10-Q 1 x10q1q03.txt 10Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Quarterly Period Ended MARCH 31, 2003 OR [ ] 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) 0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833 0-346 AEP TEXAS CENTRAL COMPANY (A Texas Corporation) 74-0550600 0-340 AEP TEXAS NORTH COMPANY (A Texas Corporation) 75-0646790 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203 1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455 1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775 1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000 0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895 (An Oklahoma Corporation) 1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455 (A Delaware Corporation) All Registrants 1 Riverside Plaza, Columbus, Ohio 43215-2373 Telephone (614) 223-1000 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 Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are accelerated filers (as defined in Rule 12b-2 of the Exchange Act). Yes No X AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma 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. The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at April 30, 2003 was 394,993,420.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended March 31, 2003 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-3 Consolidated Financial Statements A-4 - A-8 AEP Generating Company: Management's Narrative Analysis of Results of Operations B-1 - B-2 Financial Statements B-3 - B-6 AEP Texas Central Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations C-1 - C-4 Consolidated Financial Statements C-5 - C-9 AEP Texas North Company: Management's Narrative Analysis of Results of Operations D-1 - D-3 Financial Statements D-4 - D-8 Appalachian Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations E-1 - E-3 Consolidated Financial Statements E-4 - E-8 Columbus Southern Power Company and Subsidiaries: Management's Narrative Analysis of Results of Operations F-1 - F-2 Consolidated Financial Statements F-3 - F-7 Indiana Michigan Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations G-1 - G-3 Consolidated Financial Statements G-4 - G-8 Kentucky Power Company: Management's Narrative Analysis of Results of Operations H-1 - H-2 Financial Statements H-3 - H-7 Ohio Power Company: Management's Discussion and Analysis of Results of Operations I-1 - I-3 Financial Statements I-4 - I-8 Public Service Company of Oklahoma and Subsidiary: Management's Narrative Analysis of Results of Operations J-1 - J-2 Consolidated Financial Statements J-3 - J-7 Southwestern Electric Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations K-1 - K-2 Consolidated Financial Statements K-3 - K-7 Combined Notes to Financial Statements L-1 - L-33 Item 2. Registrants' Combined Management's Discussion and Analysis of Financial Condition, Accounting Policies and Other Matters M-1 - M-14 Item 3. Quantitative and Qualitative Disclosures About Risk Management Activities N-1 - N-13 Item 4. Controls and Procedures O-1 Part II. OTHER INFORMATION Item 5. Other Information P-1 Item 6. Exhibits and Reports on Form 8-K P-1 (a) Exhibits Exhibit 12 Exhibit 99.1 Exhibit 99.2 (b) Reports on Form 8-K SIGNATURES Q-1 CERTIFICATIONS R-1 - R-4 This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
iii 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 consolidated subsidiaries. AEP Credit.........................AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and non-affiliated domestic electric utility companies. AEP East 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 companies.................PSO, SWEPCo, TCC and TNC. 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. 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. CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary. CSW............................... Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.). 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. DOE................................United States Department of Energy. ECOM...............................Excess Cost Over Market. EITF...............................The Financial Accounting Standards Board's Emerging Issues Task Force. EITF 02-3..........................Recognition and Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and 00-17. ERCOT..............................The Electric Reliability Council of Texas. FASB...............................Financial Accounting Standards Board. Federal EPA........................United States Environmental Protection Agency. FERC...............................Federal Energy Regulatory Commission. GAAP...............................Generally Accepted Accounting Principles. I&M................................Indiana Michigan Power Company, an AEP electric utility subsidiary. ICR................................Interchange Cost Reconstruction. IRS................................Internal Revenue Service. IURC...............................Indiana Utility Regulatory Commission. ISO................................Independent System Operator. 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. MISO...............................Midwest Independent System Operator (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. MTM................................Mark-to-Market. MW.................................Megawatt. MWH................................Megawatthour. NOx................................Nitrogen oxide. NOx Rule...........................A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operate. NRC................................Nuclear Regulatory Commission. OCC................................The Corporation Commission of the State of Oklahoma. Ohio Act...........................The Ohio Electric Restructuring Act of 1999. Ohio EPA...........................Ohio Environmental Protection Agency. OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary. PJM................................Pennsylvania - New Jersey - Maryland regional transmission organization. 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, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. REP................................Retail Electric Provider. 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. SFAS 133...........................Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS 143...........................Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. SNF................................Spent Nuclear Fuel. SPP................................Southwest Power Pool. STP................................South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central Company, an AEP electric utility subsidiary. STPNOC.............................STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including TCC. SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary. TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central Power and Light Company (CPL)]. Texas Legislation..................Legislation enacted in 1999 to restructure the electric utility industry in Texas. TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas Utilities Company (WTU)]. TVA ...............................Tennessee Valley Authority. U.K................................The United Kingdom. VaR................................Value at Risk, a method to quantify risk exposure. Virginia SCC.......................Virginia State Corporation Commission. WVPSC..............................Public Service Commission of West Virginia. WPCo...............................Wheeling Power Company, an AEP electric distribution subsidiary. 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.
iv FORWARD LOOKING INFORMATION These reports made by AEP and its registrant subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and its registrant 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 service territories. o The ability to recover stranded costs in connection with possible/proposed deregulation. o New legislation and government regulation. o Oversight and/or investigation of the energy sector or its participants. o Our ability to successfully control costs. o The success of acquiring new business ventures and disposing of existing investments that no longer match our corporate profile. o International and country-specific developments affecting foreign investments including the disposition of any current foreign investments and potential additional foreign investments. o The economic climate and growth in our service territory and changes in market demand and demographic patterns. o Inflationary trends. o Electricity and gas market prices. o Interest rates. o Liquidity in the banking, capital and wholesale power markets. o Actions of rating agencies. o Changes in technology, including the increased use of distributed generation within our transmission and distribution service territory. o Other risks and unforeseen events, including wars, the effects of terrorism, embargoes and other catastrophic events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 American Electric Power Company, Inc.'s principal operating business segments and their major activities are: Utility Operations oDomestic generation of electricity for sale to retail and wholesale customers oDomestic electricity