNATURE P-1
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities 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.
GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. Term Meaning 2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs. AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP. AEP................................ American Electric Power Company, Inc. AEP Consolidated................... AEP and its majority owned subsidiaries consolidated. AEP Credit......................... AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and unaffiliated domestic electric utility companies. AEP East electric operating companies.......................... APCo, CSPCo, I&M, KPCo and OPCo. AEPR............................... AEP Resources, Inc. AEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. AEP West electric operating companies.......................... CPL, PSO, SWEPCo and WTU. AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities. Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo. APCo............................... Appalachian Power Company, an AEP electric utility subsidiary. Arkansas Commission................ Arkansas Public Service Commission. Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation. CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation. COLI............................... Corporate owned life insurance program. Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M. CPL................................ Central Power and Light Company, an AEP electric utility subsidiary. CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary. CSW............................... Central and South West Corporation, a subsidiary of AEP. CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants. CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States. D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit. DHMV............................... Dolet Hills Mining Venture. DOE................................ United States Department of Energy. ECOM............................... Excess Cost Over Market. ENEC............................... Expanded Net Energy Costs. EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force. ERCOT.............................. The Electric Reliability Council of Texas. EWGs............................... Exempt Wholesale Generators. FASB............................... Financial Accounting Standards Board. Federal EPA........................ United States Environmental Protection Agency. FERC............................... Federal Energy Regulatory Commission. FMB ............................... First Mortgage Bond. FUCOs.............................. Foreign Utility Companies. i GAAP............................... Generally Accepted Accounting Principles. HPL................................ Houston Pipe Line Company. I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary. IPC................................ Installment Purchase Contract. IRS................................ Internal Revenue Service. IURC............................... Indiana Utility Regulatory Commission. ISO................................ Independent system operator. Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding. KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary. KPSC............................... Kentucky Public Service Commission. KWH................................ Kilowatthour. LIG................................ Louisiana Intrastate Gas. Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier. Midwest ISO........................ An independent operator of transmission assets in the Midwest. MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members. Money Pool......................... AEP System's Money Pool. MPSC............................... Michigan Public Service Commission. MTN................................ Medium Term Notes. MW................................. Megawatt. MWH................................ Megawatthour. NEIL............................... Nuclear Electric Insurance Limited. Nox................................ Nitrogen oxide. Nox Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operates. NP................................. Notes Payable. NRC................................ Nuclear Regulatory Commission. Ohio Act........................... The Ohio Electric Restructuring Act of 1999. Ohio EPA........................... Ohio Environmental Protection Agency. OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary. OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest. PCBs............................... Polychlorinated Biphenyls. PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization. PRP.............................. Potentially Responsible Party. PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary. PUCO............................... The Public Utilities Commission of Ohio. PUCT............................... The Public Utility Commission of Texas. PUHCA.............................. Public Utility Holding Company Act of 1935, as amended. PURPA.............................. The Public Utility Regulatory Policies Act of 1978. RCRA............................... Resource Conservation and Recovery Act of 1976, as amended. Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU. Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M. RTO................................ Regional Transmission Organization. SEC................................ Securities and Exchange Commission. SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board. SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain ------------------------------------- Types of Regulation. ------------------- SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of ------------------------------------ Application of Statement 71. ii SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of -------------------------------- Long-Lived Assets and for Long-Lived Assets to be Disposed of. -------------------------------------------------------------- SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments ------------------------------------- and Hedging Activities. ----------------------- SNF................................ Spent Nuclear Fuel. SPP................................ Southwest Power Pool. STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light Company, an AEP electric utility subsidiary . STPNOC............................. South Texas Project Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including CPL. Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act. SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary. Texas Appeals Court................ The Third District of Texas Court of Appeals. Texas Restructuring Legislation.... Legislation enacted in 1999 to restructure the electric utility industry in Texas. Travis District Court.............. State District Court of Travis County, Texas. TVA ............................... Tennessee Valley Authority. U.K................................ The United Kingdom. UN................................. Unsecured Note. VaR................................ Value at Risk, a method to quantify risk exposure. Virginia SCC....................... Virginia State Corporation Commission. WV................................. West Virginia. WVPSC.............................. Public Service Commission of West Virginia. WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary. WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary. Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP and New Century Energies. Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary.
iii FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to our power generation business. o The structure and timing of a competitive market and its impact on energy prices or fixed rates. o The ability to recover stranded costs in connection with possible/proposed deregulation of generation. o New legislation and government regulations. o The ability of AEP to successfully control its costs. o The success of new business ventures. o International developments affecting AEP's foreign investments. o The economic climate and growth in AEP's service territory. o Inflationary trends. o Electricity and gas market prices. o Interest rates o Other risks and unforeseen events. iv AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 Net income increased by $241 million or 75 cents per share for the quarter and by $367 million or $1.13 per share year-to-date predominately due to strong performance from the wholesale business. Benefiting from an increased contribution from wholesale natural gas trading activities and the favorable impact of the return to service of the Cook Plant, the earnings from our wholesale business increased 116 percent over the same quarter last year. The effects of deregulation resulted in a $57 million unfavorable variance between periods from extraordinary items, and this factor partially offsets our improved wholesale business results. Income statement line items which changed significantly were:
Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Revenues $6,391 78 $14,439 101 Fuel and Purchase Power Expense 6,049 96 13,804 129 Maintenance and Other Operation Expense 89 10 191 11 Writeoff of Merger-Related Costs (154) (96) (149) (93) Other Income (Loss), net 27 N.M. 89 241 Interest and Preferred Dividends (28) (10) (12) (2) Income Taxes 121 233 214 166 Extraordinary Items (57) N.M. (57) N.M. N.M. = Not Meaningful
The increase in revenues was due to a substantial increase in electric and gas trading volumes and wholesale energy sales. Wholesale natural gas trading volume for the quarter was 774 billion cubic feet, a 178 percent increase from second-quarter 2000 volume of 278 million cubic feet. Electric trading volume for the quarter increased 16 percent to 121 million MWH and the average price per KWH increased 35%. In the first half of 2001, the average price per KWH sold and purchased moved upward reflecting market conditions during a period of high volatility in prices, especially natural gas. The increase in electric trading volume is primarily from: o continued expansion of our trading team o increased liquidity in the markets where we trade The increase in gas trading volume is from: o continued expansion of our trading team o HPL acquisition on June 1, 2001 o expansion into markets where we have not traded historically Our fuel and purchased power expense increased due to increased trading volume, particularly gas, and an increase in generation. Our generation increased 3% in 2001 due mainly to the return to service in June 2000 and December 2000 of Cook Plant's two generating units. Our maintenance and other operation expense increased largely as a result of additional traders' incentive compensation and costs associated with the development of gas-fired plants. This increase was offset, in part, by no longer incurring expenditures to prepare the Cook Plant units for restart following an extended outage. Revenues from project fees offset the charges for development costs thus not adversely affecting net income. The write-off of deferred merger costs in 2000 included transaction and transition costs not recoverable from ratepayers under regulatory commission approved settlement agreements. In March 2001, we completed the sale of Frontera, one of the generating plants required to be divested under FERC - approved merger settlement agreements. The sale resulted in a $73 million gain recorded in other income for the year-to-date period. Our interest and preferred dividends decreased primarily because of lower average outstanding short-term debt balances and a decrease in average short-term interest rates. Our income taxes increased due to an increase in pre-tax income. In the second quarter of 2001 we recorded an extraordinary loss for $48 million net of tax to write-off stranded prepaid Ohio excise taxes (See Note 2). We discontinued the application of regulatory accounting for generation in Virginia and West Virginia during the second quarter of 2000 which resulted in an after tax extraordinary gain of $9 million in 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in millions, except per-share amounts) (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- REVENUES $14,528 $8,137 $28,693 $14,254 ------- ------ ------- ------- EXPENSES: Fuel and Purchased Power 12,367 6,318 24,469 10,665 Maintenance and Other Operation 959 870 1,912 1,721 Non-recoverable Merger Costs 7 161 12 161 Depreciation and Amortization 354 305 690 625 Taxes Other Than Income Taxes 169 175 337 346 --- --- --- --- TOTAL EXPENSES 13,856 7,829 27,420 13,518 ------ ----- ------ ------ OPERATING INCOME 672 308 1,273 736 OTHER INCOME (LOSS), net 22 (5) 126 37 -- -- --- -- INCOME BEFORE INTEREST, PREFERRED DIVIDENDS AND INCOME TAXES 694 303 1,399 773 INTEREST AND PREFERRED DIVIDENDS 241 269 510 522 --- --- --- --- INCOME BEFORE INCOME TAXES 453 34 889 251 INCOME TAXES 173 52 343 129 --- -- --- --- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 280 (18) 546 122 EXTRAORDINARY GAIN (LOSS): EFFECTS OF DEREGULATION (48) 9 (48) 9 --- - --- - NET INCOME (LOSS) $ 232 $ (9) $ 498 $ 131 ======== ======== ======== ===== AVERAGE NUMBER OF SHARES OUTSTANDING 322 322 322 322 === === === === EARNINGS (LOSS) PER SHARE: Income (Loss) Before Extraordinary Item $ 0.87 $(0.06) $ 1.69 $0.38 Extraordinary Gain (Loss) (0.15) 0.03 (0.15) 0.03 ------ ------ ----- ---- Earnings (Loss) Per Share (Basic and Dilutive) $0.72 $(0.03) $1.54 $0.41 ===== ====== ===== ===== CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.20 $1.20 ===== ===== ===== ===== See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in millions) ASSETS ------ CURRENT ASSETS: Cash and Cash Equivalents $ 212 $ 437 Accounts Receivable (net) 2,532 3,699 Energy Trading Contracts 11,720 16,627 Other 1,688 1,268 ----- ----- TOTAL CURRENT ASSETS 16,152 22,031 ------ ------ PROPERTY, PLANT AND EQUIPMENT: Electric: Production 16,553 16,328 Transmission 6,145 5,609 Distribution 10,973 10,843 Other (including gas and coal mining assets and nuclear fuel) 4,192 4,077 Construction Work in Progress 988 1,231 --- ----- Total Property, Plant and Equipment 38,851 38,088 Accumulated Depreciation and Amortization 15,984 15,695 ------ ------ NET PROPERTY, PLANT AND EQUIPMENT 22,867 22,393 ------ ------ REGULATORY ASSETS 3,716 3,698 ----- ----- INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS 521 782 --- --- GOODWILL (net of amortization) 1,300 1,382 ----- ----- LONG-TERM ENERGY TRADING CONTRACTS 3,166 1,620 ----- ----- OTHER ASSETS 2,505 2,642 ----- ----- TOTAL $50,227 $54,548 ======= ======= See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $1,252 $2,627 Short-term Debt 4,055 4,333 Long-term Debt Due Within One Year 1,024 1,152 Energy Trading Contracts 11,394 16,801 Other 1,925 2,154 ----- ----- TOTAL CURRENT LIABILITIES 19,650 27,067 ------ ------ LONG-TERM DEBT 10,609 9,602 ------ ----- CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 322 334 --- --- DEFERRED INCOME TAXES 4,914 4,875 ----- ----- DEFERRED INVESTMENT TAX CREDITS 510 528 --- --- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 199 203 --- --- LONG-TERM ENERGY TRADING CONTRACTS 2,965 1,381 ----- ----- DEFERRED CREDITS AND REGULATORY LIABILITIES 986 637 --- --- OTHER NONCURRENT LIABILITIES 1,763 1,706 ----- ----- CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 161 161 --- --- CONTINGENCIES (Note 8) COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50: 2001 2000 ---- ---- Shares Authorized. . . . . 600,000,000 600,000,000 Shares Issued. . . . . . . 331,201,100 331,019,146 (8,999,992 shares were held in treasury at June 30, 2001 and December 31, 2000) 2,153 2,152 Paid-in Capital 2,916 2,915 Accumulated Other Comprehensive Income (Loss) (131) (103) Retained Earnings 3,210 3,090 ----- ----- TOTAL COMMON SHAREHOLDERS' EQUITY 8,148 8,054 ----- ----- TOTAL $50,227 $54,548 ======= ======= See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in millions) OPERATING ACTIVITIES: Net Income $ 498 $ 131 Adjustments for Noncash Items: Depreciation and Amortization 709 666 Deferred Federal Income Taxes 19 19 Deferred Investment Tax Credits (17) (17) Amortization of Deferred Property Taxes 82 79 Amortization of Cook Plant Restart Costs 20 20 Deferred Costs Under Fuel Clause Mechanisms 50 (164) Extraordinary Gain (Loss) - Effects of Deregulation 48 (9) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 1,154 (475) Fuel, Materials and Supplies (108) 73 Accrued Utility Revenues (84) (108) Accounts Payable (1,643) 311 Taxes Accrued 39 (205) Customer Deposits (39) 7 Other (net) (89) 41 --- -- Net Cash Flows From Operating Activities 639 369 --- --- INVESTING ACTIVITIES: Construction Expenditures (819) (808) Purchase of Houston Pipe Line (727) - Sale of Yorkshire 383 - Sale of Frontera 265 - Other (276) (60) ---- --- Net Cash Flows Used For Investing Activities (1,174) (868) ------ ---- FINANCING ACTIVITIES: Issuance of Common Stock 9 12 Issuance of Long-term Debt 1,388 751 Change in Short-term Debt (net) (233) 1,104 Retirement of Long-term Debt (463) (1,239) Dividends Paid on Common Stock (387) (419) ---- ---- Net Cash Flows From Financing Activities 314 209 --- --- Effect of Exchange Rate Change on Cash (4) (7) -- -- Net Decrease in Cash and Cash Equivalents (225) (297) Cash and Cash Equivalents at Beginning of Period 437 609 --- --- Cash and Cash Equivalents at End of Period $ 212 $ 312 ===== =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $342 million and $471 million and for income taxes was $107 million and $206 million in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $21 million and $50 million in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (UNAUDITED) Accumulated Other Common Paid-in Retained Comprehensive Stock Capital Earnings Income (Loss) Total ----- ------- -------- ------------- ----- (in millions) JANUARY 1, 2000 $2,149 $2,898 $3,630 $(4) $8,673 Issuance of Common Stock 2 10 12 Common Stock Dividends (419) (419) Other (46) (46) --- 8,220 Comprehensive Income: Other Comprehensive Income, Net of Taxes Currency Translation Adjustment (115) (115) Unrealized Loss on Securities 20 20 Minimum Pension Liability (2) (2) Net Income 131 131 --- Total Comprehensive Income 34 -------- -------- -------- ------ -- JUNE 30, 2000 $2,151 $2,862 $3,342 $(101) $8,254 ====== ====== ====== ===== ====== JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054 Issuance of Common Stock 1 8 9 Common Stock Dividends (387) (387) Other (7) 9 2 - 7,678 Comprehensive Income: Other Comprehensive Income, Net of Taxes Currency Translation Adjustment (53) (53) Unrealized Gain on Hedged Derivatives 31 31 Minimum Pension Liability (6) (6) Net Income 498 498 --- Total Comprehensive Income 470 -------- -------- -------- ------ ------ JUNE 30, 2001 $2,153 $2,916 $3,210 $(131) $8,148 ====== ====== ====== ===== ====== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 Operating revenues are derived from the sale of Rockport Plant energy and capacity to two affiliated companies pursuant to 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. The increase in net income of $0.4 million or 25% for the quarter resulted primarily from an adjustment to the power bills to reflect the resolution of a tax issue. Net income for the year-to-date period declined $0.1 million or 1% primarily as a result of a final true-up billing in January 2000 to an unaffiliated utility whose unit power purchase contract expired on December 31, 1999. Income statement line items which changed significantly were:
Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $(4.7) (8) $(1.1) (1) Fuel Expense (5.8) (22) (2.6) (5) Other Operation Expense 0.4 21 0.3 5 Maintenance Expense 0.8 25 0.2 4 Taxes Other Than Federal Income Taxes (0.5) (43) 1.5 68 Interest Charges (0.3) (29) (0.4) (23)
The decrease in operating revenues resulted primarily from a decrease in recoverable expenses especially fuel. The Rockport Plant underwent scheduled maintenance outages in the second quarter of 2001. In 2000, maintenance outages occurred in the first quarter. Fuel expense decreased due to a decline in generation reflecting the length of outages in the second quarter 2001 and lower average fuel cost. Other operation and maintenance expense increased due to more extensive outages during the second quarter 2001 for boiler maintenance and repair. The decline in taxes other than federal income taxes for the quarter resulted from a decrease in an accrual for state taxes as a result of a revised taxable income estimate. Taxes other than federal income taxes for the year-to-date period increased due to the accrual of state income taxes based on an estimate of higher taxable income for 2001. Reductions in variable interest rates, reflecting market conditions, produced the decrease in interest charges.
AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $52,217 $56,928 $112,724 $113,794 ------- ------- -------- -------- OPERATING EXPENSES: Fuel 20,261 26,048 47,906 50,483 Rent - Rockport Plant Unit 2 17,070 17,070 34,141 34,141 Other Operation 2,368 1,956 5,326 5,054 Maintenance 3,971 3,166 5,897 5,681 Depreciation 5,602 5,541 11,188 11,046 Taxes Other Than Federal Income Taxes 641 1,124 3,769 2,250 Federal Income Taxes 422 277 808 998 --- --- --- --- TOTAL OPERATING EXPENSES 50,335 55,182 109,035 109,653 ------ ------ ------- ------- OPERATING INCOME 1,882 1,746 3,689 4,141 NONOPERATING INCOME 887 900 1,749 1,769 --- --- ----- ----- INCOME BEFORE INTEREST CHARGES 2,769 2,646 5,438 5,910 INTEREST CHARGES 706 993 1,395 1,812 --- --- ----- ----- NET INCOME $ 2,063 $ 1,653 $ 4,043 $ 4,098 ======= ======= ========== ==========
STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $10,743 $4,183 $ 9,722 $ 3,673 NET INCOME 2,063 1,653 4,043 4,098 CASH DIVIDENDS DECLARED 959 - 1,918 1,935 --- ------ ----- ----- BALANCE AT END OF PERIOD $11,847 $5,836 $11,847 $5,836 ======= ====== ======= ====== The common stock of AEGCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $636,583 $635,215 General 2,991 2,795 Construction Work in Progress 3,471 4,292 ----- ----- Total Electric Utility Plant 643,045 642,302 Accumulated Depreciation 325,671 315,566 ------- ------- NET ELECTRIC UTILITY PLANT 317,374 326,736 ------- ------- OTHER PROPERTY AND INVESTMENTS 119 6 --- - CURRENT ASSETS: Cash and Cash Equivalents 791 2,757 Accounts Receivable: Affiliated Companies 17,852 21,374 Miscellaneous 150 2,341 Fuel - at average cost 18,621 11,006 Materials and Supplies - at average cost 4,008 3,979 Prepayments 63 145 -- --- TOTAL CURRENT ASSETS 41,485 41,602 ------ ------ REGULATORY ASSETS 5,384 5,504 ----- ----- DEFERRED CHARGES 2,392 754 ----- --- TOTAL ASSETS $366,754 $374,602 ======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (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 23,434 23,434 Retained Earnings 11,847 9,722 ------ ----- Total Common Shareowner's Equity 36,281 34,156 Long-term Debt 44,812 - ------ - TOTAL CAPITALIZATION 81,093 34,156 ------ ------ OTHER NONCURRENT LIABILITIES 358 --- 358 CURRENT LIABILITIES: Long-term Debt Due Within One Year - 44,808 Advances from Affiliates 15,165 28,068 Accounts Payable: General 9,313 6,109 Affiliated Companies 11,372 7,724 Taxes Accrued 10,826 4,993 Rent Accrued - Rockport Plant Unit 2 4,963 4,963 Other 2,077 4,443 ----- ----- TOTAL CURRENT LIABILITIES 53,716 101,108 ------ ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 119,403 122,188 ------- ------- REGULATORY LIABILITIES: Deferred Investment Tax Credit 58,045 59,718 Amounts Due to Customers for Income Taxes 22,661 23,996 ------ ------ TOTAL REGULATORY LIABILITIES 80,706 83,714 ------ ------ DEFERRED INCOME TAXES 31,328 32,928 ------ ------ DEFERRED CREDITS 150 150 --- --- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $366,754 $374,602 ======== ======== See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 4,043 $ 4,098 Adjustments for Noncash Items: Depreciation 11,188 11,046 Deferred Federal Income Taxes (2,935) (2,769) Deferred Investment Tax Credits (1,673) (1,674) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (2,785) (2,785) Deferred Property Taxes (1,829) (1,648) Changes in Certain Current Assets and Liabilities: Accounts Receivable 5,713 3,343 Fuel, Materials and Supplies (7,644) (1,593) Accounts Payable 6,852 (15,562) Taxes Accrued 5,833 2,533 Other (net) (2,371) (1,270) ------ ------ Net Cash Flow From (Used For) Operating Activities 14,392 (6,281) ------ ------ INVESTING ACTIVITIES - Construction Expenditures (1,537) (2,295) ------ ------ FINANCING ACTIVITIES: Return of Capital to Parent Company - (2,935) Change in Short-term Debt (net) - (24,700) Change in Advances from Affiliates (net) (12,903) 37,870 Dividends Paid (1,918) (1,935) ------ ------ Net Cash Flows From (Used For) Financing Activities (14,821) 8,300 ------- ----- Net Decrease in Cash and Cash Equivalents (1,966) (276) Cash and Cash Equivalents at Beginning of Period 2,757 317 ----- --- Cash and Cash Equivalents at End of Period $ 791 $ 41 ========= ========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $1,143,000 and $1,619,000 and for income taxes was $1,350,000 and $3,129, 000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS ------------------------------------------------------------- SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income decreased $2.8 million or 7% for the quarter due to the effect of an extraordinary gain recorded in 2000 for the discontinuance of regulatory accounting partially offset by favorable wholesale business performance. Net income increased $11.4 million or 13% for the year-to-date period primarily due to growth in and strong performance by the wholesale business. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $389 27 $1,341 54 Fuel Expense (8) (8) (11) (6) Purchased Power Expense 377 33 1,303 73 Other Operation Expense 6 10 12 10 Maintenance Expense 5 17 10 17 Depreciation and Amortization 5 13 11 14 Nonoperating Income 4 127 9 205 Extraordinary Gain (9) N.M. (9) N.M. N.M. = Not Meaningful The significant increase in revenues is due to increased wholesale electricity prices and trading volume of our wholesale business. Expansion of the wholesale business' trading operation and greater liquidity in the market place resulted in an increase in the number of forward electricity purchase and sales contracts in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Wholesale trading volume increased 33% for the year-to-date period. The increase in wholesale prices is due to changes in market conditions during a period of high volatility in prices. Fuel expense of the wholesale business decreased due to a decline in generation as a result of scheduled plant maintenance. The increase in the wholesale business' purchased power expense is attributable to increases in wholesale electricity prices and trading volume. Other operation expense increased as a result of power trading incentive compensation expense of the wholesale business and a reduction in transmission equalization credits for the energy delivery business. APCo and certain affiliates share, through the Transmission Agreement, the costs associated with the ownership of the extra-high voltage transmission system and certain facilities at lower voltages based upon each company's peak demand and investment. An increase in APCo's peak demand relative to its affiliates' peak demand was the main reason for the decrease in transmission equalization credits. The increase in maintenance expense is mainly attributable to increased generating plant boiler maintenance repairs to the wholesale business' Amos, Mountaineer and Glen Lyn Plants. During June 2000 we discontinued the application of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net generation-related regulatory assets were transferred to the energy delivery business' regulated distribution business where the Virginia and West Virginia jurisdictions authorized the recovery of these assets through regulated rates. Depreciation and amortization expense increased due to the accelerated amortization beginning in July 2000 of the transition regulatory assets. Additional investments in the energy delivery business' distribution and transmission plant also contributed to the increase in depreciation and amortization expense. The increase in nonoperating income was due to an increase in net gains from the wholesale business' trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps).
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $1,849,304 $1,460,774 $3,823,431 $2,482,452 ---------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 85,049 92,663 180,525 191,220 Purchased Power 1,513,831 1,137,184 3,099,033 1,795,831 Other Operation 67,948 61,566 133,837 122,207 Maintenance 33,842 28,989 66,851 57,314 Depreciation and Amortization 44,056 38,899 87,773 77,237 Taxes Other Than Federal Income Taxes 29,975 28,817 61,843 59,462 Federal Income Taxes 15,241 14,448 46,055 42,727 ------ ------ ------ ------ TOTAL OPERATING EXPENSES 1,789,942 1,402,566 3,675,917 2,345,998 --------- --------- --------- --------- OPERATING INCOME 59,362 58,208 147,514 136,454 NONOPERATING INCOME 7,772 3,427 12,823 4,208 ----- ----- ------ ----- INCOME BEFORE INTEREST CHARGES 67,134 61,635 160,337 140,662 INTEREST CHARGES 30,715 31,395 62,131 62,758 ------ ------ ------ ------ INCOME BEFORE EXTRAORDINARY ITEM 36,419 30,240 98,206 77,904 EXTRAORDINARY GAIN - DISCONTINUANCE OF SFAS 71 (INCLUSIVE OF TAX BENEFIT OF $7,872,000) - 8,938 - 8,938 ------ ----- ------ ----- NET INCOME 36,419 39,178 98,206 86,842 PREFERRED STOCK DIVIDEND REQUIREMENTS 503 632 1,006 1,265 --- --- ----- ----- EARNINGS APPLICABLE TO COMMON STOCK $ 35,916 $ 38,546 $ 97,200 $ 85,577 =========== =========== =========== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) NET INCOME $36,419 $39,178 $98,206 $86,842 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (212) - (629) - ---- ------ ---- ------ COMPREHENSIVE INCOME $36,207 $39,178 $97,577 $86,842 ======= ======= ======= ======= The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $149,469 $191,232 $120,584 $175,854 NET INCOME 36,419 39,178 98,206 86,842 DEDUCTIONS: Cash Dividends Declared: Common Stock 32,398 31,653 64,797 63,306 Cumulative Preferred Stock 360 525 721 1,050 Capital Stock Expense 143 106 285 214 --- --- --- --- BALANCE AT END OF PERIOD $152,987 $198,126 $152,987 $198,126 ======== ======== ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,073,004 $2,058,952 Transmission 1,208,519 1,177,079 Distribution 1,850,084 1,816,925 General 261,307 254,371 Construction Work in Progress 101,589 110,951 ------- ------- Total Electric Utility Plant 5,494,503 5,418,278 Accumulated Depreciation and Amortization 2,241,639 2,188,796 --------- --------- NET ELECTRIC UTILITY PLANT 3,252,864 3,229,482 --------- --------- OTHER PROPERTY AND INVESTMENTS 57,550 56,967 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 611,424 322,688 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 5,176 5,847 Advances to Affiliates - 8,387 Accounts Receivable: Customers 185,010 243,298 Affiliated Companies 48,832 63,919 Miscellaneous 19,058 16,179 Allowance for Uncollectible Accounts (1,868) (2,588) Fuel - at average cost 41,505 39,076 Materials and Supplies - at average cost 59,945 57,515 Accrued Utility Revenues 18,492 66,499 Energy Trading Contracts 1,772,239 2,036,001 Prepayments 10,029 6,307 ------ ----- TOTAL CURRENT ASSETS 2,158,418 2,540,440 --------- --------- REGULATORY ASSETS 443,511 447,750 ------- ------- DEFERRED CHARGES 35,074 48,826 ------ ------ TOTAL ASSETS $6,558,841 $6,646,153 ========== ========== See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (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 715,502 715,218 Accumulated Other Comprehensive Income (Loss) - (629) Retained Earnings 152,987 120,584 ------- ------- Total Common Shareowner's Equity 1,128,318 1,096,260 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 17,790 17,790 Subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,431,344 1,430,812 --------- --------- TOTAL CAPITALIZATION 2,588,312 2,555,722 --------- --------- OTHER NONCURRENT LIABILITIES 92,322 105,883 ------ ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 6 175,006 Short-term Debt - 191,495 Advances from Affiliates 301,890 - Accounts Payable - General 167,195 153,422 Accounts Payable - Affiliated Companies 90,036 107,556 Taxes Accrued 73,696 63,258 Customer Deposits 14,960 12,612 Interest Accrued 27,479 21,555 Energy Trading Contracts 1,729,722 2,091,804 Other 67,177 85,378 ------ ------ TOTAL CURRENT LIABILITIES 2,472,161 2,902,086 --------- --------- DEFERRED INCOME TAXES 721,412 682,474 ------- ------- DEFERRED INVESTMENT TAX CREDITS 40,881 43,093 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 550,037 259,438 ------- ------- REGULATORY LIABILITIES AND DEFERRED CREDITS 93,716 97,457 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $6,558,841 $6,646,153 ========== ========== See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 98,206 $ 86,842 Adjustments for Noncash Items: Depreciation and Amortization 87,829 77,293 Deferred Federal Income Taxes 29,279 15,054 Deferred Investment Tax Credits (2,212) (2,332) Deferred Power Supply Costs (net) 594 (11,938) Extraordinary Gain - Discontinuance of SFAS 71 - (8,938) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 69,776 (36,988) Fuel, Materials and Supplies (4,859) 8,588 Accrued Utility Revenues 48,007 13,029 Accounts Payable (3,747) 27,567 Taxes Accrued 10,438 (764) Interest Accrued 5,924 (903) Net Change in Energy Trading Contracts (96,457) (19,438) Other (net) (15,019) (17,509) ------- ------- Net Cash Flows From Operating Activities 227,759 129,563 ------- ------- INVESTING ACTIVITIES: Construction Expenditures (107,876) (80,870) Proceeds from Sale of Property 1,182 148 ----- --- Net Cash Flows Used For Investing Activities (106,694) (80,722) -------- ------- FINANCING ACTIVITIES: Issuance of Long-term Debt - 74,787 Change in Short-term Debt (net) (191,495) 22,195 Change in Advance from Affiliates (net) 310,277 (12,857) Retirement of Cumulative Preferred Stock - (210) Retirement of Long-term Debt (175,000) (131,202) Dividends Paid on Common Stock (64,797) (63,306) Dividends Paid on Cumulative Preferred Stock (721) (1,053) ---- ------ Net Cash Flows Used For Financing Activities (121,736) (111,646) -------- -------- Net Decrease in Cash and Cash Equivalents (671) (62,805) Cash and Cash Equivalents at Beginning of Period 5,847 64,828 ----- ------ Cash and Cash Equivalents at End of Period $ 5,176 $ 2,023 ============= ===========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $54,957,000 and $61,828,000 and for income taxes was $17,064,000 and $21,198,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,684,000 and $7,451,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Second quarter net income decreased $15 million or 22% while the year-to-date net income increased $12 million or 16%. The lower second quarter net income was the result of increased transmission expenses. Year-to-date net income increased primarily from participation in the power marketing and trading operations. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $211 48 $498 66 Fuel Expense 6 5 69 30 Purchased Power Expense 186 532 380 686 Other Operation 22 40 22 17 Maintenance 3 16 3 11 Depreciation and Amortization 13 31 1 1 Taxes Other Than Federal Income Taxes 2 9 4 10 Federal Income Taxes (7) (20) 7 18 Nonoperating Income (3) (185) (2) (96) The significant increase in operating revenues resulted from participation in AEP's power marketing and trading operations, which added new wholesale revenues, and higher fuel related revenues due to increased fuel and purchased power expense. CPL began sharing in AEP's marketing and trading transactions as a result of the merger of AEP and CSW in June 2000. Fuel expense increased due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. The substantial rise in purchased power expense is attributable to post merger participation in the marketing and trading operation. Other operation expense increased due primarily to a favorable adjustment recorded in the second quarter of 2000 for the energy delivery business' transmission expenses that resulted from new transmission prices for Electric Reliability Council of Texas (ERCOT) transmission grid usage. Each year ERCOT establishes new rates to allocate the costs of the Texas transmission system to Texas electric utilities. Additionally, generation expenses were up due to power trading incentive compensation. Maintenance expense for the quarter increased primarily due to two non-nuclear plant outages. Year-to-date maintenance expense increased primarily due to the wholesale business' STP nuclear plant refueling outage between March 7 and April 2, 2001. The increase in depreciation and amortization expense for the quarter is due primarily to higher depreciation expense associated with excess earning provisions of the Texas deregulation legislation. Taxes other than federal income taxes increased due primarily to an increase in Texas Gross Receipts Tax and Ad Valorem taxes. Federal income taxes attributable to operations for the quarter decreased due to a decrease in pre-tax operating income. However, federal income taxes attributable to operations for the year-to-date period increased due to an increase in pre-tax operating income. Nonoperating income decreased due to a reduction in allocated tax savings resulting from the parent company loss tax benefit.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $648,499 $437,911 $1,251,911 $754,239 -------- -------- ---------- -------- OPERATING EXPENSES: Fuel 147,179 140,841 299,032 230,238 Purchased Power 220,772 34,936 435,338 55,356 Other Operation 76,189 54,307 151,260 129,609 Maintenance 17,995 15,474 35,282 31,896 Depreciation and Amortization 53,587 40,887 95,978 95,085 Taxes Other Than Federal Income Taxes 21,711 19,922 41,199 37,456 Federal Income Taxes 28,715 35,827 47,319 40,232 ------ ------ ------ ------ TOTAL OPERATING EXPENSES 566,148 342,194 1,105,408 619,872 ------- ------- --------- ------- OPERATING INCOME 82,351 95,717 146,503 134,367 NONOPERATING INCOME (LOSS) (1,541) 1,815 98 2,362 ------ ----- -- ----- INCOME BEFORE INTEREST CHARGES 80,810 97,532 146,601 136,729 INTEREST CHARGES 28,292 29,979 59,052 61,037 ------ ------ ------ ------ NET INCOME 52,518 67,553 87,549 75,692 PREFERRED STOCK DIVIDEND REQUIREMENTS 61 61 121 121 -- -- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 52,457 $67,492 $ 87,428 $75,571 ========== ======= ======== =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $790,176 $727,973 $792,219 $758,894 NET INCOME 52,518 67,553 87,549 75,692 DEDUCTIONS: Cash Dividends Declared: Common Stock 37,014 39,000 74,028 78,000 Preferred Stock 61 61 121 121 -- -- --- --- BALANCE AT END OF PERIOD $805,619 $756,465 $805,619 $756,465 ======== ======== ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $3,163,111 $3,175,867 Transmission 604,057 581,931 Distribution 1,250,224 1,221,750 General 240,386 237,764 Construction Work in Progress 195,948 138,273 Nuclear Fuel 240,151 236,859 ------- ------- Total Electric Utility Plant 5,693,877 5,592,444 Accumulated Depreciation and Amortization 2,361,780 2,297,189 --------- --------- NET ELECTRIC UTILITY PLANT 3,332,097 3,295,255 --------- --------- OTHER PROPERTY AND INVESTMENTS 46,229 44,225 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 32,199 66,231 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 5,755 14,253 Accounts Receivable: Customers 38,616 67,787 Affiliated Companies 12,818 31,272 Allowance for Uncollectible Accounts (1,638) (1,675) Fuel Inventory - at LIFO cost 39,511 22,842 Materials and Supplies - at average cost 54,127 53,108 Under-recovered Fuel Costs 93,341 127,295 Energy Trading Contracts 112,483 481,206 Prepayments and Other Current Assets 6,151 3,014 ----- ----- TOTAL CURRENT ASSETS 361,164 799,102 ------- ------- REGULATORY ASSETS 178,299 202,440 ------- ------- REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249 ------- ------- NUCLEAR DECOMMISSIONING TRUST FUND 95,032 93,592 ------ ------ DEFERRED CHARGES 45,115 18,402 ------ ------ TOTAL ASSETS $5,043,384 $5,472,496 ========== ========== See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 12,000,000 Shares Outstanding - 6,755,535 Shares $ 168,888 $168,888 Paid-in Capital 405,000 405,000 Retained Earnings 805,619 792,219 ------- ------- Total Common Shareowner's Equity 1,379,507 1,366,107 Preferred Stock 5,967 5,967 CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of CPL 136,750 148,500 Long-term Debt 942,863 1,254,559 ------- --------- TOTAL CAPITALIZATION 2,465,087 2,775,133 --------- --------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 511,700 200,000 Advances from Affiliates 223,512 269,712 Accounts Payable - General 115,732 128,957 Accounts Payable - Affiliated Companies 26,657 40,962 Taxes Accrued 128,983 55,526 Interest Accrued 24,221 26,217 Energy Trading Contracts 111,536 489,888 Other 46,778 40,630 ------ ------ TOTAL CURRENT LIABILITIES 1,189,119 1,251,892 --------- --------- DEFERRED INCOME TAXES 1,221,213 1,242,797 --------- --------- DEFERRED INVESTMENT TAX CREDITS 125,496 128,100 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 32,999 65,740 ------- ------ DEFERRED CREDITS 9,470 8,834 ----- ----- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,043,384 $5,472,496 ========== ========== See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $87,549 $75,692 Adjustments for Noncash Items: Depreciation and Amortization 95,978 95,085 Deferred Federal Income Taxes (17,699) (4,178) Deferred Investment Tax Credits (2,604) (2,603) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 47,588 8,385 Fuel, Materials and Supplies (17,688) 4,575 Fuel Recovery 33,954 (25,227) Accounts Payable (27,530) 24,785 Taxes Accrued 73,457 (17,148) Transmission Coordination Agreement Settlement - 15,519 Deferred Property Taxes (21,563) - Other (net) (17,628) 10,002 ------- ------ Net Cash Flows From Operating Activities 233,814 184,887 ------- ------- INVESTING ACTIVITIES: Construction Expenditures (109,638) (85,215) Other (354) (4,067) ---- ------ Net Cash Flows Used For Investing Activities (109,992) (89,282) -------- ------- FINANCING ACTIVITIES: Issuance of Long-term Debt 149,413 - Retirement of Long-term Debt (11,971) (100,000) Reacquisition of Long-term Debt - (50,000) Change in Advances from Affiliates (net) (46,200) (68,379) Special Deposit for Reacquisitions of Long-term Debt 50,000 - Dividends Paid on Common Stock (74,028) (78,000) Dividends Paid on Cumulative Preferred Stock (121) (127) ---- ---- Net Cash Flows Used For Financing Activities (132,320) (97,093) -------- ------- Net Decrease in Cash and Cash Equivalents (8,498) (1,488) Cash and Cash Equivalents at Beginning of Period 14,253 7,995 ------ ----- Cash and Cash Equivalents at End of Period $ 5,755 $ 6,507 ======== =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $46,083,000 and $46,981,000 and for income taxes was $11,307,000 and $48,141,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income decreased $14 million or 41% in the second quarter of 2001 and $4 million or 7% in the year-to-date period due to an extraordinary loss recorded in the second quarter to recognize a stranded asset resulting from deregulation. Income before extraordinary item increased by $12 million or 34% in the second quarter of 2001 and $22 million or 35% in the year-to-date period versus last year. Income increased due to growth in and strong performance by the wholesale business. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $181 19 $673 43 Fuel Expense (6) (13) - - Purchased Power Expense 160 23 618 56 Other Operation Expense 4 8 13 14 Maintenance Expense 2 8 6 17 Depreciation and Amortization 6 26 13 27 Extraordinary Item 26 N.M. 26 N.M. N.M. = Not Meaningful The significant increase in revenues is due to increases in electric wholesale prices and volume of our wholesale business. Expansion of the wholesale business' trading operation and greater liquidity in the market place resulted in an increase in the number of forward electricity purchase and sales contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Wholesale trading volume increased 24% for the year-to-date period. The increase in wholesale prices is due to changes in market conditions during a period of high volatility in prices. Fuel expense of the wholesale business decreased in the second quarter of 2001 due to a decrease in net generation partially offset by an increase in price and the discontinuance of deferred fuel accounting because of deregulation effective January 1, 2001. The increase in purchased power expense was attributable to increases in the wholesale business electric trading prices and volume. Other operation expense increased due to increases in uncollectible accounts, factored customer accounts receivable expenses, the effect of gains in 2000 from the disposition of emission allowances and higher power trading expenses and trading incentive compensation. Maintenance expenses increased due to planned outages at several of the wholesale business' plants for boiler overhauls and inspections. The commencement of the amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of electricity under the deregulation of our retail supply business accounted for the increase in depreciation and amortization expense. The extraordinary loss was recorded in June 2001 to recognize stranded prepaid Ohio excise taxes (See Note 2).