transmission and distribution Investments - Gas Operations oGas pipeline and storage services Investments - UK Operations oInternational generation of electricity for sale to wholesale customers Investments - Other oCoal mining, bulk commodity barging operations and other energy supply businesses o Results of Operations Net Income of $440 million or $1.24 per share in the first quarter of 2003 included $193 million of Income from Cumulative Effect of Accounting Changes (see Note 3). Income Before Discontinued Operations and Cumulative Effect increased $97 million or 61% due to improved earnings from system sales resulting from the interactions of plant availability, the colder winter weather and higher margins. Changes in Revenues AEP's total revenue increased 36% in the first quarter of 2003. The following table shows the components of revenue. Increase (Decrease) (in millions) % REVENUES: Electric Generation $ 441 31 Electric Transmission and Distribution 74 9 Gas Pipeline and Storage 669 155 Investments ( 96) (32) TOTAL REVENUES $ 1,088 36 The increase in revenues was primarily due to higher levels of Electric Generation and Electric Transmission and Distribution resulting from plant availability and the colder winter weather as well as the higher revenue from Gas Pipeline and Storage sales resulting primarily from higher prices. Heating degree days were up 20% which resulted in higher residential KWH sales of 4%. System sales volume increased 10% to 7,681 gigawatt hours. Higher gas prices were caused by the decreasing availability of gas. Fuel inventories at gas storage facilities were reduced to low levels reflecting the colder winter weather compared to 2002. Investment revenues decreased 32% due to the completed construction of a gas-fired plant for a third party in the summer of 2002 and a reduction in U.K. operating margins due to market conditions. Changes in Expenses Increase (Decrease) (in millions) % EXPENSES: Fuel for Electric Generation $ 39 6 Purchased Electricity for Resale 176 N.M. Purchased Gas for Resale 795 225 Maintenance and Other Operation (43) (4) Depreciation and Amortization (17) (5) Taxes Other Than Income Taxes (3) (2) TOTAL OPERATING EXPENSES $947 37 N.M. = Not Meaningful The increase in Fuel for Electric Generation includes the effect of an increase in AEP's domestic net generation of 6% and higher generation output of 31% in the U.K. operation. The increase in Purchased Electricity for Resale expense was primarily attributable to an increase in MWH purchased to meet the demand. Purchased Gas for Resale increased due primarily to higher market prices. Maintenance and Other Operation expense decreased primarily due to the effect of material and labor costs related to the construction of a gas-fired plant for a third party that was completed in 2002. Project fees for the construction of the gas-fired plant for a third party were recognized in revenues on a percentage of completion method, consequently, the decrease in expense for material and labor cost does not affect net income. In addition, payroll expense decreased due in part to personnel reductions in late 2002. These decreases were partially offset by increases in U.K. operational expenses, pension and postretirement benefits expense, accretion expense related to asset retirement obligations (ARO) SFAS 143 (see Note 2 and explanation of decrease in Depreciation and Amortization expense below) and nuclear refueling outage amortization expenses. The decrease in Depreciation and Amortization expense is primarily due to the adoption of SFAS 143 for certain subsidiary utility companies effective January 1, 2003. Effective January 1, 2003 the generation depreciation rate for certain non-regulated jurisdictions was reduced to exclude the non-ARO removal cost portion that was included in the depreciation rate. In addition, certain amortization related to nuclear decommissioning costs was reclassified as ARO accretion expense which is included in Maintenance and Other Operations expense. Additionally, APCo reduced its Depreciation and Amortization expense related to the amortization of generation related regulatory assets due to the return to SFAS 71 regulatory accounting for the West Virginia jurisdiction (see Note 6 for further discussion of the return to SFAS 71 regulatory accounting). Other Income and Other Expenses Other Income includes non-operating revenue including non-utility revenue associated with energy related projects for customers, equity earnings of non-consolidated subsidiaries, a gain on the sale of our customer care operations in Texas, and interest and miscellaneous income. Other Expenses includes non-utility expenses associated with energy related projects for customers, losses on dispositions of property, donations and various other non-operating and miscellaneous expenses. Other Income increased mainly due to a gain of $39 million on the sale of our customer care operations in Texas and an increase in miscellaneous income. In the first quarter of 2003, AEP sold Mutual Energy Service Company, a customer care operation which was created to serve retail customers in the deregulated Texas market, to Alliance Data Systems. This sale continues our exit of the retail electric supply business in Texas and refocuses our resources on wholesale generation and power supply markets. Miscellaneous income increased due to additional contracts for the staffing of nonassociated companies' outages. Other Expenses increased due to increased non-utility expenses associated with energy related construction projects for third parties. Other Changes The increase in Income Taxes is due to an increase in pre-tax income and the tax effects of foreign operations. The increase in Interest was primarily due to an increase in outstanding balances of long-term debt in the first quarter of 2003. The increase was partially offset by a decrease in short-term debt interest expense due to a decrease in outstanding balances of short-term debt in the first quarter of 2003. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3).
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except per-share amounts) (UNAUDITED) Three Months Ended March 31, 2003 2002 REVENUES: Electric Generation $1,863 $ 1,422 Electric Transmission and Distribution 910 836 Gas Pipeline and Storage 1,102 433 Investments 205 301 TOTAL REVENUES 4,080 2,992 EXPENSES: Fuel for Electric Generation 660 621 Purchased Electricity for Resale 205 29 Purchased Gas for Resale 1,149 354 Maintenance and Other Operation 963 1,006 Depreciation and Amortization 315 332 Taxes Other Than Income Taxes 188 191 TOTAL EXPENSES 3,480 2,533 OPERATING INCOME 600 459 OTHER INCOME 118 12 OTHER EXPENSES 45 20 LESS: INTEREST 205 195 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 3 2 MINORITY INTEREST IN FINANCE SUBSIDIARY 9 9 INCOME BEFORE INCOME TAXES 456 245 INCOME TAXES 200 86 INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT 256 159 DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX) (9) 22 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX): Goodwill and Other Intangible Assets - (350) Accounting for Risk Management Contracts (49) - Asset Retirement Obligation 242 - NET INCOME (LOSS) $ 440 $ (169) AVERAGE NUMBER OF SHARES OUTSTANDING 356 322 EARNINGS (LOSS) PER SHARE: Income Before Discontinued Operations and Cumulative Effect of Accounting Changes $ 0.72 $ 0.49 Discontinued Operations (0.02) 0.07 Cumulative Effect of Accounting Changes 0.54 (1.08) Earnings (Loss) Per Share (Basic and Diluted) $ 1.24 $(0.52) CASH DIVIDENDS PAID PER SHARE $ 0.60 $ 0.60 See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in millions) ASSETS CURRENT ASSETS: Cash and Cash Equivalents $ 1,764 $ 1,213 Accounts Receivable (net) 2,572 1,740 Fuel, Materials and Supplies 966 1,166 Risk Management Assets 1,105 1,012 Other 1,037 935 TOTAL CURRENT ASSETS 7,444 6,066 PROPERTY, PLANT AND EQUIPMENT: Electric: Production 17,239 17,031 Transmission 5,909 5,882 Distribution 9,585 9,573 Other (including gas, coal mining and nuclear fuel) 3,911 3,965 Construction Work in Progress 1,510 1,406 Total Property, Plant and Equipment 38,154 37,857 Accumulated Depreciation and Amortization 15,826 16,173 NET PROPERTY, PLANT AND EQUIPMENT 22,328 21,684 REGULATORY ASSETS 2,669 2,688 SECURITIZED TRANSITION ASSETS 726 735 INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS 291 283 GOODWILL 396 396 ASSETS HELD FOR SALE 280 292 LONG-TERM RISK MANAGEMENT ASSETS 812 819 OTHER ASSETS 1,955 1,783 TOTAL ASSETS $36,901 $34,746 See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,930 $ 2,030 Short-term Debt 239 3,164 Long-term Debt Due Within One Year 1,696 1,633 Risk Management Liabilities 1,268 1,113 Other 2,020 1,802 TOTAL CURRENT LIABILITIES 8,153 9,742 LONG-TERM DEBT 10,436 8,487 EQUITY UNIT SENIOR NOTES 376 376 LONG-TERM RISK MANAGEMENT LIABILITIES 543 481 DEFERRED INCOME TAXES 4,037 3,916 DEFERRED INVESTMENT TAX CREDITS 448 455 DEFERRED CREDITS AND REGULATORY LIABILITIES 830 770 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 183 185 LIABILITIES HELD FOR SALE 161 142 OTHER NONCURRENT LIABILITIES 2,073 1,903 COMMITMENTS AND CONTINGENCIES (Note 7) CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 321 321 MINORITY INTEREST IN FINANCE SUBSIDIARY 759 759 CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 144 145 COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50: 2003 2002 Shares Authorized.. . 600,000,000 600,000,000 Shares Issued. . . . .403,993,412 347,835,212 (8,999,992 shares were held in treasury at March 31, 2003 and December 31, 2002) 2,626 2,261 Paid-in Capital 4,175 3,413 Accumulated Other Comprehensive Income (Loss) (602) (609) Retained Earnings 2,238 1,999 TOTAL COMMON SHAREHOLDERS' EQUITY 8,437 7,064 TOTAL LIABILITIES AND SHAREHOLDERS'EQUITY $36,901 $34,746 See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in millions) OPERATING ACTIVITIES: Net Income (Loss) $ 440 $(169) Plus: Discontinued Operations 9 (22) Net Income from Continuing Operations 449 (191) Adjustments for Noncash Items: Depreciation and Amortization 315 336 Deferred Income Taxes 27 (59) Deferred Investment Tax Credits (7) (9) Cumulative Effect of Accounting Changes (193) 350 (Gain)/Loss on Sale of Assets (36) - Mark to Market of Risk Management Contracts 69 158 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (834) (796) Fuel, Materials and Supplies 165 101 Accrued Utility Revenues (48) (51) Prepayments and Other (74) (49) Accounts Payable 905 43 Taxes Accrued 196 12 Interest Accrued 29 94 Rent Accrued - Rockport Plant Unit 2 37 37 Over/Under Fuel Recovery 74 (31) Change in Other Assets (209) (341) Change in Other Liabilities (90) 376 Net Cash Flows From (Used For) Operating Activities 775 (20) INVESTING ACTIVITIES: Construction Expenditures (324) (300) Proceeds from Sale of Assets 35 - Other - (32) Net Cash Flows Used For Investing Activities (289) (332) FINANCING ACTIVITIES: Issuance of Common Stock 1,177 14 Issuance of Long-term Debt 2,525 872 Change in Short-term Debt (net) (2,925) (49) Retirement of Long-term Debt (509) (295) Dividends Paid on Common Stock (203) (193) Net Cash Flows From Financing Activities 65 349 Effect of Exchange Rate Change on Cash - (14) Net Increase (Decrease) in Cash and Cash Equivalents 551 (17) Cash and Cash Equivalents at Beginning of Period 1,213 224 Cash and Cash Equivalents at End of Period $1,764 $ 207 Net Decrease in Cash and Cash Equivalents from Discontinued Operations $ (3) $ (9) Cash and Cash Equivalents from Discontinued Operations - Beginning of Period 8 108 Cash and Cash Equivalents from Discontinued Operations - End of Period $ 5 $ 99 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $177 million and $126 million in 2003 and 2002, respectively. There was no cash paid for income taxes in 2003. Cash paid for income taxes in 2002 was $94 million. See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (in millions) Accumulated Other Common Paid-in Retained Comprehensive Stock Capital Earnings Income (Loss) Total JANUARY 1, 2002 $2,153 $2,906 $3,296 $(126) $8,229 Issuance of Common Stock 3 3 Common Stock Dividends (193) (193) Other 6 4 10 8,049 Comprehensive Income (Loss): Other Comprehensive Income (Loss), Net of Taxes Foreign Currency Translation Adjustments (6) (6) Unrealized Losses on Cash Flow Hedges (38) (38) Net Loss (169) (169) Total Comprehensive Income (Loss) (213) MARCH 31, 2002 $2,156 $2,912 $2,938 $(170) $7,836 JANUARY 1, 2003 $2,261 $3,413 $1,999 $(609) $7,064 Issuance of Common Stock 365 812 1,177 Common Stock Dividends (203) (203) Common Stock Expense (35) (35) Other (15) 2 (13) 7,990 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes Foreign Currency Translation Adjustments 13 13 Unrealized Gains on Securities 1 1 Unrealized Losses on Cash Flow Hedges (22) (22) Minimum Pension Liability 15 15 Net Income 440 440 Total Comprehensive Income 447 MARCH 31, 2003 $2,626 $4,175 $2,238 $(602) $8,437 See Notes to Consolidated Financial Statements beginning on page L-1.
AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 AEGCo is engaged in the generation and wholesale sale of electric power to two affiliates under long-term agreements. 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 net of temporary cash investments. Results of Operations Net Income declined $97 thousand or 5% for the first quarter of 2003 as a result of terms in the unit power agreements which limits recovery of return on capital related to operating and in-service ratios of the Rockport Plant calculated and adjusted monthly. Changes in Operating Revenues An increase in Operating Revenues of $10.6 million resulted from an increase in recoverable expenses, primarily fuel, as generation increased 50% due to an increase in the Rockport Plant's availability during 2003. Outages for planned maintenance at both units decreased the Rockport Plant's generation in 2002. Changes in Operating Expenses Operating expenses increased 22% as follows: Increase (Decrease) (in thousands) % Fuel for Electric Generation $12,897 74 Rent - Rockport Plant Unit 2 - - Other Operation (673) (21) Maintenance (1,325) (45) Depreciation (12) - Taxes Other Than Income Taxes (262) (25) Income Taxes (156) (24) Total Operating Expenses $10,469 22 Fuel for Electric Generation expense increased due to a 50% increase in generation in 2003. Planned maintenance outages during the first quarter of 2002 reduced the Rockport Plant's availability and generation in 2002. The decreases in Other Operation and Maintenance expenses are primarily due to higher costs incurred during the 2002 plant outages. The decrease in Taxes Other Than Income Taxes reflects a decline in the accrual of real and personal property tax for Indiana for the Rockport Plant, reflecting a favorable change in the law effective March 2002. Income Taxes attributable to operations decreased primarily due to a decrease in pre-tax operating income and a decrease in accrued state income. Other Changes The increase in Nonoperating Expense reflects additional expenses related to a construction project.
AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES $60,428 $49,875 OPERATING EXPENSES: Fuel for Electric Generation 30,397 17,500 Rent - Rockport Plant Unit 2 17,071 17,071 Other Operation 2,549 3,222 Maintenance 1,651 2,976 Depreciation 5,621 5,633 Taxes Other Than Income Taxes 791 1,053 Income Taxes 497 653 TOTAL OPERATING EXPENSES 58,577 48,108 OPERATING INCOME 1,851 1,767 NONOPERATING INCOME 2 2 NONOPERATING EXPENSES 217 12 NONOPERATING INCOME TAX CREDITS 894 832 INTEREST CHARGES 734 696 NET INCOME $ 1,796 $ 1,893 STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) BALANCE AT BEGINNING OF PERIOD $18,163 $13,761 NET INCOME 1,796 1,893 CASH DIVIDENDS DECLARED 1,171 1,050 BALANCE AT END OF PERIOD $18,788 $14,604 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) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $638,481 $637,095 General 4,643 4,728 Construction Work in Progress 10,707 10,390 Total Electric Utility Plant 653,831 652,213 Accumulated Depreciation 364,316 358,174 NET ELECTRIC UTILITY PLANT 289,515 294,039 OTHER PROPERTY AND INVESTMENTS 119 119 CURRENT ASSETS: Accounts Receivable - Affiliated Companies 21,583 18,454 Fuel 18,005 20,260 Materials and Supplies 4,859 4,913 Prepayments 73 - TOTAL CURRENT ASSETS 44,520 43,627 REGULATORY ASSETS 5,701 4,970 DEFERRED CHARGES 9,297 6,974 TOTAL ASSETS $349,152 $349,729 See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 18,788 18,163 Total Common Shareholder's Equity 43,222 42,597 Long-term Debt 44,804 44,802 TOTAL CAPITALIZATION 88,026 87,399 OTHER NONCURRENT LIABILITIES 1,333 301 CURRENT LIABILITIES: Advances from Affiliates 9,650 28,034 Accounts Payable: General - 26 Affiliated Companies 12,585 15,907 Taxes Accrued 7,294 2,327 Rent Accrued - Rockport Plant Unit 2 23,427 4,963 Other 633 1,111 TOTAL CURRENT LIABILITIES 53,589 52,368 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 109,654 111,046 REGULATORY LIABILITIES: Deferred Investment Tax Credit 52,108 52,943 Amounts Due to Customers for Income Taxes 16,143 16,670 TOTAL REGULATORY LIABILITIES 68,251 69,613 DEFERRED INCOME TAXES 28,299 29,002 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $349,152 $349,729 See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $ 1,796 $ 1,893 Adjustment for Noncash Items: Depreciation 5,621 5,633 Deferred Income Taxes (1,230) (1,470) Deferred Investment Tax Credits (835) (835) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (1,392) (1,392) Deferred Property Taxes (2,329) (2,693) Changes in Certain Current Assets and Liabilities: Accounts Receivable (3,129) 1,337 Fuel, Materials and Supplies 2,309 (1,214) Accounts Payable (3,348) (1,221) Taxes Accrued 4,967 5,529 Rent Accrued - Rockport Plant Unit 2 18,464 18,464 Change in Other Assets (1,021) 586 Change in Other Liabilities 554 (545) Net Cash Flow From Operating Activities 20,427 24,072 INVESTING ACTIVITIES - Construction Expenditures (872) (4,282) FINANCING ACTIVITIES: Change in Advances from Affiliates (net) (18,384) (15,511) Dividends Paid (1,171) (1,050) Net Cash Flows Used For Financing Activities (19,555) (16,561) Net Increase in Cash and Cash Equivalents - 3,229 Cash and Cash Equivalents at Beginning of Period - 983 Cash and Cash Equivalents at End of Period $ - $ 4,212 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $1,123,000 and $1,108,000 and for income taxes was $(384,000) and $176,000 in 2003 and 2002, respectively. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 AEP Texas Central Company (TCC), formerly known as Central Power and Light Company (CPL), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in southern Texas. TCC sells electric power to utilities, municipalities, rural electric cooperatives and beginning in 2002 to retail electric providers (REPs) in Texas. Wholesale risk management activities are conducted on TCC's behalf by AEPSC. TCC, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TCC submitted a plan for separation that was subsequently approved by the PUCT. TCC functionally separated its generation from its transmission and distribution operations and AEP formed separate affiliated REPs, Mutual Energy CPL and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual Energy CPL provides default electric service to residential and small commercial customers (customers eligible for price-to-beat rates). AEP Texas Commercial & Industrial Retail Limited Partnership provides default electric service to large commercial and industrial customers not eligible for price- to-beat rates. Mutual Energy CPL, a separate legal entity that was an AEP subsidiary (not owned by or consolidated with TCC), was sold in December 2002. Since REPs are the electricity suppliers to retail customers in the ERCOT area, TCC sells its generation to the REPs and other market participants and provides transmission and distribution services to retail customers of the REPs in the TCC service territory. As a result of the provision of retail electric service by REPs, effective January 1, 2002, TCC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TCC's sales as further described below under "Results of Operations." In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who assumed the obligations of the affiliated REP including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002 sales to Mutual Energy CPL were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions with Mutual Energy CPL are classified as Electric Generation and delivery charges as Electric Transmission and Distribution. Results of Operations In 2003 Net Income increased $40 million or 164% driven by a $56 million ($36 million, net of tax) increase in revenues associated with recognition of stranded costs in Texas, and a $5.0 million ($3.2 million, net of tax) increase in profits on derivative contracts. Changes in Operating Revenues Increase (Decrease) (in millions) % Electric Generation $166.4 198 Electric Transmission and Distribution 124.9 346 Sales to AEP Affiliates (141.9) (89) Total Operating Revenues $149.4 54 In 2003, Electric Generation revenues increased due to the reclassification of energy revenues as a result of the sale of Mutual Energy CPL in December 2002, discussed above, and increased MWH sales at higher prices, and increased revenues from ERCOT of $77 million. These revenues were offset in part by a decrease in average electric rates, as 2002 included a transition period which included fuel revenue collections from retail customers; and a reduction of $27 million resulting from a provision for rate refund (see Note 5). Additionally, delivery charges provided to Mutual Energy CPL are classified as Sales to AEP Affiliates in 2002, whereas in 2003 they are classified as Electricity Transmission and Distribution revenue. Actual delivered MWHs increased in 2003. Revenues for 2003 include $56 million of revenue associated with recognition of stranded costs in Texas (see Note 6). Electric Transmission and Distribution revenue also included revenues received for securitized assets beginning in February 2002 and revenues from ERCOT for system management services. In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification of revenues as a result of the sale of Mutual Energy CPL in December 2002, discussed above. Changes in Operating Expenses Increase (Decrease) (in millions) % Fuel for Electric Generation $ 0.3 1 Fuel from Affiliates for Electric Generation 11.0 40 Purchased Electricity for Resale 68.1 N.M. Purchased Electricity from AEP Affiliates 3.6 46 Other Operation 3.4 5 Maintenance 5.2 47 Depreciation and Amortization 2.2 5 Taxes Other Than Income Taxes (4.9) (18) Income Taxes 24.0 229 Total Operating Expenses $112.9 51 N.M. = Not meaningful The increase in total fuel expense was due to an increase in the average unit cost of fuel offset in part by decreased MWH generation. The increase in the average unit cost was due to gas generation as the per unit cost of gas more than doubled from 2002 to 2003, while the actual gas MWH generation decreased due to the mothballing of several gas plants in late 2002. Nuclear generation decreased due to outages at the STP nuclear plant during the first quarter of 2003. See Note 7 for further information regarding the outage at the STP nuclear plant. The increase in total purchased electricity expense in 2003 was mainly due to increased MWHs purchased as a result of the mothballed plants, the STP outage and higher open market purchase prices. Other Operation expense increased due primarily to the accretion expense for nuclear decommissioning associated with the adoption of SFAS 143 (see Note 2). A corresponding offsetting decrease in Depreciation and Amortization is also a result of the adoption of SFAS 143. See Depreciation and Amortization explanation below. Maintenance expense increased due to an unscheduled outage at one of the nuclear units and a refueling outage at the other nuclear unit (see Note 7). The increase in Depreciation and Amortization is attributable to the absence in 2003 of an excess earnings favorable true-up adjustment offset in part by reduced expense attributable to the adoption of SFAS 143, the amortization of regulatory assets associated with the securitization during the first quarter of 2002 and decreased depreciation due to several plants mothballed during late 2002. The decrease in Taxes Other Than Income Taxes resulted primarily from decreased gross receipts tax, due to deregulation. The increase in Income Taxes is due to an increase in pre-tax income. Other Changes Nonoperating Income increased as a result of premium payments on derivative contracts, offset in part by decreased non-utility revenue associated with energy related construction projects for third parties. Nonoperating Expenses also decreased due to lower expenses associated with energy related construction projects for third parties. Cumulative Effect of Accounting Change This amount represents the one-time after-tax effect of the application of EITF 02-3 (see Notes 2 and 3).
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $250,377 $ 83,988 Electric Transmission and Distribution 161,006 36,060 Sales to AEP Affiliates 16,975 158,862 TOTAL OPERATING REVENUES 428,358 278,910 OPERATING EXPENSES: Fuel for Electric Generation 27,339 26,989 Fuel from Affiliates for Electric Generation 38,289 27,339 Purchased Electricity for Resale 72,122 4,012 Purchased Electricity from AEP Affiliates 11,562 7,927 Other Operation 69,402 65,986 Maintenance 16,099 10,959 Depreciation and Amortization 44,073 41,847 Taxes Other Than Income Taxes 22,979 27,922 Income Taxes 34,483 10,484 TOTAL OPERATING EXPENSES 336,348 223,465 OPERATING INCOME 92,010 55,445 NONOPERATING INCOME 10,162 9,531 NONOPERATING EXPENSES 5,195 9,387 NONOPERATING INCOME TAX EXPENSE 558 133 INTEREST CHARGES 31,982 31,011 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 64,437 24,445 CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) 122 - NET INCOME 64,559 24,445 PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60 EARNINGS APPLICABLE TO COMMON STOCK $ 64,499 $ 24,385 The common stock of TCC is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Common Paid-in Retained Comprehensive Stock Capital Earnings Income (Loss) Total (in thousands) JANUARY 1, 2002 $168,888 $405,015 $826,197 $ - $1,400,100 Redemption of Common Stock (113,596) (272,409) (386,005) Common Stock Dividends (38,502) (38,502) Preferred Stock Dividends (60) (60) 975,533 Comprehensive Income: Other Comprehensive Income - - Net Income 24,445 24,445 Total Comprehensive Income 24,445 MARCH 31, 2002 $ 55,292 $132,606 $812,080 $ - $ 999,978 JANUARY 1, 2003 $ 55,292 $132,606 $986,396 $(73,160) $1,101,134 Common Stock Dividends (30,201) (30,201) Preferred Stock Dividends (60) (60) 1,070,873 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (1,018) (1,018) Net Income 64,559 64,559 Total Comprehensive Income 63,541 MARCH 31, 2003 $ 55,292 $132,606 $1,020,694 $(74,178) $1,134,414 See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, December 31, 2003 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,977,890 $2,903,942 Transmission 715,195 698,964 Distribution 1,305,884 1,296,731 General 260,834 258,386 Construction Work in Progress 180,178 200,947 Nuclear Fuel 270,521 266,766 Total Electric Utility Plant 5,710,502 5,625,736 Accumulated Depreciation and Amortization 2,356,530 2,405,492 NET ELECTRIC UTILITY PLANT 3,353,972 3,220,244 OTHER PROPERTY AND INVESTMENTS 4,219 3,977 SECURITIZED TRANSITION ASSETS 725,597 734,591 LONG-TERM RISK MANAGEMENT ASSETS 11,547 4,392 CURRENT ASSETS: Cash and Cash Equivalents 32,796 85,420 Advances to Affiliates 18,346 - Accounts Receivable: General 190,905 113,543 Affiliated Companies 110,291 121,324 Allowance for Uncollectible