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $1,109,095 $928,332 $2,234,668 $1,561,637 ---------- -------- ---------- ---------- OPERATING EXPENSES: Fuel 42,368 48,581 89,398 89,329 Purchased Power 845,860 685,411 1,717,771 1,100,113 Other Operation 54,510 50,332 109,058 95,621 Maintenance 19,729 18,228 38,509 32,924 Depreciation and Amortization 31,379 24,896 62,861 49,440 Taxes Other Than Federal Income Taxes 32,909 31,084 64,816 62,561 Federal Income Taxes 19,446 19,002 37,429 36,727 ------ ------ ------ ------ TOTAL OPERATING EXPENSES 1,046,201 877,534 2,119,842 1,466,715 --------- ------- --------- --------- OPERATING INCOME 62,894 50,798 114,826 94,922 NONOPERATING INCOME (LOSS) 3,012 2,497 6,484 4,181 ----- ----- ----- ----- INCOME BEFORE INTEREST CHARGES 65,906 53,295 121,310 99,103 INTEREST CHARGES 18,488 17,960 36,221 36,297 ------ ------ ------ ------ INCOME BEFORE EXTRAORDINARY ITEM 47,418 35,335 85,089 62,806 EXTRAORDINARY LOSS - EFFECTS OF DEREGULATION (INCLUSIVE OF TAX BENEFIT OF $8,353,000) (26,407) - (26,407) - ------- ----- ------- - NET INCOME 21,011 35,335 58,682 62,806 PREFERRED STOCK DIVIDEND REQUIREMENTS 301 532 603 1,065 --- --- --- ----- EARNINGS APPLICABLE TO COMMON STOCK $ 20,710 $ 34,803 $ 58,079 $ 61,741 ============ ======== ============ ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $115,486 $249,872 $ 99,069 $246,584 NET INCOME 21,011 35,335 58,682 62,806 DEDUCTIONS: Cash Dividends Declared: Common Stock 20,738 23,650 41,476 47,300 Cumulative Preferred Stock 263 438 525 875 Capital Stock Expense 253 95 507 191 --- -- --- --- BALANCE AT END OF PERIOD $115,243 $261,024 $115,243 $261,024 ======== ======== ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,569,118 $1,564,254 Transmission 392,383 360,302 Distribution 1,124,668 1,096,365 General 148,224 156,534 Construction Work in Progress 79,612 89,339 ------ ------ Total Electric Utility Plant 3,314,005 3,266,794 Accumulated Depreciation and Amortization 1,337,358 1,299,697 --------- --------- NET ELECTRIC UTILITY PLANT 1,976,647 1,967,097 --------- --------- OTHER PROPERTY AND INVESTMENTS 43,283 39,848 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 333,816 172,167 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 10,030 11,600 Accounts Receivable: Customers 78,089 73,711 Affiliated Companies 82,426 49,591 Miscellaneous 19,463 18,807 Allowance for Uncollectible Accounts (659) (659) Fuel - at average cost 20,648 13,126 Materials and Supplies - at average cost 37,333 38,097 Accrued Utility Revenues - 9,638 Energy Trading Contracts 966,617 1,085,989 Prepayments and Other Current Assets 27,334 46,735 ------ ------ TOTAL CURRENT ASSETS 1,241,281 1,346,635 --------- --------- REGULATORY ASSETS 273,528 291,553 ------- ------- DEFERRED CHARGES 36,923 77,634 ------ ------ TOTAL ASSETS $3,905,478 $3,894,934 ========== ========== See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (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 573,861 573,354 Retained Earnings 115,243 99,069 ------- ------ Total Common Shareowner's Equity 730,130 713,449 Cumulative Preferred Stock - Subject to Mandatory Redemption 15,000 15,000 Long-term Debt 899,874 899,615 ------- ------- TOTAL CAPITALIZATION 1,645,004 1,628,064 --------- --------- OTHER NONCURRENT LIABILITIES 40,662 47,584 ------ ------ CURRENT LIABILITIES: Advances from Affiliates 115,302 88,732 Accounts Payable - General 92,461 89,846 Accounts Payable - Affiliated Companies 98,033 72,493 Taxes Accrued 117,277 162,904 Interest Accrued 15,808 13,369 Energy Trading Contracts 944,778 1,115,967 Other 49,943 60,701 ------ ------ TOTAL CURRENT LIABILITIES 1,433,602 1,604,012 --------- --------- DEFERRED INCOME TAXES 431,000 422,759 ------- ------- DEFERRED INVESTMENT TAX CREDITS 39,563 41,234 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 15,108 12,861 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 300,539 138,420 ------- ------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $3,905,478 $3,894,934 ========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 58,682 $62,806 Adjustments for Noncash Items: Depreciation and Amortization 52,392 49,709 Amortization of Regulatory Assets 11,294 - Deferred Federal Income Taxes 18,384 6,783 Deferred Investment Tax Credits (1,671) (1,694) Deferred Fuel Cost (net) - (1,835) Amortization of Deferred Property Taxes 35,416 33,721 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (37,869) 83,720 Fuel, Materials and Supplies (6,758) 1,447 Accrued Utility Revenues 9,638 46,416 Prepayments and Other Current Assets 19,401 (11,899) Accounts Payable 28,155 12,174 Taxes Accrued (45,627) (53,895) Energy Trading Contracts (net) (51,347) (5,321) Other (net) (9,981) 3,047 ------ ----- Net Cash Flows From Operating Activities 80,109 225,179 ------ ------- INVESTING ACTIVITIES: Construction Expenditures (67,532) (59,372) Proceeds from Sale of Property 1,284 463 ----- --- Net Cash Flows Used For Investing Activities (66,248) (58,909) ------- ------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) 26,570 (61,504) Change in Short-term Debt (net) - (45,500) Retirement of Long-term Debt - (6,879) Dividends Paid on Common Stock (41,476) (47,300) Dividends Paid on Cumulative Preferred Stock (525) (875) ---- ---- Net Cash Flows Used For Financing Activities (15,431) (162,058) ------- -------- Net Increase (Decrease) in Cash and Cash Equivalents (1,570) 4,212 Cash and Cash Equivalents at Beginning of Period 11,600 5,107 ------ ----- Cash and Cash Equivalents at End of Period $ 10,030 $ 9,319 ========== =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $32,812,000 and $34,547,000 and for income taxes was $17,579,000 and $35,539,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $734,000 and $3,233,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income increased $67 million in the quarter and $135 million in the year-to-date period primarily due to the return to service of both of I&M's Cook Plant nuclear units in 2000. Unit 2 and Unit 1 returned to service in June and December 2000, respectively. Income statement line items which changed significantly were: Increase (Decrease) ------------------- econd Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $248 25 $832 48 Fuel Expense 17 38 33 36 Purchased Power Expense 191 26 713 60 Other Operation Expense (41) (27) (77) (27) Maintenance Expense (24) (44) (52) (46) Federal Income Taxes 34 N.M. 69 N.M. N.M. = Not Meaningful The significant increase in operating revenues resulted from increased wholesale prices and volumes. I&M's share of the AEP System's sales to and forward trades with other utility systems and power marketers and sales to the AEP Power Pool rose in 2001. In 2001 both price and volume in the trading operation increased. The number of forward electricity contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) grew due to the expansion of our trading operation and increased liquidity in the markets. Wholesale prices increased reflecting market conditions during a period of high volatility in prices. With the return to service of the nuclear units in 2000, I&M's available generation increased resulting in additional power being delivered to the AEP Power Pool in 2001. Fuel expense increased primarily due to increased generation reflecting the return to service of the nuclear units following the extended outage. The increase in purchased power expense resulted mainly from increases in wholesale prices and sales and trading volume. Other operation and maintenance expenses decreased primarily due to the cessation of expenses related to work to restart the Cook Plant units. The significant increase in federal income tax expense attributable to operations was primarily due to major increases in pre-tax operating income.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $1,259,874 $1,011,706 $2,551,412 $1,719,856 ---------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 60,491 43,844 124,464 91,704 Purchased Power 936,454 745,656 1,908,041 1,194,926 Other Operation 110,197 151,328 207,560 284,879 Maintenance 31,506 55,841 59,681 111,225 Depreciation and Amortization 40,840 38,499 81,563 76,710 Taxes Other Than Federal Income Taxes 20,316 16,787 40,648 33,996 Federal Income Tax Expense (Credit) 12,730 (21,650) 29,417 (39,734) ------ ------- ------ ------- TOTAL OPERATING EXPENSES 1,212,534 1,030,305 2,451,374 1,753,706 --------- --------- --------- --------- OPERATING INCOME (LOSS) 47,340 (18,599) 100,038 (33,850) NONOPERATING INCOME 4,411 2,637 8,856 3,202 ----- ----- ----- ----- INCOME (LOSS) BEFORE INTEREST CHARGES 51,751 (15,962) 108,894 (30,648) INTEREST CHARGES 24,377 23,219 49,157 45,086 ------ ------ ------ ------ NET INCOME (LOSS) 27,374 (39,181) 59,737 (75,734) PREFERRED STOCK DIVIDEND REQUIREMENTS 1,156 1,153 2,311 2,313 ----- ----- ----- ----- EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 26,218 $ (40,334) $ 57,426 $ (78,047) ============ ============ ============ =========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) NET INCOME (LOSS) $27,374 $(39,181) $59,737 $(75,734) OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge (903) - (2,822) - ---- ------ ------ ------ COMPREHENSIVE INCOME (LOSS) $26,471 $(39,181) $56,915 $(75,734) ======= ======== ======= ========
The common stock of I&M is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $34,651 $102,364 $ 3,443 $166,389 NET INCOME (LOSS) 27,374 (39,181) 59,737 (75,734) DEDUCTIONS: Cash Dividends Declared: Common Stock - - - 26,290 Cumulative Preferred Stock 1,122 2,243 2,244 3,368 Capital Stock Expense 34 10 67 67 -- -- -- -- BALANCE AT END OF PERIOD $60,869 $ 60,930 $60,869 $ 60,930 ======= ======== ======= ======== See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,738,228 $2,708,436 Transmission 950,648 945,709 Distribution 878,487 863,736 General (including nuclear fuel) 231,786 257,152 Construction Work in Progress 98,130 96,440 ------ ------ Total Electric Utility Plant 4,897,279 4,871,473 Accumulated Depreciation and Amortization 2,379,292 2,280,521 --------- --------- NET ELECTRIC UTILITY PLANT 2,517,987 2,590,952 --------- --------- NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 801,760 778,720 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 380,005 194,947 ------- ------- OTHER PROPERTY AND INVESTMENTS 133,032 131,417 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 12,069 14,835 Accounts Receivable: Customers 89,393 106,832 Affiliated Companies 47,644 48,706 Miscellaneous 35,595 27,491 Allowance for Uncollectible Accounts (734) (759) Fuel - at average cost 26,906 16,532 Materials and Supplies - at average cost 87,955 84,471 Energy Trading Contracts 1,130,779 1,230,041 Prepayments 3,888 6,066 ----- ----- TOTAL CURRENT ASSETS 1,433,495 1,534,215 --------- --------- REGULATORY ASSETS 500,879 552,140 ------- ------- DEFERRED CHARGES 30,071 36,156 ------ ------ TOTAL ASSETS $5,797,229 $5,818,547 ========== ========== See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (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 733,139 733,072 Accumulated Other Comprehensive Income (Loss) (2,822) - Retained Earnings 60,869 3,443 ------ ----- Total Common Shareowner's Equity 847,770 793,099 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 8,736 8,736 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,349,874 1,298,939 --------- --------- TOTAL CAPITALIZATION 2,271,325 2,165,719 --------- --------- OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 576,267 560,628 Other 101,000 108,600 ------- ------- TOTAL OTHER NONCURRENT LIABILITIES 677,267 669,228 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - 90,000 Advances from Affiliates 302,030 253,582 Accounts Payable: General 99,800 119,472 Affiliated Companies 53,775 75,486 Taxes Accrued 99,671 68,416 Interest Accrued 22,919 21,639 Obligations Under Capital Leases 9,141 100,848 Energy Trading Contracts 1,092,357 1,275,097 Other 77,955 97,070 ------ ------ TOTAL CURRENT LIABILITIES 1,757,648 2,101,610 --------- --------- DEFERRED INCOME TAXES 472,626 487,945 ------- ------- DEFERRED INVESTMENT TAX CREDITS 110,037 113,773 ------- ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 79,445 81,299 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 345,216 156,736 ------- ------- DEFERRED CREDITS 83,665 42,237 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,797,229 $5,818,547 ========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $59,737 $ (75,734) Adjustments for Noncash Items: Depreciation and Amortization 83,090 81,423 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) (771) 3,722 Unrecovered Fuel and Purchased Power Costs 18,751 18,751 Amortization of Nuclear Outage Costs 20,000 20,000 Deferred Federal Income Taxes (4,256) (12,038) Deferred Investment Tax Credits (3,736) (3,773) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 10,372 61,510 Fuel, Materials and Supplies (13,858) (1,464) Accrued Utility Revenues - 44,428 Accounts Payable (41,383) (14,093) Taxes Accrued 31,255 (28,268) Net Change in Energy Trading Contracts (80,056) (8,935) Regulatory Liability - Trading Gains 38,159 3,284 Other (net) 12,261 (23,988) ------ ------- Net Cash Flows From Operating Activities 129,565 64,825 ------- ------ INVESTING ACTIVITIES: Construction Expenditures (41,321) (93,002) Buyout of Nuclear Fuel Leases (92,616) - Other 324 587 --- --- Net Cash Flows Used For Investing Activities (133,613) (92,415) -------- ------- FINANCING ACTIVITIES: Retirement of Long-term Debt (44,922) (48,000) Retirement of Cumulative Preferred Stock (314) - Change in Short-term Debt (net) (224,262) - Change in Advances from Affiliates (net) 48,448 331,852 Dividends Paid on Common Stock (26,290) - Dividends Paid on Cumulative Preferred Stock (2,244) (2,249) ------ ------ Net Cash Flows From Financing Activities 1,282 30,737 ----- ------ Net Increase (Decrease) in Cash and Cash Equivalents (2,766) 3,147 Cash and Cash Equivalents at Beginning of Period 14,835 3,863 ------ ----- Cash and Cash Equivalents at End of Period $ 12,069 $ 7,010 ======== ======= Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $46,243,000 and $39,686,000 and for income taxes was $11,073,000 and $(2,365,000) in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $1,020,000 and $15,423,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution service. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Although revenues rose significantly, net income increased slightly in the quarter and declined by less than $1.0 million or 7% for the year-to-date period. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $96 28 $324 56 Purchased Power Expense 98 35 324 72 Other Operation Expense 2 20 7 29 Maintenance Expense (3) (39) (4) (28) Federal Income Taxes - N.M. (2) (31) Nonoperating Income 1 85 2 335 Interest Charges (1) (11) (1) (8) N.M. = Not Meaningful The significant increase in operating revenues resulted from increased wholesale prices and volumes. Our wholesale sales to and forward trades with other utility systems and power marketers rose by 15% in the quarter and 37% for the year-to-date period. The number of forward electricity contracts in AEP's traditional marketing area (up to two transmission systems from AEP's service territory) grew due to the expansion of our trading operation and increased liquidity in the markets. Wholesale prices increased reflecting market conditions during a period of high volatility in prices. Purchased power expense for the wholesale business increased due to higher wholesale prices and increased sales and trading volume. Other operation expense increased due to an increase in trading incentive compensation for the wholesale business, a decline in AEP transmission equalization credits for the energy delivery business and the cost of accounts receivable factoring for both businesses. Under the AEP East Region Transmission Agreement, KPCo and certain affiliates share the costs associated with the ownership of their transmission system based upon each company's peak demand and investment. An increase in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the decline in transmission equalization credits. The effect of the costs of outages at our wholesale business' Big Sandy Plant in 2000 caused maintenance expense to decrease. Federal income taxes attributable to operations decreased due to a decline in pre-tax income. The increase in nonoperating income was due to an increase in net gains from non-regulated trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures, swaps) for the wholesale business. Interest charges declined due to lower outstanding debt balances and lower interest rates in 2001.
KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: $439,131 $342,660 $898,288 $574,114 -------- -------- -------- -------- OPERATING EXPENSES: Fuel 17,418 17,871 35,374 34,673 Purchased Power 381,913 283,653 775,778 451,385 Other Operation 14,470 12,103 29,198 22,487 Maintenance 5,185 8,438 10,614 14,805 Depreciation and Amortization 8,080 7,676 16,107 15,279 Taxes Other Than Federal Income Taxes 3,102 2,659 6,836 5,493 Federal Income Taxes 599 804 3,413 4,979 --- --- ----- ----- TOTAL OPERATING EXPENSES 430,767 333,204 877,320 549,101 ------- ------- ------- ------- OPERATING INCOME 8,364 9,456 20,968 25,013 NONOPERATING INCOME 1,243 671 2,718 625 ----- --- ----- --- OME BEFORE INTEREST CHARGES 9,607 10,127 23,686 25,638 INTEREST CHARGES 6,865 7,678 13,869 15,137 ----- ----- ------ ------ NET INCOME $ 2,742 $ 2,449 $ 9,817 $10,501 ========== ======= ======= =======
STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) NET INCOME $2,742 $2,449 $ 9,817 $10,501 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge (68) - (1,422) - --- ------- ------ -- COMPREHENSIVE INCOME $2,674 $2,449 $ 8,395 $10,501 ====== ====== ======= ======= The common stock of KPCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $57,027 $67,572 $57,513 $67,110 NET INCOME 2,742 2,449 9,817 10,501 CASH DIVIDENDS DECLARED: Common Stock 7,561 7,590 15,122 15,180 ----- ----- ------ ------ BALANCE AT END OF PERIOD $52,208 $62,431 $52,208 $62,431 ======= ======= ======= ======= See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 270,699 $ 271,107 Transmission 368,978 360,563 Distribution 395,660 387,499 General 66,695 67,476 Construction Work in Progress 11,018 16,419 ------ ------ Total Electric Utility Plant 1,113,050 1,103,064 Accumulated Depreciation and Amortization 372,856 360,648 ------- ------- NET ELECTRIC UTILITY PLANT 740,194 742,416 ------- ------- OTHER PROPERTY AND INVESTMENTS 6,139 6,559 ----- ----- LONG-TERM ENERGY TRADING CONTRACTS 150,630 76,657 ------- ------ CURRENT ASSETS: Cash and Cash Equivalents 2,513 2,270 Accounts Receivable: Customers 29,029 34,555 Affiliated Companies 20,891 22,119 Miscellaneous 9,157 6,419 Allowance for Uncollectible Accounts (278) (282) Fuel - at average cost 4,690 4,760 Materials and Supplies - at average cost 16,150 15,408 Accrued Utility Revenues - 6,500 Energy Trading Contracts 434,802 483,537 Prepayments 951 766 --- --- TOTAL CURRENT ASSETS 517,905 576,052 ------- ------- REGULATORY ASSETS 98,800 98,515 ------ ------ DEFERRED CHARGES 7,334 11,817 ----- ------ TOTAL ASSETS $1,521,002 $1,512,016 ========== ========== See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $50 Par Value: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares $ 50,450 $50,450 Paid-in Capital 158,750 158,750 Accumulated Other Comprehensive Income (Loss) (1,422) - Retained Earnings 52,208 57,513 ------ ------ Total Common Shareowner's Equity 259,986 266,713 Long-term Debt 270,996 270,880 Long-term Debt - Affiliated Company 75,000 - ------ - TOTAL CAPITALIZATION 605,982 537,593 ------- ------- OTHER NONCURRENT LIABILITIES 15,347 18,348 ------ ------ CURRENT LIABILITIES: Long-term Debt Due Within One Year - 60,000 Advances from Affiliates 47,231 47,636 Accounts Payable: General 37,529 32,043 Affiliated Companies 35,265 37,506 Customer Deposits 4,676 4,389 Taxes Accrued 5,279 11,885 Interest Accrued 5,740 5,610 Energy Trading Contracts 428,052 496,884 Other 10,269 14,517 ------ ------ TOTAL CURRENT LIABILITIES 574,041 710,470 ------- ------- DEFERRED INCOME TAXES 173,197 165,935 ------- ------- DEFERRED INVESTMENT TAX CREDITS 11,063 11,656 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 135,967 61,632 ------- ------ DEFERRED CREDITS 5,405 6,382 ----- ----- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $1,521,002 $1,512,016 ========== ========== See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $9,817 $ 10,501 Adjustments for Noncash Items: Depreciation and Amortization 16,107 15,279 Deferred Federal Income Taxes 7,921 2,563 Deferred Investment Tax Credits (593) (596) Deferred Fuel Costs (net) (1,241) 910 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 4,012 14,948 Fuel, Materials and Supplies (672) 342 Accrued Utility Revenues 6,500 13,737 Accounts Payable 3,245 776 Taxes Accrued (6,606) (4,004) Net Change in Energy Trading Contracts (19,735) (3,955) Other (3,289) (84) ------ --- Net Cash Flows From Operating Activities 15,466 50,417 ------ ------ INVESTING ACTIVITIES: Construction Expenditures (14,912) (14,188) Proceeds from Sales of Property 216 - --- ------ Net Cash Flow Used for Investing Activities (14,696) (14,188) ------- ------- FINANCING ACTIVITIES: Issuance of Long-term Debt - Affiliated Company 75,000 - Retirement of Long-term Debt (60,000) (25,000) Change in Short-term Debt (net) - (39,665) Change in Advances from Affiliates (net) (405) 43,634 Dividends Paid (15,122) (15,180) ------- ------- Net Cash Flows Used For Financing Activities (527) (36,211) ---- ------- Net Increase in Cash and Cash Equivalents 18 243 Cash and Cash Equivalents at Beginning of Period 2,270 674 ----- --- Cash and Cash Equivalents at End of Period $2,513 $ 692 ====== =====
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $13,692,000 and $15,046,000 and for income taxes was $6,010,000 and $5,921,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $760,000 and $1,836,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of the generation, marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. We belong to the AEP Power Pool and share in the revenues and costs of wholesale marketing and trading activities conducted on our behalf by the AEP Power Pool. Net income decreased $48 million or 82% for the second quarter of 2001 and $40 million or 39% for the year-to-date period due to an extraordinary loss recorded in the second quarter to recognize a stranded asset resulting from deregulation. Income before extraordinary item decreased by $26 million or 45% in the second quarter of 2001 and $19 million or 18% in the year-to-date period because of implementation of customer choice. In connection with the start of customer choice on January 1, 2001, the generation portion of residential rates was reduced by 5% and the amortization of transition regulatory assets began. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $191 13 $843 34 Purchased Power Expense 204 22 845 57 Other Operation 10 12 14 8 Maintenance Expense 3 8 10 17 Depreciation and Amortization 19 48 40 52 Taxes Other Than Federal Income taxes 5 13 2 3 Federal Income Taxes (20) (55) (24) (34) Nonoperating Income 7 N.M. 15 N.M. Extraordinary Item 22 N.M. 22 N.M. N.M. = Not Meaningful The significant increase in revenues is due to increases in electric trading wholesale prices and volume of our wholesale business. Expansion of the wholesale business' trading operation and greater liquidity in the marketplace resulted in an increase in the number of forward electricity purchase and sales contracts made in AEP's traditional marketing area (up to two transmission systems from AEP's service territory). Wholesale trading volume increased 19% for the year-to-date period. The increase in wholesale prices reflects market conditions during a period of high volatility in prices. The increase in purchased power expense was attributable to the increase in the wholesale business' electric trading volume and prices. Other operation expense increased due to increases in uncollectible accounts and factored customer accounts receivable expenses of both the wholesale business and energy delivery business, the effect of gains in 2000 from the disposition of emission allowances, and trading incentive compensation of the wholesale business. Maintenance expenses increased due to planned outages at several of the wholesale business' plants for boiler overhauls and inspections. The commencement of amortization of transition regulatory assets in connection with the transition to customer choice and market-based pricing of electricity under Ohio deregulation accounted for the increase in depreciation and amortization expense. Federal income taxes attributable to operations decreased due to a decrease in pre-tax operating income. The increase in nonoperating income was due to an increase in net gains from the wholesale business' trading transactions outside of the AEP System's traditional marketing area and speculative financial transactions (options, futures and swaps). An extraordinary loss was recorded in June 2001 to recognize stranded prepaid Ohio excise taxes (See Note 2).
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $1,627,177 $1,436,330 $3,326,842 $2,484,167 ---------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 180,057 177,314 380,618 392,562 Purchased Power 1,146,655 943,060 2,325,561 1,480,788 Other Operation 96,623 86,244 185,029 170,696 Maintenance 36,448 33,595 71,848 61,625 Depreciation and Amortization 57,666 38,843 117,725 77,332 Taxes Other Than Federal Income Taxes 46,193 41,055 87,054 84,787 Federal Income Taxes 16,468 36,251 47,184 71,296 ------ ------ ------ ------ TOTAL OPERATING EXPENSES 1,580,110 1,356,362 3,215,019 2,339,086 --------- --------- --------- --------- OPERATING INCOME 47,067 79,968 111,823 145,081 NONOPERATING INCOME 7,809 1,250 18,917 4,150 ----- ----- ------ ----- INCOME BEFORE INTEREST CHARGES 54,876 81,218 130,740 149,231 INTEREST CHARGES 22,782 22,985 45,249 44,782 ------ ------ ------ ------ INCOME BEFORE EXTRAORDINARY ITEM 32,094 58,233 85,491 104,449 EXTRAORDINARY LOSS - EFFECTS OF DEREGULATION (INCLUSIVE OF TAX BENEFIT OF $11,585,000) (21,515) - (21,515) - ------- ----- ------- - NET INCOME 10,579 58,233 63,976 104,449 PREFERRED STOCK DIVIDEND REQUIREMENTS 316 315 630 636 --- --- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 10,263 $ 57,918 $ 63,346 $103,813 =========== ======== ============ ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) NET INCOME $10,579 $58,233 $63,976 $104,449 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge (104) - (325) - ---- ------ ---- ------ COMPREHENSIVE INCOME $10,475 $58,233 $63,651 $104,449 ======= ======= ======= ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $415,425 $595,620 $398,086 $587,424 NET INCOME 10,579 58,233 63,976 104,449 CASH DIVIDENDS DECLARED: Common Stock 35,744 37,703 71,488 75,406 Cumulative Preferred Stock 315 316 629 633 --- --- --- --- BALANCE AT END OF PERIOD $389,945 $615,834 $389,945 $615,834 ======== ======== ======== ======== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,955,482 $2,764,155 Transmission 884,720 870,033 Distribution 1,059,174 1,040,940 General (including mining assets) 523,987 707,417 Construction Work in Progress 83,461 195,086 ------ ------- Total Electric Utility Plant 5,506,824 5,577,631 Accumulated Depreciation and Amortization 2,670,874 2,764,130 --------- --------- NET ELECTRIC UTILITY PLANT 2,835,950 2,813,501 --------- --------- OTHER PROPERTY AND INVESTMENTS 114,811 109,124 ------- ------- LONG-TERM ENERGY TRADING CONTRACTS 479,759 256,455 ------- ------- CURRENT ASSETS: Cash and Cash Equivalents 28,943 31,393 Advances to Affiliates - 92,486 Accounts Receivable: Customers 174,891 139,732 Affiliated Companies 141,778 126,203 Miscellaneous 26,188 39,046 Allowance for Uncollectible Accounts (1,026) (1,054) Fuel - at average cost 100,400 82,291 Materials and Supplies - at average cost 75,692 96,053 Energy Trading Contracts 1,389,132 1,617,660 Prepayments and Other 17,766 33,146 ------ ------ TOTAL CURRENT ASSETS 1,953,764 2,256,956 --------- --------- REGULATORY ASSETS 674,099 714,710 ------- ------- DEFERRED CHARGES 59,384 101,690 ------ ------- TOTAL ASSETS $6,117,767 $6,252,436 ========== ========== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 40,000,000 Shares Outstanding - 27,952,473 Shares $ 321,201 $321,201 Paid-in Capital 462,483 462,483 Accumulated Other Comprehensive Income (Loss) (325) - Retained Earnings 389,945 398,086 ------- ------- Total Common Shareholder's Equity 1,173,304 1,181,770 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,648 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 1,078,354 1,077,987 --------- --------- TOTAL CAPITALIZATION 2,277,156 2,285,255 --------- --------- OTHER NONCURRENT LIABILITIES 515,450 542,017 ------- ------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - 117,506 Advances from Affiliates 252,323 - Accounts Payable - General 160,578 179,691 Accounts Payable - Affiliated Companies 77,477 121,360 Customer Deposits 7,368 39,736 Taxes Accrued 184,079 223,101 Interest Accrued 24,299 20,458 Obligations Under Capital Leases 14,057 32,716 Energy Trading Contracts 1,358,005 1,662,315 Other 140,792 151,934 ------- ------- TOTAL CURRENT LIABILITIES 2,218,978 2,548,817 --------- --------- DEFERRED INCOME TAXES 609,885 621,941 ------- ------- DEFERRED INVESTMENT TAX CREDITS 23,644 25,214 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 431,934 206,187 ------- ------- REGULATORY LIABILITIES AND DEFERRED CREDITS 40,720 23,005 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $6,117,767 $6,252,436 ========== ========== See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 63,976 $ 104,449 Adjustments for Noncash Items: Depreciation 93,161 100,439 Amortization of Transition Assets 36,705 - Deferred Federal Income Taxes 116 (6,387) Deferred Fuel Costs (net) - (8,844) Amortization of Deferred Property Taxes 40,596 39,944 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (37,904) (88,341) Fuel, Materials and Supplies 2,252 47,680 Accrued Utility Revenues 264 45,575 Prepayments and Other Current Assets 15,116 (6,219) Accounts Payable (62,996) 129,756 Customer Deposits (32,368) (1,209) Taxes Accrued (39,022) (44,129) Interest Accrued 3,841 1,334 Energy Trading Contract (net) (73,339) (8,546) Other (net) (24,345) 10,864 ------- ------ Net Cash Flows From (Used For) Operating Activities (13,947) 316,366 ------- ------- INVESTING ACTIVITIES: Construction Expenditures (151,314) (91,118) Proceeds from Sale of Property and Other 7,626 - ----- ------ Net Cash Flows Used For Investing Activities (143,688) (91,118) -------- ------- FINANCING ACTIVITIES: Issuance of Long-term Debt - 74,748 Change in Advances to Affiliates (net) 344,809 (148,965) Change in Short-term Debt (net) - (194,918) Retirement of Cumulative Preferred Stock - (160) Retirement of Long-term Debt (117,506) (11,752) Dividends Paid on Common Stock (71,488) (75,406) Dividends Paid on Cumulative Preferred Stock (630) (633) ---- ---- Net Cash Flows From (Used For) Financing Activities 155,185 (357,086) ------- -------- Net Decrease in Cash and Cash Equivalents (2,450) (131,838) Cash and Cash Equivalents at Beginning of Period 31,393 157,138 ------ ------- Cash and Cash Equivalents at End of Period $ 28,943 $ 25,300 =========== ========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $40,580,000 and $40,791,000 and for income taxes was $54,694,000 and $64,597,000 in 2001 and 2000, respectively. Noncash acquisitions under capital leases were $522,000 and $8,422,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Although revenues increased substantially, operating expenses increased by a greater amount causing net income to decrease by $2.8 million or 19% in the second quarter and $5.5 million or 35% in the first half of 2001. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $189 90 $384 104 Fuel Expense 70 92 110 75 Purchased Power Expense 118 373 264 505 Other Operation Expense 6 21 17 32 Federal Income Taxes (3) (40) (5) (61) The significant increase in operating revenues was due to participation in the AEP System's power marketing and trading activities subsequent to June 2000. Revenues for the year-to-date period also increased as a result of the absence of a 2000 adjustment due to a FERC-approved Transmission Coordination Agreement, which decreased revenues and other operation expenses in 2000. The transmission coordination agreement provides the means by which the AEP West electric operating companies plan, operate and maintain their four separate transmission systems as a single unit. The agreement also established the method by which these companies allocate revenues and costs received under open access transmission tariffs. Fuel expense increased due primarily to a rise in the average unit fuel cost reflecting an increase in natural gas prices. The increase in purchased power expense was primarily attributable to participation in the AEP System's power marketing and trading activities. Other operation expenses increased in the second quarter due to increased transmission expenses, public liability insurance premiums, and power trading incentive compensation. Expenses increased for the first half of 2001 due mainly to the absence of a 2000 favorable adjustment due to the FERC-approved Transmission Coordination Agreement mentioned above, along with increased incentive compensation for power trading and transmission expenses. Federal income tax expense associated with utility operations decreased as a result of a decline in pre-tax book income.