Accounts (230) (346) Fuel Inventory 22,103 32,563 Materials and Supplies 47,220 51,593 Accrued Utility Revenues 27,540 27,150 Risk Management Assets 21,395 22,493 Prepayments and Other Current Assets 4,769 2,133 TOTAL CURRENT ASSETS 475,135 455,873 REGULATORY ASSETS 570,058 458,552 REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION 321,156 336,444 NUCLEAR DECOMMISSIONING TRUST FUND 97,128 98,474 DEFERRED CHARGES 88,896 43,891 TOTAL ASSETS $5,647,708 $5,356,438 See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, December 31, 2003 2002 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 12,000,000 Shares Outstanding - 2,211,678 Shares $ 55,292 $ 55,292 Paid-in Capital 132,606 132,606 Accumulated Other Comprehensive Income (Loss) (74,178) (73,160) Retained Earnings 1,020,694 986,396 Total Common Shareholder's Equity 1,134,414 1,101,134 Preferred Stock 5,942 5,942 CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of TCC 136,250 136,250 Long-term Debt 1,980,640 1,209,434 TOTAL CAPITALIZATION 3,257,246 2,452,760 OTHER NONCURRENT LIABILITIES 309,028 74,572 CURRENT LIABILITIES: Short-term Debt - Affiliates - 650,000 Long-term Debt Due Within One Year 209,705 229,131 Advances from Affiliates (net) - 126,711 Accounts Payable - General 81,997 72,199 Accounts Payable - Affiliated Companies 65,725 36,242 Customer Deposits 1,803 666 Taxes Accrued 94,315 24,791 Interest Accrued 24,920 51,205 Risk Management Liabilities 28,334 19,811 Other 18,142 36,698 TOTAL CURRENT LIABILITIES 524,941 1,247,454 DEFERRED INCOME TAXES 1,239,961 1,261,252 DEFERRED INVESTMENT TAX CREDITS 116,384 117,686 LONG-TERM RISK MANAGEMENT LIABILITIES 5,824 1,713 REGULATORY LIABILITIES AND DEFERRED CREDITS 194,324 201,001 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $5,647,708 $5,356,438 See Notes to Financial Statements beginning on page L-1.
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $ 64,559 $ 24,445 Adjustments to Reconcile Net Income to Net Cash Flows From (Used For) Operating Activities: Depreciation and Amortization 44,073 41,847 Deferred Income Taxes (2,260) (8,083) Deferred Investment Tax Credits (1,302) (1,302) Cumulative Effect of Accounting Change (122) - Mark-to-Market of Risk Management Contracts 5,197 6,466 Changes in Certain Assets and Liabilities: Accounts Receivable (net) (66,445) (69,400) Fuel, Materials and Supplies 14,833 (1,359) Interest Accrued (26,285) 8,942 Accrued Utility Revenue (390) (4,458) Accounts Payable 39,281 (28,577) Taxes Accrued 69,524 17,767 Deferred Property Tax (31,590) (32,899) Change in Other Assets (51,108) (20,966) Change in Other Liabilities (15,185) (19,726) Net Cash Flows From (Used For) Operating Activities 42,780 (87,303) INVESTING ACTIVITIES: Construction Expenditures (21,851) (21,002) Other - - Net Cash Flows Used For Investing Activities (21,851) (21,002) FINANCING ACTIVITIES: Change in Short-term Debt Affiliated (Net) (650,000) - Issuance of Long-term Debt 800,000 796,613 Retirement of Long-term Debt (48,235) (149,998) Change in Advances to/from Affiliates (Net) (145,057) (115,447) Retirement of Common Stock - (386,004) Dividends Paid on Common Stock (30,201) (38,502) Dividends Paid on Cumulative Preferred Stock (60) (60) Net Cash Flows From (Used For) Financing Activities (73,553) 106,602 Net Decrease in Cash and Cash Equivalents (52,624) (1,703) Cash and Cash Equivalents at Beginning of Period 85,420 10,909 Cash and Cash Equivalents at End of Period $ 32,796 $ 9,206 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $55,483,000 and $18,505,000 and for income taxes was $(22,959,000) and $18,482,000 in 2003 and 2002, respectively. See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 AEP Texas North Company (TNC), formerly known as West Texas Utilities Company (WTU), is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. TNC sells electric power to utilities, municipalities, rural electric cooperatives and beginning in 2002 to retail electric providers (REPs) in Texas. Wholesale risk management activities are conducted on TNC's behalf by AEPSC. TNC, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the majority of its operations being in the ERCOT territory. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into an affiliated REP, a power generator, and a transmission and distribution utility. During the year 2000, TNC submitted a plan for separation that was subsequently approved by the PUCT. TNC functionally separated its generation from its transmission and distribution operations and AEP formed separate affiliated REPs, Mutual Energy WTU and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual Energy WTU provides default electric service to residential and small commercial customers (customers eligible for price-to-beat rates). AEP Texas Commercial & Industrial Retail Limited Partnership provides default electric service to large commercial and industrial customers not eligible for price- to-beat-rates. Mutual Energy WTU, a separate legal entity that was an AEP subsidiary (not owned by or consolidated with TNC), was sold in December 2002. Since REPs are the electricity suppliers to retail customers in the ERCOT area, TNC sells its generation to the REPs and other market participants and provides transmission and distribution services to retail customers of the REPs in the TNC service territory. As a result of the provision of retail electric service by REPs effective January 1, 2002, TNC no longer supplies electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a significant shift in TNC's sales as further described below under "Results of Operations." In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who assumed the obligations of the affiliated REP, including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002 sales to Mutual Energy WTU were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions with Mutual Energy WTU are classified as Electric Generation and delivery charges as Electric Transmission and Distribution. Results of Operations In 2003, Net Income increased $5.8 million or 146% primarily due to the cumulative effect of accounting changes and increased nonoperating results, offset by lower Operating Income. Changes in Operating Revenues Increase (Decrease) (in millions) % Electric Generation $ 41.9 109 Electric Transmission and Distribution 18.5 126 Sales to AEP Affiliates (47.8) (95) Total Operating Revenues $ 12.6 12 In 2003, Electric Generation revenues increased due to the reclassification of energy revenues as a result of the sale of Mutual Energy WTU in December 2002, discussed above, decreased MWH sales at higher prices and increased revenues from ERCOT of $17 million. These revenues were offset in part by a decrease in average electric rates, as 2002 included a transition period which included fuel revenue collections from retail customers; and a reduction of $13 million resulting from a provision for rate refund (see Note 5). The increase in Electric Transmission and Distribution is primarily due to delivery charges classified as Electric Transmission and Distribution in 2003, whereas in 2002 they were classified as Sales to AEP Affiliates. In addition, TNC had increased MWHs delivered in 2003 and increased revenues from ERCOT for system management services. In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification of energy revenues as a result of the sale of Mutual Energy WTU in December 2002, discussed above. Changes in Operating Expenses Increase (Decrease) (in millions) % Fuel for Electric Generation $ 2.7 32 Fuel from Affiliates for Electric Generation (10.1) (63) Purchased Electricity for Resale 18.3 280 Purchased Electricity from AEP Affiliates 7.7 66 Other Operation (3.6) (15) Maintenance (0.2) (5) Depreciation and Amortization (2.1) (18) Taxes Other Than Income Taxes (0.3) (4) Income Taxes 1.5 50 Total Operating Expenses $ 13.9 15 Net fuel for electric generation decreased due to lower MWHs generated, offset in part by an increase in the average per unit fuel cost. TNC used coal for 91% of its generation in 2003 since many of its gas plants were mothballed in late 2002. This higher use of coal helped lower the fuel costs in 2003. The increase in total Purchased Electricity expense in 2003 was mainly due to both increased MWHs purchased as a result of the mothballed plants and higher open market purchase prices. Other Operation expense decreased in 2003 due to lower uncollectible account expenses and lower administrative and general expenses. Depreciation and Amortization expense decreased due to the absence in 2003 of excess earnings expense adjustments under Texas Restructuring Legislation and the decrease in depreciation due to the mothballing of several power plants in late 2002. The increase in Income Tax Expense is primarily a result of an increase in pre-tax income. Other Changes Nonoperating Income and Nonoperating Expenses increased significantly as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties. Additionally, Nonoperating Income increased due to increased earnings on derivative contracts. Interest Charges declined primarily due to lower average borrowings in 2003 versus 2002. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to a one time after-tax impact of adopting SFAS 143 (see Notes 2 and 3).
AEP TEXAS NORTH COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $ 80,369 $ 38,437 Electric Transmission and Distribution 33,124 14,672 Sales to AEP Affiliates 2,769 50,517 TOTAL OPERATING REVENUES 116,262 103,626 OPERATING EXPENSES: Fuel for Electric Generation 11,461 8,714 Fuel from Affiliates for Electric Generation 6,085 16,266 Purchased Electricity for Resale 24,778 6,513 Purchased Electricity from AEP Affiliates 19,345 11,650 Other Operation 20,619 24,170 Maintenance 4,141 4,356 Depreciation and Amortization 9,532 11,569 Taxes Other Than Income Taxes 6,033 6,300 Income Tax Expense 4,403 2,943 TOTAL OPERATING EXPENSES 106,397 92,481 OPERATING INCOME 9,865 11,145 NONOPERATING INCOME (LOSS) 13,463 (1,488) NONOPERATING EXPENSES 11,559 1,372 NONOPERATING INCOME TAX EXPENSE (CREDIT) 339 (989) INTEREST CHARGES 4,665 5,282 NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 6,765 3,992 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 3,071 - NET INCOME 9,836 3,992 PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 EARNINGS APPLICABLE TO COMMON STOCK $ 9,810 $ 3,966 The common stock of TNC is wholly owned by AEP. See Note to Financial Statements beginning on Page L-1.
AEP TEXAS NORTH COMPANY STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $137,214 $2,351 $105,970 $ - $245,535 Common Stock Dividends (6,749) (6,749) Preferred Stock Dividends (26) (26) 238,760 Comprehensive Income: Other Comprehensive Income - - Net Income 3,992 3,992 Total Comprehensive Income 3,992 MARCH 31, 2002 $137,214 $2,351 $103,187 $ - $242,752 JANUARY 1, 2003 $137,214 $2,351 $71,942 $(30,763) $180,744 Common Stock Dividends (4,970) (4,970) Preferred Stock Dividends (26) (26) 175,748 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (421) (421) Unrealized Loss on Minimum Pension Liability (7) (7) Net Income 9,836 9,836 Total Comprehensive Income 9,408 MARCH 31, 2003 $137,214 $2,351 $ 76,782 $(31,191) $185,156 See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 354,117 $ 353,087 Transmission 255,343 254,483 Distribution 446,150 445,486 General 109,200 111,679 Construction Work in Progress 39,991 37,012 Total Electric Utility Plant 1,204,801 1,201,747 Accumulated Depreciation and Amortization 518,631 521,792 NET ELECTRIC UTILITY PLANT 686,170 679,955 OTHER PROPERTY AND INVESTMENTS 1,065 1,213 LONG-TERM RISK MANAGEMENT ASSETS 4,433 2,248 CURRENT ASSETS: Cash and Cash Equivalents 4,681 1,219 Advances to Affiliates 8,460 - Accounts Receivable: Customers 32,776 62,660 Affiliated Companies 37,796 43,632 Allowance for Uncollectible Accounts (4,728) (5,041) Fuel Inventory 8,916 12,677 Materials and Supplies 10,029 9,574 Accrued Utility Revenues 5,591 6,829 Risk Management Assets 3,411 4,130 Prepayments and Other 1,198 1,070 TOTAL CURRENT ASSETS 108,130 136,750 REGULATORY ASSETS 44,165 45,097 DEFERRED CHARGES 27,481 11,912 TOTAL ASSETS $ 871,444 $ 877,175 See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 2,351 2,351 Accumulated Other Comprehensive Income (Loss) (31,191) (30,763) Retained Earnings 76,782 71,942 Total Common Shareholder's Equity 185,156 180,744 Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,367 2,367 Long-term Debt 333,473 132,500 TOTAL CAPITZALIZATION 520,996 315,611 OTHER NONCURRENT LIABILITIES 41,859 28,861 CURRENT LIABILITIES: Short-term Debt - Affiliates - 125,000 Long-term Debt Due Within One Year 24,036 - Advances from Affiliates - 80,407 Accounts Payable - General 17,297 32,714 Accounts Payable - Affiliated Companies 37,152 76,217 Customer Deposits 320 117 Taxes Accrued 25,425 3,697 Interest Accrued 4,847 2,776 Risk Management Liabilities 4,761 3,801 Other 8,237 17,414 TOTAL CURRENT LIABILITIES 122,075 342,143 DEFERRED INCOME TAXES 113,465 117,521 DEFERRED INVESTMENT TAX CREDITS 21,130 21,510 LONG-TERM RISK MANAGEMENT LIABILITIES 2,300 557 REGULATORY LIABILITIES AND DEFERRED CREDITS 49,619 50,972 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $871,444 $877,175 See Notes to Financial Statements beginning on page L-1.
AEP TEXAS NORTH COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $ 9,836 $ 3,992 Adjustments to Reconcile Net Income to Net Cash Flows From (Used For) Operating Activities: Depreciation and Amortization 9,532 11,569 Deferred Income Taxes (5,666) (226) Deferred Investment Tax Credits (380) (318) Cumulative Effect of Accounting Changes (3,071) - Mark-to-Market of Risk Management Contracts 608 (213) Changes in Certain Assets and Liabilities: Accounts Receivable (net) 35,407 (28,456) Fuel, Materials and Supplies 3,306 (906) Accrued Utility Revenues 1,238 474 Accounts Payable (54,482) (1,423) Taxes Accrued 21,728 4,205 Fuel Recovery - (1,384) Deferred Property Taxes (10,868) (9,525) Change in Other Assets (4,593) (3,068) Change in Other Liabilities 4,927 (1,033) Net Cash Flows From (Used For) Operating Activities 7,522 (26,312) INVESTING ACTIVITIES: Construction Expenditures (10,197) (7,531) Other - - Net Cash Flows Used For Investing Activities (10,197) (7,531) FINANCING ACTIVITIES: Change in Short-term Debt (net) (125,000) - Issuance of Long-term Debt 225,000 - Change in Advances to/from Affiliates (net) (88,867) 38,720 Dividends Paid on Common Stock (4,970) (6,749) Dividends Paid on Cumulative Preferred Stock (26) (26) Net Cash Flows From Financing Activities 6,137 31,945 Net Increase (Decrease) in Cash and Cash Equivalents 3,462 (1,898) Cash and Cash Equivalents at Beginning of Period 1,219 2,454 Cash and Cash Equivalents at End of Period $ 4,681 $ 556 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $2,021,000 and $2,097,000 and for income taxes was $(8,873,000) and $(1,575,000) in 2003 and 2002, 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 FIRST QUARTER 2003 vs. FIRST QUARTER 2002 APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 925,000 retail customers in southwestern Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool, shares in the revenues and cost of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketing transactions. APCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of revenues and costs. Results of Operations Net Income of $156.4 million in the first quarter of 2003 included income from the Cumulative Effect of Accounting Changes of $77.3 million (see Note 3). Income Before Cumulative Effect of Accounting Changes increased $23.8 million or 43% primarily due to an improvement in earnings from retail and AEP Power Pool sales resulting from the interaction of plant availability, the colder winter weather and higher margins. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of marketing and activities conducted on its behalf by the AEP Power Pool. This increase was partially offset by a decline in Nonoperating Income. Changes in Operating Revenues The following analyzes the changes in operating revenues: (in millions) % Electric Generation $56.0 21 Electric Transmission and Distribution 3.5 2 Sales to AEP Affiliates 14.1 33 Total Operating Revenues $73.6 16 The increase in Operating Revenues was due primarily to higher Electric Generation sales and Sales to AEP Affiliates reflecting the more severe winter weather of 2003 and an increase in the volume of AEP Power Pool transactions. Heating degree days were up 18% over the prior year which resulted in an increase in Residential KWH sales of 16% as well as a 10% increase in total Retail sales. Additionally, APCo's relative share of the AEP Power Pool revenues (as well as expenses) for February and March, 2003 increased over the prior period as a result of APCo reaching a new peak demand in January 2003. Changes in Operating Expenses Operating expenses increased 11% in the first quarter of 2003 over the prior year. The changes in the components of operating expenses were: Increase (Decrease) (in millions) % Fuel for Electric Generation $12.4 12 Purchased Electricity for Resale 3.6 27 Purchased Electricity from AEP Affiliates 19.9 33 Other Operation (4.8) (7) Maintenance 6.9 27 Depreciation and Amortization (10.8) (23) Taxes Other Than Income Taxes 0.1 - Income Taxes 15.2 44 Total Operating Expenses $42.5 11 Fuel for Electric Generation increased in the first quarter of 2003 to meet the demand of the higher Electric Generation sales as KWH generated increased 7%. Purchased Electricity for Resale increased in the first quarter of 2003 as Retail KWH sales outpaced net generation. Purchased Electricity from AEP Affiliates increased due to higher charges resulting from the increased of all volume and the increase in APCo's share of the AEP Power Pool. The decline in Other Operation expense was primarily due to decreased employee-related expenses in the first quarter of 2003 reflecting the cost-saving effects of the Sustained Earnings Improvement Initiative (see Note 9). The increase in Maintenance expense is due to increased distribution line maintenance caused by severe winter storm damage in 2003 and increased plant maintenance primarily at the Sporn plant. Depreciation and Amortization expense decreased primarily due to reduced expense attributable to the adoption of SFAS 143. Effective January 1, 2003 the generation depreciation rate for APCo's non-regulated operations was reduced to exclude the non-ARO removal cost portion that was included in the depreciation rate. Additionally, APCo had reduced Depreciation and Amortization expense related to the amortization of generation related regulatory assets over the transition period due to the return to SFAS 71 accounting for the West Virginia jurisdiction (see Note 6 for further discussion of the return to SFAS 71 accounting). Amortization costs of transition regulatory assets had been accelerated since July 2000 in connection with the discontinuance of SFAS 71 in APCo's West Virginia jurisdiction. At that time net generation-related regulatory assets were transferred to the distribution portion of the business commensurate with their recovery through regulated rates. The increase in operating Income Taxes is due to an increase in pre-tax operating book income. Other Changes The decrease in Nonoperating Income is due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to reduce those types of transactions. The Nonoperating Income Tax Credit in 2003 reflects the tax benefits associated with the reduction in Nonoperating Income. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF of 02-3 (see Notes 2 and 3).
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $323,484 $267,475 Electric Transmission and Distribution 155,849 152,324 Sales to AEP Affiliates 56,895 42,806 TOTAL OPERATING REVENUES 536,228 462,605 OPERATING EXPENSES: Fuel for Electric Generation 119,865 107,490 Purchased Electricity for Resale 17,118 13,516 Purchased Electricity from AEP Affiliates 80,720 60,780 Other Operation 62,115 66,959 Maintenance 32,738 25,851 Depreciation and Amortization 36,008 46,772 Taxes Other Than Income Taxes 25,079 24,995 Income Taxes 49,901 34,688 TOTAL OPERATING EXPENSES 423,544 381,051 OPERATING INCOME 112,684 81,554 NONOPERATING INCOME (LOSS) (4,484) 5,084 NONOPERATING EXPENSES 3,674 3,645 NONOPERATING INCOME TAX EXPENSE (CREDIT) (3,733) 264 INTEREST CHARGES 29,106 27,388 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 79,153 55,341 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 77,257 - NET INCOME 156,410 55,341 PREFERRED STOCK DIVIDEND REQUIREMENTS 984 503 EARNINGS APPLICABLE TO COMMON STOCK $155,426 $ 54,838 The common stock of APCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $260,458 $715,786 $150,797 $ (340) $1,126,701 Common Stock Dividends (30,984) (30,984) Preferred Stock Dividends (361) (361) Capital Stock Expense 142 (142) - 1,095,356 Comprehensive Income: Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Power Hedges 143 143 Net Income 55,341 55,341 Total Comprehensive Income 55,484 MARCH 31, 2002 $260,458 $715,928 $174,651 $ (197) $1,150,840 JANUARY 1, 2003 $260,458 $717,242 $260,439 $(72,082) $1,166,057 Common Stock Dividends (32,066) (32,066) Preferred Stock Dividends (361) (361) Capital Stock Expense 623 (623) - SFAS 71 Reapplication 162 162 1,133,792 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (12,518) (12,518) Net Income 156,410 156,410 Total Comprehensive Income 143,892 MARCH 31, 2003 $260,458 $718,027 $383,799 $(84,600) $1,277,684 See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,256,941 $2,245,945 Transmission 1,218,056 1,218,108 Distribution 1,964,405 1,951,804 General 275,416 272,901 Construction Work in Progress 234,995 206,545 Total Electric Utility Plant 5,949,813 5,895,303 Accumulated Depreciation and Amortization 2,317,009 2,424,607 NET ELECTRIC UTILITY PLANT 3,632,804 3,470,696 OTHER PROPERTY AND INVESTMENTS 53,149 54,653 LONG-TERM RISK MANAGEMENT ASSETS 130,451 115,748 CURRENT ASSETS: Cash and Cash Equivalents 10,449 4,285 Advances to Affiliates 87,859 - Accounts Receivable: Customers 164,050 132,266 Affiliated Companies 88,948 122,665 Miscellaneous 29,217 28,629 Allowance for Uncollectible Accounts (2,596) (13,439) Fuel Inventory 39,817 53,646 Materials and Supplies 61,697 59,886 Accrued Utility Revenues 7,620 30,948 Risk Management Assets 135,545 94,238 Prepayments and Other 13,716 13,396 TOTAL CURRENT ASSETS 636,322 526,520 REGULATORY ASSETS 407,687 395,553 DEFERRED CHARGES 67,273 64,677 TOTAL ASSETS $4,927,686 $4,627,847 See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 718,027 717,242 Accumulated Other Comprehensive Income (Loss) (84,600) (72,082) Retained Earnings 383,799 260,439 Total Common Shareowner's Equity 1,277,684 1,166,057 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 17,790 17,790 Subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,739,210 1,738,854 TOTAL CAPITALIZATION 3,045,544 2,933,561 OTHER NONCURRENT LIABILITIES 191,764 173,438 CURRENT LIABILITIES: Long-term Debt Due Within One Year 155,007 155,007 Advances from Affiliates - 39,205 Accounts Payable - General 153,667 141,546 Accounts Payable - Affiliated Companies 72,179 98,374 Taxes Accrued 88,442 29,181 Customer Deposits 35,245 26,186 Interest Accrued 39,222 22,437 Risk Management Liabilities 118,979 69,001 Other 63,607 79,832 TOTAL CURRENT LIABILITIES 726,348 660,769 DEFERRED INCOME TAXES 749,572 701,801 DEFERRED INVESTMENT TAX CREDITS 33,936 33,691 LONG-TERM RISK MANAGEMENT LIABILITIES 79,901 44,517 REGULATORY LIABILITIES AND DEFERRED CREDITS 100,621 80,070 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $4,927,686 $4,627,847 See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $156,410 $ 55,341 Adjustments for Noncash Items: Cumulative Effect of Accounting Changes (77,257) - Depreciation and Amortization 36,008 46,800 Deferred Income Taxes 1,005 (3,644) Deferred Investment Tax Credits 245 (1,098) Deferred Power Supply Costs (net) 63,837 352 Mark to Market of Risk Management Contracts 5,383 (6,653) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (9,498) (51,419) Fuel, Materials and Supplies 12,018 12,659 Accrued Utility Revenues 23,328 7,013 Accounts Payable (14,074) 11,456 Taxes Accrued 59,261 29,129 Interest Accrued 16,785 17,516 Incentive Plan Accrued (9,595) (9,362) Change in Operating Reserves 20,095 1,541 