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $398,194 $209,172 $754,333 $370,501 -------- -------- -------- -------- OPERATING EXPENSES: Fuel 145,927 75,808 257,728 147,394 Purchased Power 149,261 31,541 315,807 52,207 Other Operation 34,332 28,476 68,889 52,232 Maintenance 12,859 13,408 22,689 21,995 Depreciation and Amortization 19,673 18,926 39,144 37,838 Taxes Other Than Federal Income Taxes 9,550 8,819 16,923 16,058 Federal Income Taxes 4,650 7,692 2,871 7,415 ----- ----- ----- ----- TOTAL OPERATING EXPENSES 376,252 184,670 724,051 335,139 ------- ------- ------- ------- OPERATING INCOME 21,942 24,502 30,282 35,362 NONOPERATING INCOME 92 494 695 716 -- --- --- --- INCOME BEFORE INTEREST CHARGES 22,034 24,996 30,977 36,078 INTEREST CHARGES 10,113 10,296 20,616 20,213 ------ ------ ------ ------ NET INCOME 11,921 14,700 10,361 15,865 PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 106 106 -- -- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 11,868 $ 14,647 $10,255 $ 15,759 ======== ======== ======= ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $123,015 $123,348 $137,688 $139,236 NET INCOME 11,921 14,700 10,361 15,865 CASH DIVIDENDS DECLARED: Common Stock 13,060 17,000 26,120 34,000 Preferred Stock 53 53 106 106 -- -- --- --- BALANCE AT END OF PERIOD $121,823 $120,995 $121,823 $120,995 ======== ======== ======== ======== The common stock of PSO is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 914,958 $914,096 Transmission 415,083 396,695 Distribution 960,152 938,053 General 209,171 206,731 Construction Work in Progress 157,452 149,095 ------- ------- Total Electric Utility Plant 2,656,816 2,604,670 Accumulated Depreciation and Amortization 1,167,875 1,150,253 --------- --------- NET ELECTRIC UTILITY PLANT 1,488,941 1,454,417 --------- --------- OTHER PROPERTY AND INVESTMENTS 39,749 38,211 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 26,801 52,629 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 10,906 11,301 Accounts Receivable: Customers 32,105 59,957 Affiliated Companies 13,817 3,453 Fuel - at LIFO costs 20,078 28,113 Materials and Supplies - at average costs 31,583 29,642 Under-recovered Fuel Costs 11,519 43,267 Energy Trading Contracts 93,037 382,380 Prepayments 2,816 1,559 ----- ----- TOTAL CURRENT ASSETS 215,861 559,672 ------- ------- REGULATORY ASSETS 23,106 29,338 ------ ------ DEFERRED CHARGES 22,116 7,889 ------ ----- TOTAL ASSETS $1,816,574 $2,142,156 ========== ========== See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $15 Par Value: Authorized Shares: 11,000,000 Shares Issued Shares: 10,482,000 shares and Outstanding Shares: 9,013,000 Shares $ 157,230 $157,230 Paid-in Capital 180,000 180,000 Retained Earnings 121,823 137,688 ------- ------- Total Common Shareholder's Equity 459,053 474,918 Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,283 5,283 PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 450,975 450,822 ------- ------- TOTAL CAPITALIZATION 990,311 1,006,023 ------- --------- CURRENT LIABILITIES: Long-term Debt Due Within One Year - 20,000 Advances from Affiliates 147,447 81,120 Accounts Payable - General 60,949 104,379 Accounts Payable - Affiliated Companies 55,104 64,556 Customers Deposits 22,497 19,294 Taxes Accrued 29,665 1,659 Interest Accrued 7,389 8,336 Energy Trading Contracts 92,367 389,279 Other 12,615 12,137 ------ ------ TOTAL CURRENT LIABILITIES 428,033 700,760 ------- ------- DEFERRED INCOME TAXES 302,746 312,060 ------- ------- DEFERRED INVESTMENT TAX CREDITS 34,888 35,783 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 32,342 35,292 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 28,254 52,238 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $1,816,574 $2,142,156 ========== ========== See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 10,361 $15,865 Adjustments for Noncash Items: Depreciation and Amortization 39,144 37,838 Deferred Income Taxes (10,754) 18,715 Deferred Investment Tax Credits (895) (896) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 17,488 (2,608) Fuel, Materials and Supplies 6,094 1,932 Accounts Payable (52,882) 48,788 Taxes Accrued 28,006 (22,413) Other Property and Investments (1,178) 2,391 Transmission Coordination Agreement Settlement - (15,063) Deferred Property Taxes (14,951) - Fuel Recovery 31,748 (25,571) Other (net) (5,276) 796 ------ --- Net Cash Flows From Operating Activities 46,905 59,774 ------ ------ INVESTING ACTIVITIES: Construction Expenditures (67,042) (80,997) Other (359) (4,694) ---- ------ Net Cash Flows Used For Investing Activities (67,401) (85,691) ------- ------- FINANCING ACTIVITIES: Retirement of Long-term Debt (20,000) (10,000) Retirement of Cumulative Preferred Stock - (1) Change in Advances from Affiliates (net) 66,327 69,690 Dividends Paid on Common Stock (26,120) (34,000) Dividends Paid on Cumulative Preferred Stock (106) (108) ---- ---- Net Cash Flows From Financing Activities 20,101 25,581 ------ ------ Net Increase in Cash and Cash Equivalents (395) (336) Cash and Cash Equivalents at Beginning of Period 11,301 3,173 ------ ----- Cash and Cash Equivalents at End of Period $10,906 $2,837 ======= ====== Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $19,011,000 and $16,754,000 and for income taxes was $1,978,000 and $11,725,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Net income increased $11.2 million, or 42%, for the first half of 2001 despite a small decrease in the quarter of $1 million, or 5%. The increase for the first half of 2001 resulted from the favorable impact of our power marketing and trading operations. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $162 60 $376 78 Fuel Expense 10 9 39 19 Purchased Power Expense 149 776 307 991 Other Operation Expense (3) (9) 1 2 Depreciation and Amortization 6 21 7 12 Taxes Other Than Federal Income Taxes 2 11 5 21 Federal Income Taxes - - 6 73 The significant increase in operating revenues and purchased power expense for the quarter and first half of 2001 resulted from increased trading volumes of the wholesale business due to the post merger favorable impact of AEP's power marketing and trading operations. SWEPCo began sharing in AEP's marketing and trading transactions as a result of the merger of AEP and CSW in June 2000. Fuel expense for the wholesale business increased due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. Other operation expense decreased for the quarter due to the reversal of a $4 million environmental reserve originally recorded in the fourth quarter of 1999. The reserve was set up for expected remediation work at a site on which a manufactured gas plant previously resided. In June 2001, the site was donated to a city for use as a major civic complex. As part of the donation, the city agreed to hold us harmless from any future liability arising from the site. Other operation expense increased for the year-to-date period as a result of a bad debt write-off, our share of power trading incentive compensation incurred since the June 2000 merger and increased transmission services expense partially offset by the reversal of the $4 million environmental reserve. Depreciation and amortization expenses increased due to an increase in excess earnings accruals under the Texas restructuring legislation. Taxes other than federal income taxes increased during the second quarter due to increased state income taxes reflecting higher state taxable income. The increase for the first six months of 2001 is due to a favorable adjustment of ad valorem taxes recorded in 2000 and increased state income taxes due to increased state taxable income. The increase in federal income tax expense attributable to operations was primarily due to an increase in pre-tax operating income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $434,795 $272,409 $860,484 $484,565 -------- -------- -------- -------- OPERATING EXPENSES: Fuel 124,151 113,773 242,397 203,125 Purchased Power 168,671 19,252 337,528 30,950 Other Operation 34,071 37,362 73,339 72,060 Maintenance 20,431 20,906 35,667 35,212 Depreciation and Amortization 33,328 27,525 61,458 54,882 Taxes Other Than Federal Income Taxes 14,986 13,455 29,252 24,116 Federal Income Taxes 6,508 6,840 14,208 8,193 ----- ----- ------ ----- TOTAL OPERATING EXPENSES 402,146 239,113 793,849 428,538 ------- ------- ------- ------- OPERATING INCOME 32,649 33,296 66,635 56,027 NONOPERATING INCOME 30 678 277 445 -- --- --- --- INCOME BEFORE INTEREST CHARGES 32,679 33,974 66,912 56,472 INTEREST CHARGES 14,895 15,188 29,259 30,023 ------ ------ ------ ------ NET INCOME 17,784 18,786 37,653 26,449 PREFERRED STOCK DIVIDEND REQUIREMENTS 58 57 115 114 -- -- --- --- EARNINGS APPLICABLE TO COMMON STOCK $ 17,726 $ 18,729 $ 37,538 $ 26,335 ========= =========== ========= ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $295,248 $275,652 $293,989 $283,546 NET INCOME 17,784 18,786 37,653 26,449 CASH DIVIDENDS DECLARED: Common Stock 18,552 15,500 37,105 31,000 Preferred Stock 58 57 115 114 -- -- --- --- BALANCE AT END OF PERIOD $294,422 $278,881 $294,422 $278,881 ======== ======== ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,472,831 $1,414,527 Transmission 531,793 519,317 Distribution 1,024,442 1,001,237 General 327,976 325,948 Construction Work in Progress 48,381 57,995 ------ ------ Total Electric Utility Plant 3,405,423 3,319,024 Accumulated Depreciation and Amortization 1,500,099 1,457,005 --------- --------- NET ELECTRIC UTILITY PLANT 1,905,324 1,862,019 --------- --------- OTHER PROPERTY AND INVESTMENTS 41,443 39,627 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 32,212 63,028 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 1,954 1,907 Accounts Receivable: Customers 50,532 41,399 Affiliated Companies - 11,419 Fuel Inventory - at average cost 43,194 40,024 Under-recovered Fuel 44,916 35,469 Materials and Supplies - at average cost 30,004 25,137 Energy Trading Contracts 112,529 457,936 Prepayments 18,562 16,780 ------ ------ TOTAL CURRENT ASSETS 301,691 630,071 ------- ------- REGULATORY ASSETS 52,123 57,082 ------ ------ DEFERRED CHARGES 83,774 10,707 ------ ------ TOTAL ASSETS $2,416,567 $2,662,534 ========== ========== See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $18 Par Value: Authorized - 7,600,000 Shares Outstanding - 7,536,640 Shares $ 135,660 $135,660 Paid-in Capital 245,000 245,000 Retained Earnings 294,422 293,989 ------- ------- Total Common Shareowner's Equity 675,082 674,649 Preferred Stock 4,704 4,704 SWEPCO-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SWEPCO 110,000 110,000 Long-term Debt 494,876 645,368 ------- ------- TOTAL CAPITALIZATION 1,284,662 1,434,721 --------- --------- OTHER NONCURRENT LIABILITIES 32,377 11,290 ------ ------ CURRENT LIABILITIES: Long-term Debt Due Within One Year 150,595 595 Advances from Affiliates 136,483 16,823 Accounts Payable - General 63,892 107,747 Accounts Payable - Affiliated Companies 34,650 36,021 Customer Deposits 20,471 16,433 Taxes Accrued 52,382 11,224 Interest Accrued 13,466 13,198 Energy Trading Contracts 111,582 466,198 Other 20,487 15,064 ------ ------ TOTAL CURRENT LIABILITIES 604,008 683,303 ------- ------- DEFERRED INCOME TAXES 396,364 399,204 ------- ------- DEFERRED INVESTMENT TAX CREDITS 50,955 53,167 ------ ------ REGULATORY LIABILITIES AND DEFERRED CREDITS 15,189 18,288 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 33,012 62,561 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $2,416,567 $2,662,534 ========== ========== See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 37,653 $26,449 Adjustments for Noncash Items: Depreciation and Amortization 61,458 54,882 Deferred Income Taxes (4,546) 9,960 Deferred Investment Tax Credits (2,212) (2,241) Deferred Property Taxes (17,703) - Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 2,286 8,375 Fuel, Materials and Supplies (4,266) (5,890) Accounts Payable (45,226) 29,989 Taxes Accrued 41,158 (8,474) Transmission Coordination Agreement Settlement - (24,406) Fuel Recovery (9,447) (18,218) Other (5,553) 647 ------ --- Net Cash Flows From Operating Activities 53,602 71,073 ------ ------ INVESTING ACTIVITIES: Construction Expenditures (49,418) (61,879) Purchase of Dolet Hills (85,716) - Other (411) (4,338) ---- ------ Net Cash Flows Used For Investing Activities (135,545) (66,217) -------- ------- FINANCING ACTIVITIES: Issuance of Long-term Debt - 149,367 Retirement of Long-term Debt (450) (45,451) Change in Advances from Affiliates (net) 119,660 (77,655) Dividends Paid on Common Stock (37,105) (31,000) Dividends Paid on Cumulative Preferred Stock (115) (119) ---- ---- Net Cash Flows From (Used For) Financing Activities 81,990 (4,858) ------ ------ Net Increase (Decrease) in Cash and Cash Equivalents 47 (2) Cash and Cash Equivalents at Beginning of Period 1,907 3,043 ----- ----- Cash and Cash Equivalents at End of Period $ 1,954 $ 3,041 ========= =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $25,743,000 and $20,711,000 and for income taxes was $4,144,000 and $14,270,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2001 vs. SECOND QUARTER 2000 AND YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000 We have two businesses: wholesale which consists of generation, power marketing and trading of electricity; and energy delivery which consists of transmission and distribution services. Since the merger of AEP and CSW, we participate in power marketing and trading activities conducted on our behalf by the AEP System. Net income decreased $1.9 million or 24% for the quarter and was $4.9 million, or 41%, lower for the six months ended June 30, 2001. The decreases were primarily due to increased operating expenses primarily higher transmission related expenses offset in part by trading related activities and nonoperating income. Income statement line items which changed significantly were: Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % ------------- - ------------- - Operating Revenues $62 47 $161 71 Fuel Expense - - 31 41 Purchased Power Expense 58 258 125 334 Other Operation Expense 10 61 15 42 Maintenance Expense 2 40 2 17 Federal Income Taxes (3) (56) (5) (69) Nonoperating Income 3 82 4 127 The significant increase in operating revenues was primarily due to the participation in the AEP System's power marketing and trading activities subsequent to June 2000 and higher fuel related revenues due to increased fuel and purchased power expense of the wholesale business. WTU began sharing in AEP's marketing and trading transactions as a result of the merger of AEP and CSW in June 2000. Fuel expense increased due primarily to an increase in the average unit cost of fuel as a result of higher spot market natural gas prices. Purchased power expense's significant rise was primarily attributable to participation in AEP's trading operation and the impact of natural gas prices on wholesale purchased power prices. Other operation expense increase is due primarily to a 2000 reduction in energy delivery's transmission expenses that resulted from new prices for the Electric Reliability Council of Texas (ERCOT) transmission grid. Other operation expense also increased year-to-date due to a favorable adjustment made in January 2000 related to the FERC approved Transmission Coordination Agreement. Maintenance expense increased due to a scheduled overhaul in 2001 of Oklaunion Power Plant of our wholesale business. Federal income taxes attributable to operations decreased due primarily to a decrease in pre-tax income. The increase in nonoperating income was due primarily to a loss provision recorded in the second quarter of 2000 for the termination of merchandise sales and the cost of phasing out the merchandising sales program.
WEST TEXAS UTILITIES COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) OPERATING REVENUES $192,839 $130,742 $387,845 $227,277 -------- -------- -------- -------- OPERATING EXPENSES: Fuel 46,848 47,207 106,753 75,787 Purchased Power 80,485 22,455 162,177 37,348 Other Operation 25,355 15,751 51,111 36,055 Maintenance 7,046 5,045 11,608 9,907 Depreciation and Amortization 11,529 11,292 23,300 22,533 Taxes Other Than Federal Income Taxes 6,775 6,653 12,813 11,616 Federal Income Taxes 2,373 5,401 2,263 7,312 ----- ----- ----- ----- TOTAL OPERATING EXPENSES 180,411 113,804 370,025 200,558 ------- ------- ------- ------- OPERATING INCOME 12,428 16,938 17,820 26,719 NONOPERATING INCOME (LOSS) (553) (3,149) 878 (3,239) ---- ------ --- ------ INCOME BEFORE INTEREST CHARGES 11,875 13,789 18,698 23,480 INTEREST CHARGES 5,742 5,719 11,674 11,577 ----- ----- ------ ------ NET INCOME 6,133 8,070 7,024 11,903 PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 52 52 -- -- -- -- EARNINGS APPLICABLE TO COMMON STOCK $ 6,107 $ 8,044 $ 6,972 $11,851 ========= ======= ========= =======
STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2001 2000 2001 2000 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $116,247 $112,549 $122,588 $113,242 NET INCOME 6,133 8,070 7,024 11,903 DEDUCTIONS: Cash Dividends Declared: Common Stock 7,206 4,500 14,412 9,000 Preferred Stock 26 26 52 52 -- -- -- -- BALANCE AT END OF PERIOD $115,148 $116,093 $115,148 $116,093 ======== ======== ======== ======== The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 437,880 $ 431,793 Transmission 236,532 235,303 Distribution 424,258 416,587 General 112,139 110,832 Construction Work in Progress 35,156 34,824 ------ ------ Total Electric Utility Plant 1,245,965 1,229,339 Accumulated Depreciation and Amortization 531,411 515,041 ------- ------- NET ELECTRIC UTILITY PLANT 714,554 714,298 ------- ------- OTHER PROPERTY AND INVESTMENTS 24,100 23,154 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 10,705 20,944 ------ ------ CURRENT ASSETS: Cash and Cash Equivalents 6,941 3,982 Accounts Receivable: Customers 19,111 36,217 Affiliated Companies 8,271 16,095 Allowance for Uncollectible Accounts (299) (288) Fuel Inventory - at average cost 14,861 12,174 Materials and Supplies - at average cost 11,099 10,510 Underrecovered Fuel 59,129 68,107 Energy Trading Contracts 37,398 152,174 Prepayments and Other Current Assets 851 --- 811 TOTAL CURRENT ASSETS 154,363 302,781 ------- ------- REGULATORY ASSETS 19,075 24,808 ------ ------ DEFERRED CHARGES 10,188 2,947 ------ ----- TOTAL ASSETS $ 932,985 $1,088,932 ========== ========== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2001 December 31, 2000 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 7,800,000 Shares Outstanding - 5,488,560 Shares $ 137,214 $137,214 Paid-in Capital 2,236 2,236 Retained Earnings 115,148 122,588 ------- ------- Total Common Shareowner's Equity 254,598 262,038 Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482 2,482 Long-term Debt 255,905 255,843 ------- ------- TOTAL CAPITZALIZATION 512,985 520,363 ------- ------- CURRENT LIABILITIES: Advances from Affiliates 71,953 58,578 Accounts Payable - General 32,073 45,562 Accounts Payable - Affiliated Companies 12,896 42,212 Customer Deposits 2,659 4,614 Taxes Accrued 32,206 18,901 Interest Accrued 3,717 3,119 Energy Trading Contracts 37,083 154,919 Other 7,906 ----- 8,895 TOTAL CURRENT LIABILITIES 202,839 334,454 ------- ------- DEFERRED INCOME TAXES 152,232 157,038 ------- ------- DEFERRED INVESTMENT TAX CREDITS 23,416 24,052 ------ ------ LONG-TERM ENERGY TRADING CONTRACTS 20,789 ------ 10,972 REGULATORY LIABILITIES AND DEFERRED CREDITS 30,541 32,236 ------ ------ CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $ 932,985 $1,088,932 ========== ========== See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2001 2000 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 7,024 $11,903 Adjustments for Noncash Items: Depreciation and Amortization 23,300 22,959 Deferred Income Taxes (4,738) (1,220) Deferred Investment Tax Credits (636) (636) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 24,941 8,644 Fuel, Materials and Supplies (3,276) 5,682 Accounts Payable (42,805) 11,627 Taxes Accrued 13,305 (1,981) Transmission Coordination Agreement Settlement - 15,465 Deferred Property Taxes (6,200) - Fuel Recovery 8,978 (5,818) Other (net) (1,324) (894) ------ ---- Net Cash Flows From Operating Activities 18,569 65,731 ------ ------ INVESTING ACTIVITIES: Construction Expenditures (20,312) (32,470) Other (127) (1,878) ---- ------ Net Cash Flows Used For Investing Activities (20,439) (34,348) ------- ------- FINANCING ACTIVITIES: Retirement of Long-term Debt - (40,000) Change in Advances from Affiliates (net) 13,375 19,048 Dividends Paid on Common Stock (14,412) (9,000) Dividends Paid on Cumulative Preferred Stock (52) (55) --- --- Net Cash Flows Used For Financing Activities (1,089) (30,007) ------ ------- Net Increase (Decrease) in Cash and Cash Equivalents (2,959) 1,376 Cash and Cash Equivalents at Beginning of Period 6,941 6,074 ----- ----- Cash and Cash Equivalents at End of Period $ 3,982 $ 7,450 ======= =======
Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $10,139,000 and $9,053,000 and for income taxes was ($2,957,000) and $5,442,000 in 2001 and 2000, respectively. See Notes to Financial Statements beginning on page L-1.
NOTES TO FINANCIAL STATEMENTS JUNE 30, 2001 (UNAUDITED) The notes to financial statements are a combined presentation for AEP and its subsidiary registrants as follows: 1. General AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 2. Extraordinary Items AEP, CSPCo, OPCo 3. Acquisitions and Sales of Assets AEP, OPCo, SWEPCo 4. Rate Matters AEP, CPL, SWEPCo, WTU 5. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU 6. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 7. Financing and Related Activities AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 8. Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 2000 Annual Report as incorporated in and filed with the Form 10-K. The AEP System operating companies have reclassified certain settled forward energy transactions of their trading operation from a net to a gross basis of presentation in order to better reflect the scope and nature of the AEP System's energy sales and purchases. All financially net settled trading transactions, such as swaps, futures, and unexercised options, continue to be reported on a net basis, reflecting the financial nature of these transactions. The following prior year amounts were reclassified from revenues to purchased power expense to present the prior period on a comparable basis:
Three Months Ended Six Months Ended June 30, 2000 June 30, 2000 Company (in thousands) ------- AEP $4,968,235 $8,064,527 APCo 1,030,774 1,596,856 CSPCo 597,406 932,417 I&M 649,433 1,013,598 KPCo 244,901 379,152 OPCo 896,008 1,398,435
In the opinion of management, the unaudited financial statements reflect all normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. EXTRAORDINARY ITEMS OPCo and CSPCo Recognize Loss from the Stranding of Ohio Gross Receipts Tax OPCo and CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal credits during the quarter ended June 30, 2001. This loss resulted from regulatory decisions in connection with Ohio deregulation which stranded the recovery of the GRT. The components of the extraordinary loss by company were: CSPCo OPCo Total ----- ---- ----- (in thousands) Gross Receipts Tax $42,493 $50,461 $92,954 Less Coal Credits 7,733 17,361 25,094 ------- ------- ------- Net Liability for Ohio Gross Receipts Tax 34,760 33,100 67,860 Less Income Tax Benefit 8,353 11,585 19,938 ------- ------- ------- Extraordinary Loss $26,407 $21,515 $47,922 ======= ======= ======= As discussed in Note 7 of the 2000 Annual Report, CSPCo and OPCo appealed to the Ohio Supreme Court a PUCO order on Ohio restructuring that the companies believe failed to provide for recovery for the final year of the GRT. Effective May 1, 2001, the PUCO order reduced the companies' rates by the annual level of GRT. Effective with the liability affixing on May 1, 2001, the PUCO's decision to deny recovery in the final year of the GRT resulted, under SFAS 101, in an extraordinary impairment of the prepaid asset due to the deregulation of the companies' generation business. CSPCo and OPCo continue to seek recovery at the Ohio Supreme Court where a decision is expected in 2002. 3. ACQUISITIONS AND SALES OF ASSETS Acquisition of Houston Pipe Line Company - Affecting AEP On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe Line Company and Lodisco LLC for $727 million. The acquired assets include 4,200 miles of gas pipeline, a 30-year sublease of a gas storage facility and certain gas marketing contracts. The purchase method of accounting was used to record the acquisition. AEP may adjust the allocation of purchase price for changes in its preliminary evaluations and assumptions based on review of additional information. The purchase method results in the assets and earnings of the acquired operations being included in AEP's consolidated financial statements from the purchase date. Acquisition of Lignite Mining Operations - Affecting AEP and SWEPCo On June 1, 2001, SWEPCo assumed mining operations at its jointly owned lignite reserves in Louisiana. To settle litigation, which is discussed in Note 8, SWEPCo paid $86 million to purchase the mining assets and rights of the previous mine operator and assumed existing mine reclamation liabilities. The lignite from the mine will continue to supply SWEPCo's jointly owned power plant. Management expects the acquisition to have minimal impact on results of operations. Sale of Generating Assets - Affecting AEP In July 2001, AEP, through a wholly owned subsidiary, sold its 50% interest in a 120-megawatt generating plant located in Mexico. The sale resulted in a third quarter after tax gain of approximately $11 million. Sale of Affiliated Coal Mines - Affecting AEP and OPCo In July 2001 AEP and OPCo sold coal mines in Ohio and West Virginia and agreed to purchase approximately 34 million tons of coal from the purchaser of the mines through 2008. The sale is expected to have a nominal impact on results of operations and cash flows. 4. RATE MATTERS Texas Fuel Costs - Affecting AEP, CPL, SWEPCo and WTU As discussed in Note 5 of the 2000 Annual Report, AEP's Texas electric operating companies experienced natural gas fuel price increases which resulted in under-recoveries of fuel costs. Fuel recovery for Texas utilities is a multi-step procedure. When fuel costs change, utilities file with the PUCT for authority to adjust fuel factors. If a utility's prior fuel factors result in an over- or under-recovery of fuel, the utility will also request a surcharge factor to refund or collect that amount. While fuel factors are intended to recover all fuel-related costs, final settlement of these accounts are subject to reconciliation and approval by the PUCT. Fuel reconciliation proceedings determine whether fuel costs incurred and collected during the reconciliation period were reasonable and necessary. All fuel costs incurred since the prior reconciliation date are subject to PUCT review and approval. If material amounts are determined to be unreasonable and ordered to be refunded to customers, results of operations and cash flows would be negatively impacted. Fuel cost in the Texas jurisdiction after 2001 will no longer be subject to PUCT review and reconciliation. During 2002 CPL, SWEPCo, and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. The unrecovered deferred fuel balances at December 31, 2001 will be included in each company's 2004 true-up proceeding. If the final under-recovered fuel balances or any amounts incurred but not yet reconciled are disallowed, it would have a negative impact on results of operations. The following table lists the Texas jurisdictional reconciliation status, total fuel cost subject to reconciliation, under-recovered fuel balances and the remaining fuel surcharge for the companies:
Fuel cost subject to Under-recovered Reconciliation reconciliation at fuel balances at Remaining authorized Company completed through June 30, 2001 June 30, 2001 fuel surcharge ------- ----------------- ------------- ------------- -------------- CPL June 30, 1998 $1.4 billion $93 million $25 million SWEPCo December 31, 1999 240 million 29 million 13 million WTU June 30, 1997 581 million 57 million 6 million
Under Texas restructuring, newly organized retail electric providers will make sales to consumers beginning in January 1, 2002. These sales will be at fixed rates during a transition period from 2002 through 2006. However, the fuel cost component of a retail electric providers' fixed rates will be subject to prospective adjustment twice a year based upon changes in a natural gas price index. As part of the preparation for customer choice, CPL, SWEPCo and WTU filed their proposed fuel factors to be implemented as part of the fixed rates effective January 1, 2002. The filings are pending at the PUCT. Status of Rate Filings Central Power and Light In January 2001 CPL filed an application with the PUCT to implement a $175.9 million increase in fuel factors over the ten months March 2001 through December 2001. In addition, to collect its under-recovered fuel costs, CPL proposed to implement an interim fuel surcharge of $51.8 million, which includes accumulated interest on unrecovered amounts. The PUCT approved in April 2001 the implementation of a $170.5 million increase in fixed fuel factors. The PUCT voted to defer implementation of the requested fuel surcharge until the final fuel reconciliation, which occurs as part of the 2004 true-up proceeding. Southwestern Electric Power Company In November 2000 SWEPCo filed with the PUCT to increase its fuel factors effective January 2001 and to collect previously under-recovered fuel costs over a six-month period through a proposed interim fuel surcharge, which includes accumulated interest on previous unrecovered fuel costs. The PUCT approved an increase in SWEPCo's fuel factors of $12 million and the implementation of a fuel surcharge of $11.8 million from February to July 2001. In May 2001 SWEPCo filed an application to increase its fuel factors by $4.3 million. The application also proposed a fuel surcharge of $18.3 million, which includes accumulated interest on previous unrecovered fuel costs. The PUCT approved in August 2001 a unanimous stipulation, requiring SWEPCo to withdraw its fuel factors request and to implement a surcharge of $10.7 million for unrecovered fuel. The PUCT deferred the remaining $6.8 million balance of unrecovered fuel until a later proceeding. West Texas Utilities In April 2001 the PUCT approved new fuel factors for WTU to collect $43.4 million of increased fuel costs from March through December 2001. WTU implemented the increase in its fuel factors in March 2001 after an Administrative Law Judge approved a settlement of WTU's application. WTU's original application, in January 2001, had requested a $46.5 million increase in its fuel factors. In March 2001 WTU filed with the PUCT to implement a fuel surcharge for under-recovered fuel costs of $59.5 million including interest on previous unrecovered fuel costs. WTU requested that the surcharge be effective May 2001 through December 2001. A decision on the WTU fuel surcharge request is pending. Management expects the PUCT to defer WTU's recovery until the 2004 true-up proceeding. Texas Transmission Rates - Affecting AEP, CPL and WTU On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing mechanism created by the PUCT in 1996 was invalid. The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT exceeded its statutory authority to set such rates for the period January 1, 1997 through August 31, 1999. Effective September 1, 1999, the legislature granted this authority to the PUCT. CPL and WTU were not parties to the case. However, the companies' transmission sales and purchases were priced using the invalid rates. It is unclear what action the PUCT will take to respond to the court's ruling. If the PUCT changes rates retroactively, the result could have a material impact on results of operations and cash flows for CPL and WTU. Excess Earnings - Affecting AEP, CPL, SWEPCo and WTU In March 2001 CPL, SWEPCo and WTU filed their Annual Report of Excess Earnings for 2000 with the PUCT. In July 2001 the companies received official notice of certain disagreements with the reports as filed from the Staff of the PUCT and the Office of Public Utility Counsel (OPC). The Staff and OPC took exception to certain adjustments made by the companies, and OPC also took exception to the application of certain sections of the law as it pertains to the calculation of revenue within the report. The table below shows the amounts of excess earnings calculated by each company, the PUCT Staff and the OPC: 2000 Excess Earnings As filed As calculated As calculated by company by PUCT Staff by the OPC ---------- ------------- ---------- (in millions) CPL $12.6 $21.7 $42.4 SWEPCo (3.7) 1.4 1.2 WTU 10.2 16.6 15.3 The companies believe that the calculations in their reports are proper and believe the ultimate amount of excess earnings finally approved by the PUCT will not have a materially adverse effect on their results of operations or cash flows. A PUCT decision is due in late August 2001. 5. INDUSTRY RESTRUCTURING As discussed in the 2000 Annual Report, restructuring legislation has been enacted in seven of AEP's eleven state retail electric jurisdictions. The legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the generation of electricity. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. The PUCO approved alternative suppliers (many of whom remain inactive) to compete for CSPCo's and OPCo's customers. Virtually all customers continue to be served by CSPCo and OPCo. In accordance with the Ohio Act, CSPCo and OPCo implemented rate reductions of 5% for the generation portion of residential rates effective January 1, 2001. The generation portion of retail rates, including fuel, will remain frozen until December 31, 2005 or the PUCO determines that a competitive market exists. On January 16, 2001, Shell Energy Services Company filed a Notice of Appeal with the Ohio Supreme Court challenging PUCO's approval of our transition settlement agreement including recovery of regulatory assets. Management is unable to predict the outcome of this litigation. The resolution of this matter could negatively impact future results of operations and cash flows. Virginia Restructuring - Affecting AEP and APCo In accordance with its restructuring law, the Virginia jurisdiction will begin a transition to choice of electricity supplier for retail customers on January 1, 2002. The Virginia restructuring law requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. APCo filed its separation plan and rate unbundling plan with the Virginia SCC. Hearings are scheduled for October 2001. Presently, capped rates are sufficient to recover generation-related regulatory assets. Management is unable to predict if the outcome of the hearings will result in the ability to recover generation-related regulatory assets. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor to delay restructuring. The legislation extended the date for the start of retail electric competition to October 1, 2003 and provided the Arkansas Commission with the authority to delay that date for up to two additional years. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU Texas Restructuring Legislation gives customers the opportunity to choose their electric provider and eliminates the fuel clause reconciliation process beginning January 1, 2002. A 2004 true-up proceeding will determine the amount of stranded costs including the final fuel recovery, net regulatory asset recovery, excess earnings offsets and other issues. As discussed in the 2000 Annual Report, the method used to determine initial stranded costs to be recovered beginning on January 1, 2002 is still subject to challenge. In March 2000 CPL submitted a $1.1 billion estimate of stranded costs. After hearing on the submission, the PUCT issued in February 2001 an interim decision determining an initial amount of stranded costs for CPL of negative $580 million. In April 2001 the PUCT ruled that its current estimate of CPL's stranded costs was negative $615 million. CPL disagrees with the ruling and has requested a rehearing. In April 2001 the PUCT issued an order requiring CPL to reduce future distribution rates by $54.8 million over a five-year period in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings reduce stranded costs. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings. Management believes that CPL will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time. CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the April order has no effect on reported net income. As discussed in Note 7 of the 2000 Annual Report, the PUCT authorized the issuance of up to $797 million of bonds to securitize certain of CPL's regulatory assets. The PUCT's order that authorized the securization was appealed to the Supreme Court of Texas. On June 6, 2001, the Supreme Court upheld the PUCT's securitization order. The plaintiffs have requested a rehearing. We expect the court to dismiss this request. Management plans to issue the securitization bonds prior to January 1, 2002. On August 3, 2001, the Staff of the PUCT filed a Petition seeking a determination of whether electric operations in the SPP are ready for competition. This Petition affects SWEPCo and part of WTU. Under the Texas Restructuring Legislation, the PUCT can delay the start of competition if the market and its participants are not prepared for competition. Under the law, certain situations indicate this lack of preparedness, and in Staff's opinion, those indicators are present for the SPP area. The Petition seeks an expedited process to achieve a final PUCT determination by November 1, 2001. Management is evaluating the ramifications of a potential delay in the January 1, 2002 start date of competition for SWEPCo's and WTU's Texas operations in the SPP. A Texas settlement agreement in connection with the AEP and CSW merger permits CPL to apply up to $20 million of previously identified STP ECOM plant assets a year in 2000 and 2001 to reduce any excess earnings. STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis. To the extent excess earnings exceed $20 million in 2001, CPL will establish a regulatory liability or reduce regulatory assets by a charge to earnings. In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to recover their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Michigan Restructuring - Affecting AEP and I&M As discussed in the 2000 Annual Report, the Michigan Legislation gave the MPSC broad powers to implement customer choice. In compliance with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access tariffs and terms of service. MPSC action on the filing is expected in 2001 with competition commencing on January 1, 2002. Management does not expect that I&M will incur material tangible asset impairments or regulatory asset write-offs. If I&M is not permitted to recover all or a portion of its generation-related regulatory assets, unrecorded decommissioning obligation, stranded costs and other implementation costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Oklahoma Restructuring - Affecting AEP and PSO In June 2001 the Oklahoma Governor signed into law a bill that delayed retail electric competition indefinitely. Under previously approved legislation, the start date for Oklahoma customer choice had been July 1, 2002. 6. BUSINESS SEGMENTS AEP's three principal business segments and their respective activities are: o Wholesale o Generation of electricity for sale to retail and wholesale customers. o Trading of electricity and gas worldwide. o Other energy supply related businesses. o Energy Delivery o Domestic electric transmission. o Domestic electric distribution. o Other Investments o Foreign electricity generation investments. o Foreign electric distribution and supply. o Telecommunication services. Amounts reported below for the three business segments include certain estimates and allocations where necessary.
Energy Other Reconciling Wholesale Delivery Investments Adjustments Consolidated June 30, 2001 (in millions) Revenues from: External customers $22,877 $ 1,637 $1,881 $ 2,298 $28,693 Transactions with other operating segments 1,067 10 30 (1,107) - Segment EBIT 845 483 142 (71) 1,399 Total assets 29,566 14,379 7,539 (1,257) 50,227 June 30, 2000 Revenues from: External customers 11,731 1,508 1,078 (63) 14,254 Transactions with other operating segments 734 1 50 (785) - Segment EBIT 302 513 155 (197) 773 Total assets 21,033 12,370 7,709 (713) 40,399
All of the registrant subsidiaries, except AEGCo, have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.
Wholesale Segment June 30, 2001 June 30, 2000 Revenues Revenues From From External Segment External Segment Customers EBIT Total Assets Customers EBIT Total Assets (in thousands) (in thousands) APCo $3,523,410 $107,415 $3,666,392 $2,198,766 $ 74,080 $2,970,385 CPL 1,008,450 133,445 2,935,249 535,881 100,597 2,789,432 CSPCo 2,016,002 119,544 2,499,506 1,370,892 100,274 2,107,087 I&M 2,394,505 86,108 3,994,291 1,569,142 (123,565) 3,517,833 KPCo 831,124 4,162 772,669 509,991 2,425 605,132 OPCo 3,061,833 125,565 3,927,606 2,255,604 147,781 3,657,373 PSO 644,622 12,124 859,240 267,225 14,203 747,576 SWEPCo 696,457 32,036 1,184,118 324,673 3,608 1,048,972 WTU 306,515 1,336 400,251 149,959 241 360,295
Energy Delivery Segment June 30, 2001 June 30, 2000 Revenues Revenues From From External Segment External Segment Customers EBIT Total Assets Customers EBIT Total Assets (in thousands) (in thousands) APCo $300,021 $115,711 $2,892,449 $283,686 $113,629 $2,343,363 CPL 243,461 65,612 2,108,135 218,358 75,334 2,003,407 CSPCo 218,666 44,065 1,405,972 190,745 36,605 1,185,236 I&M 156,907 61,410 1,802,938 150,714 55,592 1,587,875 KPCo 67,164 27,246 748,333 64,123 30,337 586,072 OPCo 265,009 58,512 2,190,161 228,563 67,336 2,039,469 PSO 109,711 23,187 957,334 103,276 28,855 832,922 SWEPCo 164,027 51,909 1,232,449 159,892 60,994 1,091,788 WTU 81,330 21,041 532,734 77,318 28,508 479,553
Registrant Subsidiaries Company Total June 30, 2001 June 30, 2000 Revenues Revenues From From External External Customers EBIT Total Assets Customers EBIT Total Assets (in thousands) (in thousands) APCo $3,823,431 $223,126 $6,558,841 $2,482,452 $187,709 $5,313,748 CPL 1,251,911 199,057 5,043,384 754,452 175,931 4,792,839 CSPCo 2,234,668 163,609 3,905,478 1,561,637 136,879 3,292,323 I&M 2,551,412 147,518 5,797,229 1,719,856 (67,973) 5,105,708 KPCo 898,288 31,408 1,521,002 574,114 32,762 1,191,204 OPCo 3,326,842 184,077 6,117,767 2,484,167 215,117 5,696,842 PSO 754,333 35,311 1,816,574 370,501 43,058 1,580,498 SWEPCo 860,484 83,945 2,416,567 484,565 64,602 2,140,760 WTU 387,845 22,377 932,985 227,277 28,749 839,848
Management's intention is to structurally and functionally separate operations into regulated and non-regulated businesses. The vertically integrated generation-transmission-distribution operations of the utility companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU) will be unbundled into non-regulated wholesale and regulated energy delivery businesses. The remaining utility subsidiaries are expected to be grouped with AEP's regulated business. Management is currently in the process of obtaining the necessary regulatory approvals to support this new business structure. 7. FINANCING AND RELATED ACTIVITIES
Long-term debt and other securities issuances and retirements during the first six months of 2001 were: Type Principal Interest Company of Debt Amount Rate Due Date ------- ------- --------- -------- -------- Issuances (in millions) (%) --------- AEP Senior Unsecured Notes $ 250 5.50 2003 AEP Senior Unsecured Notes 1,000 6.125 2006 Other AEP Subs. Various 152 4.00-6.00 2001-2004 ------ Total AEP System $1,402 ====== Retirements APCo First Mortgage Bonds $100 6-3/8 2001 APCo Senior Unsecured Notes 75 4.00-6.00 2001 CPL Trust Preferred Securities 1 8.00 2037 I&M First Mortgage Bonds 40 7.63 2001 KPCo First Mortgage Bonds 20 8.95 2001 KPCo First Mortgage Bonds 40 8.90 2001 OPCo Senior Unsecured Notes 75 4.00-6.00 2001 OPCo Notes Payable 30 6.20 2001 OPCo Finance Obligation 13 6.98 2001 PSO First Mortgage Bonds 6 5.91 2001 PSO First Mortgage Bonds 5 6.02 2001 PSO First Mortgage Bonds 9 6.02 2001 Other AEP Subs. Various 43 4.00-6.00 2001 ---- Total AEP System $457 ====
In addition to the transactions reported in the table above, the following table lists intercompany issuances of debt due to AEP Co., Inc.
Interest Company Type of Debt Principal Amount Rate Due Date ------- ------------ ---------------- ---- -------- Issuances (in millions) (%) --------- KPCo Note Payable $ 60 6.501 2006 KPCo Note Payable 15 4.336 2003 Non-Registrant AEP Subsidiaries Note Payable 644 4.336-6.501 2001-2006 ---- Total AEP System $719 ====
8. CONTINGENCIES Litigation Shareholders' Litigation - Affecting AEP In 2000 five complaints were filed against AEP seeking unspecified compensatory damages for alleged violations of federal securities laws. A court order consolidated the cases. However, the court has not determined if the plaintiffs represent a class consisting of all persons and entities who acquired AEP common stock between July 25, 1997 and June 25, 1999. On March 5, 2001, AEP filed a motion to dismiss the cases. All parties presented oral arguments on AEP's motion to dismiss on June 7, 2001. Management believes these shareholder complaints are without merit and intends to continue to oppose them. The outcome of this litigation or its impact on results of operations, cash flows or financial condition cannot be predicted. Municipal Franchise Fee Litigation - Affecting AEP and CPL CPL has been involved in litigation regarding municipal franchise fees in Texas as a result of a class action suit filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and seeks damage of up to $300 million plus attorney's fees. CPL filed a counterclaim for overpayment of franchise fees. The litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. CPL notified the cities it serves of the pending class action suit. If a final decision determines an underpayment of franchise fees, CPL has pledged to extend that final decision to cities who declined to participate in the suit. The court ruled that the class of plaintiffs would consist of approximately 30 cities and set a trial date for October 2001. Management believes that it has substantial defenses against the cities' claims and plans to pursue its counterclaims. However, management cannot predict the outcome of this litigation or its impact on results of operations, cash flows or financial condition. Texas Base Rate Litigation - Affecting AEP and CPL As discussed in the 2000 Annual Report, CPL is involved in litigation concerning a 1997 PUCT base rate order. A request for review is pending before the Texas Supreme Court. The primary issues are: o Classification of $800 million of invested capital at STP as excess cost over market (ECOM) earning a lower return than other generating property; and o An $18 million disallowance of affiliated service billings. Management is unable to predict the final resolution of this litigation or its impact on results of operations and cash flows. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In May 2001 SWEPCo settled ongoing litigation concerning lignite mining in Louisiana. As discussed in Note 8 of the 2000 Annual Report, SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are joint owners of Dolet Hills Power Station Unit 1 and own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982 SWEPCo and CLECO entered into a lignite mining agreement with DHMV, a partnership for the mining and delivery of lignite from these reserves. Since 1997 SWEPCo and CLECO have been involved in litigation with DHMV and its partners. In 2000 the parties agreed to settle the litigation. As part of the settlement, SWEPCo purchased DHMV's interest in the mining assets and mining rights for $86 million and assumed the related obligations for mine reclamation (See Note 3). The settlement agreement gives CLECO the option to acquire up to a 50% interest in the mining assets. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in the 2000 Annual Report, Federal EPA and a number of states alleged that AEP, APCo, CSPCo, I&M and OPCo modified certain generating units in violation of the Clean Air Act. The Federal EPA filed complaints against the companies in U.S. District Court for the Southern District of Ohio in 1999. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints, cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the plaintiffs requested a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. The AEP System companies' request to allow time for additional discovery before responding to the plaintiffs' action was granted. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. In the event the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned with CSPCo, reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future earnings and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo Federal EPA issued a rule (the NOx Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including states in which the AEP System's generating plants are located. The NOx Rule was upheld by the D.C. Circuit Court. The U.S. Supreme Court denied a petition requesting its review of the lower court decision. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its mandates. Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit compliance plans. This ruling means that those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. AEP and other utilities requested the D.C. Circuit Court review this ruling. Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired generating units. After review, the D.C. Circuit Court upheld the Section 126 Rule. The D.C. Circuit Court instructed Federal EPA for both the NOx Rule and the Section 126 Rule to justify methods used to allocate allowances and project growth. AEP and other utilities requested the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. They also asked the D.C. Circuit Court to retain jurisdiction until Federal EPA complied with the Court's instructions. The Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including those owned by CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. In May 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant began operation. Construction of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant began in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million ($145 million for APCo and $85 million for OPCo). Construction of SCR technology on KPCo's Big Sandy Plant Unit 2 is scheduled for completion in May 2003 at an estimated cost of $107 million. Preliminary estimates indicate that compliance for the AEP System with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures totaling approximately $1.6 billion. Estimated compliance costs by registrant subsidiaries are as follows: (in millions) AEGCo $125 APCo 365 CPL 57 CSPCo 106 I&M 202 KPCo 140 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital and operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2000 Annual Report. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS This is our combined presentation of management's discussion and analysis of financial condition, contingencies and other matters related to AEP and our subsidiary registrants. Management's discussion and analysis of results of operations for the three and six month periods ended June 30, 2001 is presented with each registrants' financial statements elsewhere in this document. FINANCIAL CONDITION Financing Activity On May 10, 2001, AEP issued $1.25 billion of debt consisting of $1 billion of senior notes and $250 million of putable callable notes. The interest rate on the senior notes (due May 2006) is 6.125%. Additionally, AEP entered into an interest rate swap for a portion of the proceeds, which effectively converts a portion of this interest rate into LIBOR based floating rate through 2006. The putable callable notes (Series B notes) have a fixed interest rate of 5.5% until May 2003. At that date the Series B notes may be subject to call by a third party for purchase and remarketing, in which case the maturity would extend until May 2013. If the Series B notes are not called for remarketing, they will be redeemed. On May 24, 2001, AEP renewed its existing $2.5 billion 364-day revolving credit facility. AEP renews this facility annually and uses it, together with an existing $1 billion 5-year revolving credit which matures May 30, 2005 as a backstop for AEP's commercial paper program. On May 30, 2001, AEP Credit ceased to issue commercial paper and allowed its $2 billion unsecured revolving credit facility to mature. A $1.5 billion 364-day note purchase agreement, which closed on May 30, 2001, replaced Credit's funding needs. Bank-sponsored conduits are funding this facility. Acquisitions We continue to pursue a strategy of aligning assets with our wholesale business model. The strategy is to selectively purchase assets which enhance information flow from energy markets and support our trading and marketing activity. The June 2001 purchase of Houston Pipe Line Company (HPL) complements our existing Louisiana natural gas assets and will contribute to continued growth in natural gas marketing and trading. The HPL acquisition includes 4,200 miles of pipeline with capacity of approximately 2.4 billion cubic feet per day (Bcf/d), the operation of the Bammel Storage Facility, one of the largest storage facilities in North America with a capacity of approximately 118 billion cubic feet, and certain gas marketing contracts. We used short-term borrowings of $727 million for the interim financing of this acquisition. In the third quarter, we plan to replace this short-term borrowing with long-term financing through a limited liability company. The limited liability company expects to sell a non-controlling, preferred interest to a third party for $750 million. The preferred interest will receive a preferred return equal to an adjusted floating reference rate. The results of operations, cash flows and financial position of the limited liability company will be consolidated with AEP and treated as minority interests. We announced our plan to acquire the MEMCO Barge Line. This acquisition will continue our growth strategy to create value at various points along the energy chain. With the addition of MEMCO, we will triple the size of our barge fleet and become a full-service carrier throughout the U.S. inland waterways. We expect this acquisition to add to both earnings and meaningful operational insight into the fuel transportation portion of our business. Total consolidated plant and property additions including capital leases for the year-to-date period were $865 million. The following table shows the additions by certain subsidiary registrants: Company Amount ------- ------ (in millions) APCo $108 CPL 110 I&M 41 OPCo 151 SWEPCo 96 Corporate Separation On July 24, 2001, we filed an application with the FERC requesting approval of proposed transactions necessary to complete a restructuring of our regulated and unregulated operations. These transactions will enable us to implement our plans for corporate separation and allow us to meet the requirements of Texas and Ohio restructuring legislation. As part of the filed plan, AEP intends to transfer the generation assets from the integrated business for Ohio and Texas operating companies, which includes CSPCo, OPCo, CPL and WTU, to unregulated companies. The filed plan also proposes amendments of the power pooling agreements that affects all operating companies. Only those operating companies that continue to exist as integrated utilities would be included in the amended power pooling agreements, which would govern energy exchanges among members and off system purchases and sales. In order to execute this separation, we anticipate retiring first mortgage bonds at CSPCo, OPCo, CPL and WTU using various methods including: o call provisions for bonds that have an optional redemption o open market purchases o exchange offers o tender offers o defeasance To date, we have not made decisions relating to securities other than first mortgage bonds. OTHER MATTERS Industry Restructuring As discussed in our 2000 Annual Report, seven of our eleven state retail jurisdictions enacted restructuring legislation. The legislation provides for a transition from cost-based regulation of bundled electric service to unbundled customer choice and market pricing for the generation of electricity. Ohio Restructuring - Affecting AEP, CSPCo and OPCo Effective January 1, 2001, customer choice of electricity supplier began under the Ohio Act. The PUCO approved alternative suppliers (many of whom remain inactive) to compete for CSPCo's and OPCo's customers. CSPCo and OPCo continue to serve virtually all customers. In accordance with the Ohio Act, CSPCo and OPCo implemented rate reductions of 5% for the generation portion of residential rates effective January 1, 2001. Retail rates, including fuel, will remain frozen until December 31, 2005 or the PUCO determines that a competitive market exists. On January 16, 2001, Shell Energy Services Company filed a Notice of Appeal with the Ohio Supreme Court challenging PUCO's approval of our transition settlement agreement including recovery of regulatory assets. Management is unable to predict the outcome of this litigation. The resolution of this matter could negatively impact our future results of operations and cash flows. Virginia Restructuring - Affecting AEP and APCo In accordance with its restructuring law, the Virginia jurisdiction will begin a transition to choice of electricity supplier for retail customers on January 1, 2002. The Virginia restructuring law requires filings to be made that outline the functional separation of generation from transmission and distribution and a rate unbundling plan. APCo filed its separation plan and rate unbundling plan with the Virginia SCC. Hearings are scheduled for October 2001. Presently, capped rates are sufficient to recover generation-related regulatory assets. We are unable to predict if the outcome of the hearings will result in the ability to recover generation-related regulatory assets. Arkansas Restructuring - Affecting AEP and SWEPCo In 1999 Arkansas enacted legislation to restructure its electric utility industry. In February 2001 the Arkansas General Assembly passed legislation that was signed into law by the Governor to delay restructuring. The legislation extended the date for the start of retail electric competition to October 1, 2003 and provided the Arkansas Commission with the authority to delay that date for up to two additional years. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU Texas Restructuring Legislation gives customers the opportunity to choose their electric provider and eliminates the fuel clause reconciliation process beginning January 1, 2002. A 2004 true-up proceeding will determine the amount of stranded costs including the final fuel recovery, net regulatory asset recovery, excess earnings offsets and other issues. As discussed in our 2000 Annual Report, the method used to determine initial stranded costs to be recovered beginning on January 1, 2002 is still subject to challenge. In March 2000 CPL submitted a $1.1 billion estimate of stranded costs. After hearing on the submission, the PUCT issued in February 2001 an interim decision determining an initial amount of stranded costs for CPL of negative $580 million. In April 2001 the PUCT ruled that its current estimate of CPL's stranded costs was negative $615 million. We disagree with the ruling and have requested a rehearing. In April 2001 the PUCT issued an order requiring CPL to reduce future distribution rates by $54.8 million over a five-year period in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings reduce stranded costs. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL will have no stranded costs and has ordered the rate reduction to return excess earnings. We believe that CPL will have stranded costs in 2004, and that the current treatment of excess earnings will be amended at that time. CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the April order has no effect on reported net income. As discussed in Note 7 of our 2000 Annual Report, the PUCT authorized the issuance of up to $797 million of bonds to securitize certain of CPL's regulatory assets. The PUCT's order that authorized the securization was appealed to the Supreme Court of Texas. On June 6, 2001, the Supreme Court upheld the PUCT's securitization order. The plantiffs have requested a rehearing. We expect the court to dismiss this request. We plan to issue the securitization bonds prior to January 1, 2002. On August 3, 2001, the Staff of the PUCT filed a Petition seeking a determination of whether electric operations in the SPP are ready for competition. This Petition affects SWEPCo and part of WTU. Under the Texas Restructuring Legislation, the PUCT can delay the start of competition if the market and its participants are not prepared for competition. Under the law, certain situations indicate this lack of preparedness, and in Staff's opinion, those indicators are present for the SPP area. The Petition seeks an expedited process to achieve a final PUCT determination by November 1, 2001. We are evaluating the ramifications of a potential delay in the January 1, 2002 start date of competition for SWEPCo's and WTU's Texas operations in the SPP. A Texas settlement agreement in connection with our merger with CSW permits CPL to apply up to $20 million of previously identified STP ECOM plant assets a year in 2000 and 2001 to reduce any excess earnings. STP ECOM plant assets will be depreciated in accordance with GAAP, on a systematic and rational basis. To the extent excess earnings exceed $20 million in 2001, CPL will establish a regulatory liability or reduce regulatory assets by a charge to earnings. In the event CPL, SWEPCo, and WTU are unable, after the 2004 true-up proceeding, to recover their generation-related regulatory assets, unrecovered fuel balances, stranded costs and other restructuring related costs, it could have a material adverse effect on results of operations, cash flows and possibly financial condition. Michigan Restructuring - Affecting AEP and I&M As discussed in the 2000 Annual Report, the Michigan Legislation gave the MPSC broad powers to implement customer choice. In compliance with MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access tariffs and terms of service. MPSC action on the filing is expected in 2001 with competition commencing on January 1, 2002. We do not expect to incur material tangible asset impairments or regulatory asset write-offs. If we are not permitted to recover all or a portion of our generation-related regulatory assets, unrecorded decommissioning obligation, stranded costs and other implementation costs, it could have a material adverse effect on our results of operations, cash flows and possibly financial condition. Oklahoma Restructuring - Affecting AEP and PSO In June 2001 the Oklahoma Governor signed into law a bill that delayed retail electric competition indefinitely. Under previously approved legislation, the start date for Oklahoma customer choice had been July 1, 2002. Litigation Shareholders' Litigation - Affecting AEP In 2000 five complaints were filed against us seeking unspecified compensatory damages for alleged violations of federal securities laws (see Note 8). We believe these shareholder complaints are without merit and intend to continue to oppose them. The outcome of this litigation or its impact on our results of operations, cash flows or financial condition cannot be predicted. Municipal Franchise Fee Litigation - Affecting AEP and CPL We have been involved in litigation regarding municipal franchise fees in Texas as a result of a class action suit filed by the City of San Juan, Texas in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and seeks damage of up to $300 million plus attorney's fees. CPL filed a counterclaim for overpayment of franchise fees. The litigation moved procedurally through the Texas Court System and was sent to mediation without resolution. CPL notified the cities it serves of the pending class action suit. If a final decision determines an underpayment of franchise fees, CPL has pledged to extend that final decision to cities who declined to participate in the suit. The court ruled that the class of plaintiffs would consist of approximately 30 cities and set a trial date for October 2001. We believe that we have substantial defenses against the cities' claims and plan to pursue our counterclaims. However, we cannot predict the outcome of this litigation or its impact on our results of operations, cash flows or financial condition. Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo In May 2001 SWEPCo settled ongoing litigation concerning lignite mining in Louisiana. As discussed in Note 8 of the 2000 Annual Report, SWEPCo has been involved in litigation concerning the mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are joint owners of Dolet Hills Power Station Unit 1 and own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982 SWEPCo and CLECO entered into a lignite mining agreement with DHMV, a partnership for the mining and delivery of lignite from these reserves. Since 1997 SWEPCo and CLECO have been involved in litigation with DHMV and its partners. In 2000 the parties agreed to settle the litigation. As part of the settlement, SWEPCo purchased DHMV's interest in the mining assets and mining rights for $86 million and assumed the related obligations for mine reclamation (See Note 3). The settlement agreement gives CLECO the option to acquire up to a 50% interest in the mining assets. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, I&M, and OPCo As discussed in our 2000 Annual Report, Federal EPA and a number of states alleged that AEP, APCo, CSPCo, I&M, and OPCo modified certain generating units in violation of the Clean Air Act. The Federal EPA filed complaints against the companies in U.S. District Court for the Southern District of Ohio in 1999. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20 year period. Under the Clean Air Act, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In March 2001 the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints, cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the plaintiffs requested a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. Our request to allow time for additional discovery before responding to the plaintiffs' action was granted. We believe our maintenance, repair and replacement activities were in conformity with the Clean Air Act and intend to vigorously pursue our defense. If we do not prevail, any capital and operating costs of additional pollution control equipment that may be required as well as any penalties imposed would adversely affect future results of operations, cash flows and possibly financial condition. In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing in an attempt to reach final settlement terms. Cinergy's settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement's impact on its jointly owned facilities and its future earnings and cash flows. NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo Federal EPA issued a rule (the NOx Rule) requiring substantial reductions in NOx emissions in a number of eastern states, including certain states in which the AEP System's generating plants are located. The NOx Rule was upheld by the D.C. Circuit Court. The U.S. Supreme Court denied a petition requesting its review of the lower court decision. The compliance date for the NOx Rule is May 31, 2004. The NOx Rule required states to submit plans to comply with its mandates. Federal EPA ruled that eleven states, including states in which APCo's, I&M's and OPCo's generating units are located, failed to submit compliance plans. This ruling means that those states could face stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA takeover of state air quality management programs. AEP and other utilities requested the D.C. Circuit Court review this ruling. Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by certain northeastern states under the Clean Air Act. The rule imposes emissions reduction requirements comparable to the NOx Rule beginning May 1, 2003, for most of our coal-fired generating units. After review, the D.C. Circuit Court upheld the Section 126 Rule. The D.C. Circuit Court instructed Federal EPA for both the NOx Rule and the Section 126 Rule to justify methods used to allocate allowances and project growth. AEP and other utilities requested the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. They also asked the D.C. Circuit Court to retain jurisdiction until Federal EPA complied with the Court's instructions. The Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including those owned by CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. In May 2001 selective catalytic reduction (SCR) technology to reduce NOx emissions on OPCo's Gavin Plant began operation. Construction of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant began in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are estimated to cost a total of $230 million ($145 million for APCo and $85 million for OPCo). Construction of SCR technology on KPCo's Big Sandy Plant Unit 2 is scheduled for completion in May 2003 at an estimated cost of $107 million. Preliminary estimates indicate that our compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures totaling approximately $1.6 billion. The following table shows the estimated compliance cost for certain of AEP's subsidiary registrants. Company Amount ------- ------ (in millions) APCo $365 CPL 57 I&M 202 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the preliminary estimates depending upon the compliance alternatives selected to achieve reductions in NOx emissions. Unless any capital or operating costs for additional pollution control equipment are recovered from customers, they will have an adverse effect on future results of operations, cash flows and possibly financial condition. New Accounting Standards FASB's Derivative Implementation Group (DIG) Guidance for SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" DIG guidance for fuel supply (for example, coal and gas) and electricity contracts becomes effective in the third quarter. DIG guidance concluded that fuel supply contracts with volumetric optionality cannot qualify as a normal purchase or sale and provided guidance for determining when electricity contracts can qualify as a normal purchase or sale. Predominantly all of AEP's contracts for coal, gas and electricity which are recorded on a settlement basis do not meet the criteria of a financial derivative instrument and are thereby exempt from DIG guidance described above. The few contracts that qualify as financial derivative instruments are not expected to materially affect AEP's results of operations, cash flows or financial condition. SFAS 141 and SFAS 142 In July 2001 the FASB issued SFAS 141, "Business Combinations" and SFAS 142, "Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase method of accounting be used to account for all business combinations entered into after June 30, 2001. SFAS 142 requires that goodwill and other intangible assets with indefinite lives be tested for impairment annually and not be subjected to amortization. The provisions of SFAS 142 will apply to us beginning January 1, 2002. The amortization of goodwill reduced our net income by $23 million for the six months ended June 30, 2001. We have not quantified the impact of adopting other provisions of these standards. QUALITATIVE AND QUANTITATIVE DISCLOSURES ON RISK RISK MANAGEMENT AEP and its registrant subsidiaries are subject to risks in their day to day operations. The risks and correlating strategies are:
Risk Description Strategy ---- ----------- -------- Market Risk Volatility in commodity prices Trading and hedging Interest Rate Risk Changes in Interest rates Hedging Foreign Exchange Risk Fluctuations in foreign currency rates Hedging Credit Risk Non-performance on contracts with Guarantees, Collateral counter parties
AEP's strategies of trading, hedging and credit risk management to mitigate various risks have not materially changed since December 31, 2000. Commodity Price Risk We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset market risk. AEP's internationally based electric distribution utilities hedge market risk through forward commodity contracts. Interest Rate Risk Fair value and cash flow hedge contracts mitigate changes in interest rates on short and long-term debt of AEP, KPCo, and I&M. CitiPower uses interest rate swaps for the same purpose. Foreign Exchange Risk AEP, KPCo, and OPCo employ cash flow forward hedge contracts to lock-in prices on purchased assets denominated in foreign currencies. International subsidiaries use currency swaps to hedge fluctuations in debt transactions. We do not hedge all foreign currency exposure. Credit Risk AEP limits credit risk by accepting primarily investment grade counter parties. We also require cash deposits, letters of credit and affiliate guarantees as collateral from certain counter parties in case of adverse market conditions. QUANTITATIVE MARKET RISK We employ policies and procedures to identify, assess and manage market risk exposure. One procedure is the risk measurement model Value at Risk (VaR). VaR is used daily to measure and monitor trading risk. VaR operates on the variance - covariance method using historical prices to estimate volatility and correlation and assumes a 95% confidence level and a one-day holding period. The following table represents the high, average and low VaRs for AEP's electric and gas trading activities and electric trading for its registrant subsidiaries. VaR for AEP and Registrant Subsidiaries: Six Months Ended Year Ending June 30, December 31, 2001 2000 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $25 $14 $6 $32 $10 $1 APCo 6 2 1 6 2 - CPL 1 - - 4 1 - CSPCo 3 1 - 3 1 - I&M 4 1 - 4 1 - KPCo 1 1 - 1 - - OPCo 5 2 1 5 2 - PSO 1 - - 3 1 - SWEPCo 1 - - 4 1 - WTU - - - 1 - - Near term changes in commodity prices are not expected to materially affect our results of operations, cash flows and financial conditions. PART II. OTHER INFORMATION Item 1. Legal Proceedings. AEP On May 15, 2001, the Louisiana Department of Environmental Quality issued a Compliance Order and Notice of Potential Penalty to LIG's Plaquemine Gas Processing Plant alleging violations of regulations and finding certain deficiencies with respect to the Risk Management Plan developed for the plant. Reference is made to pages 28 and 29 of the Annual Report on Form 10-K for the year ended December 31, 2000 for a discussion of hazardous air pollutants. On July 26, 2001, upon motion by Federal EPA, the U.S. Court of Appeals for the District of Columbia Circuit dismissed the petition for review filed by utility industry groups in February 2001 relating to Federal EPA's action classifying coal-fired electric generating units as "major sources" of hazardous air pollutants. AEP and SWEPCo On May 22, 2001, Federal EPA, Region 6, issued Findings of Violation and an Order for Compliance to SWEPCo's Wilkes Power Plant alleging violations of waste water discharge permit limits and directing SWEPCo to undertake corrective action. Item 4. Submission of Matters to a Vote of Security Holders. --------------------------------------------------- AEP The annual meeting of shareholders was held in Corpus Christi, Texas on April 25, 2001. 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 fourteen directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director received the votes of shareholders as follows:
Number of Shares Number of Nominee Voted For Votes Withheld E. R. Brooks 262,469,347 3,811,294 Donald M. Carlton 262,727,287 3,553,354 John P. DesBarres 262,695,391 3,585,250 E. Linn Draper, Jr. 262,682,299 3,598,342 Robert W. Fri 262,558,070 3,722,571 William R. Howell 215,949,995 50,330,646 Lester A. Hudson, Jr. 262,626,424 3,654,217 Leonard J. Kujawa 262,546,000 3,734,641 James L. Powell 257,694,138 8,586,503 Richard L. Sandor 262,658,024 3,622,617 Thomas V. Shockley, III 262,622,071 3,658,570 Donald G. Smith 262,633,432 3,647,209 Linda Gillespie Stuntz 262,613,798 3,666,843 Kathryn D. Sullivan 262,429,116 3,851,525 2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as independent auditors of AEP for the year 2001. The proposal was approved by a vote of the shareholders as follows: Votes FOR 262,196,889 Votes AGAINST 2,151,465 Votes ABSTAINED 1,932,287 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 24, 2001 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 withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena No other business was transacted at the meeting. CPL Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 12, 2001, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena I&M Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 24, 2001, the following thirteen persons were elected directors to hold office for one year or until their successors are elected and qualify: Karl G. Boyd Thomas V. Shockley, III E. Linn Draper, Jr. Jackie S. Siefker Henry W. Fayne David B. Synowiec Marc E. Lewis Susan Tomasky William J. Lhota J. H. Vipperman Susanne M. Moorman W. E. Walters John R. Sampson OPCo The annual meeting of shareholders was held on May 1, 2001 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,473 votes were cast FOR each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena No other business was transacted at the meeting. SWEPCo Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 11, 2001, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky William J. Lhota J. H. Vipperman Armando A. Pena Item 5. Other Information. AEP and APCo Reference is made to pages 17 and 18 of the Annual Report on Form 10-K for the year ended December 31, 2000 for a discussion of APCo's proposed transmission facilities. On May 31, 2001, the Virginia SCC issued an order approving the Wyoming-Jacksons Ferry Project. On August 6, 2001, the U.S. Forest Service published in the Federal Register a Notice of Intent to prepare a Supplemental Draft Environmental Impact Statement (SDEIS). The Forest Service has scheduled three public meetings in August 2001 in the Virginia area to be crossed by the route to Jacksons Ferry. The Forest Service expects to file the SDEIS with Federal EPA for public review by April 2002. Following public comment, the Forest Service expects to file the final EIS with Federal EPA in October 2002 and then issue a Record of Decision. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. (b) Reports on Form 8-K: Companies Reporting Date of Report Item Reported AEP April 24, 2001 Item 7. Financial Statements and Exhibits AEP May 3, 2001 Item 7. Financial Statements and Exhibits AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU No reports on Form 8-K were filed during the quarter ended June 30, 2001. Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The 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. By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto --------------------------- ----------------------------------- Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto --------------------------- ----------------------------------- Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer Date: August 10, 2001