Rate Stabilization Deferral (75,601) - Change in Other Assets (14,446) (7,043) Change in Other Liabilities 26,114 9,187 Net Cash Flows From Operating Activities 220,018 111,775 INVESTING ACTIVITIES: Construction Expenditures (56,627) (62,685) Proceeds from Sale of Property and Other 2,264 583 Net Cash Flows Used For Investing Activities (54,363) (62,102) FINANCING ACTIVITIES: Change in Advances From Affiliates (127,064) (31,991) Dividends Paid on Common Stock (32,066) (30,984) Dividends Paid on Cumulative Preferred Stock (361) (361) Net Cash Flows Used For Financing Activities (159,491) (63,336) Net Increase (Decrease) in Cash and Cash Equivalents 6,164 (13,663) Cash and Cash Equivalents at Beginning of Period 4,285 13,663 Cash and Cash Equivalents at End of Period $ 10,449 $ - Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $11,191,000 and $9,222,000 and for income taxes was $(11,498,000) and $9,593,000 in 2003 and 2002, 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 FIRST QUARTER 2003 vs. FIRST QUARTER 2002 Columbus Southern Power Company (CSPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 689,000 retail customers in central and southern Ohio. CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketing transactions. CSPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivery to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing AEP Power Pool revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Results of Operations Net Income increased $32 million or 94% including a $27 million Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note 3). Net Income Before Cumulative Effect increased $5 million or 13% due to an improvement in earnings from retail and AEP Power Pool sales resulting from the interactions of plant availability, colder winter weather and higher margins. CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of marketing and activities conducted on its behalf by the AEP Power Pool. Changes in Operating Revenues The following analyzes the increase in operating revenue components: (in millions) % Electric Generation $20.0 10 Electric Transmission and Distribution 11.3 10 Sales to AEP Affiliates 13.1 170 Total Operating Revenues $44.4 14 The increase in Electric Generation was driven largely by a rise in demand due to more severe winter weather in 2003 versus 2002. Heating degree days for the first quarter of 2003 were up 24% from the same quarter last year which resulted in 14% higher Residential KWH sales as well as a 5% increase in Commercial KWH Sales. CSPCo's share of AEP Power Pool revenues and expenses for 2003 increased over the prior year as a result of an increase in the volume of the AEP Power Pool sales. CSPCo's share of AEP Power Pool sales increased 5%. Changes in Operating Expenses Operating Expenses increased 13% in 2003. The increases in the components of Operating Expenses were: (in millions) % Fuel for Electric Generation $ 6.4 14 Purchased Electricity for Resale 0.5 13 Purchased Electricity from AEP Affiliates 10.6 15 Other Operation 2.5 5 Maintenance 0.4 3 Depreciation and Amortization 1.0 3 Taxes Other Than Income Taxes 5.3 18 Income Taxes 8.1 47 Total Operating Expenses $34.8 13 Fuel for Electric Generation increased in the first quarter of 2003 to meet the demand of the higher Electric Generation sales as net KWH generation increased 13%. Purchased Electricity from AEP Affiliates was higher due to increases in energy purchased from the AEP Power Pool resulting from a high volume of AEP Power Pool sales and greater capacity charges. The increase in Taxes Other Than Income Taxes was a result of increases in property taxes and state excise taxes. An increase in operating Income Taxes is due to an increase in pre-tax operating book income. Other Changes The decrease in Nonoperating Income is due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to reduce those types of transactions. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time, after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3).
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $214,821 $194,824 Electric Transmission and Distribution 123,616 112,324 Sales to AEP Affiliates 20,768 7,678 TOTAL OPERATING REVENUES 359,205 314,826 OPERATING EXPENSES: Fuel for Electric Generation 52,043 45,650 Purchased Electricity for Resale 4,198 3,729 Purchased Electricity from AEP Affiliates 82,149 71,582 Other Operation 56,385 53,861 Maintenance 14,559 14,140 Depreciation and Amortization 33,737 32,736 Taxes Other Than Income Taxes 35,608 30,276 Income Taxes 25,375 17,304 TOTAL OPERATING EXPENSES 304,054 269,278 OPERATING INCOME 55,151 45,548 NONOPERATING INCOME (LOSS) (7,015) 5,074 NONOPERATING EXPENSES 1,862 1,624 NONOPERATING INCOME TAX EXPENSE (CREDIT) (5,547) 1,347 INTEREST CHARGES 13,462 13,793 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 38,359 33,858 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 27,283 - NET INCOME 65,642 33,858 PREFERRED STOCK DIVIDEND REQUIREMENTS 254 181 EARNINGS APPLICABLE TO COMMON STOCK $ 65,388 $ 33,677 The common stock of CSPCo is wholly owned by AEP. See Notes to Financial Statements beginning on Page L-1
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $41,026 $574,369 $176,103 $ - $791,498 Common Stock Dividends Declared (21,766) (21,766) Preferred Stock Dividends Declared (175) (175) Capital Stock Expense 253 (254) (1) 769,556 Comprehensive Income: Other Comprehensive Income - - Net Income 33,858 33,858 Total Comprehensive Income 33,858 MARCH 31, 2002 $41,026 $574,622 $187,766 $ - $803,414 JANUARY 1, 2003 $41,026 $575,384 $290,611 $(59,357) $847,664 Common Stock Dividends Declared (38,311) (38,311) Capital Stock Expense 254 (254) - 809,353 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (7,343) (7,343) Net Income 65,642 65,642 Total Comprehensive Income 58,299 MARCH 31, 2003 $41,026 $575,638 $317,688 $(66,700) $867,652 See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,591,772 $1,582,627 Transmission 413,327 413,286 Distribution 1,214,588 1,208,255 General 155,854 165,025 Construction Work in Progress 106,447 98,433 Total Electric Utility Plant 3,481,988 3,467,626 Accumulated Depreciation and Amortization 1,428,761 1,465,174 NET ELECTRIC UTILITY PLANT 2,053,227 2,002,452 OTHER PROPERTY AND INVESTMENTS 34,589 35,759 LONG-TERM RISK MANAGEMENT ASSETS 76,680 77,810 CURRENT ASSETS: Cash and Cash Equivalents 7,968 1,479 Advances to Affiliates 87,460 31,257 Accounts Receivable: Customers 55,642 49,566 Affiliated Companies 39,880 54,518 Miscellaneous 19,546 22,005 Allowance for Uncollectible Accounts (579) (634) Fuel 15,757 24,844 Materials and Supplies 40,928 40,339 Accrued Utility Revenues 6,964 12,671 Risk Management Assets 79,692 63,348 Prepayments and Other 9,221 7,308 TOTAL CURRENT ASSETS 362,479 306,701 REGULATORY ASSETS 252,940 257,682 DEFERRED CHARGES 77,510 72,836 TOTAL ASSETS $2,857,425 $2,753,240 See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 575,638 575,384 Accumulated Other Comprehensive Loss (66,700) (59,357) Retained Earnings 317,688 290,611 Total Common Shareholder's Equity 867,652 847,664 Long-term Debt - General 747,264 418,626 Long-term Debt - Affiliated Companies - 160,000 TOTAL CAPITALIZATION 1,614,916 1,426,290 OTHER NONCURRENT LIABILITIES 92,207 95,460 CURRENT LIABILITIES: Long-term Debt Due Within One Year 168,500 43,000 Short-term Debt - Affiliated Companies 40,000 290,000 Accounts Payable - General 86,989 89,736 Accounts Payable - Affiliated Companies 45,099 81,599 Taxes Accrued 123,989 112,172 Interest Accrued 13,692 9,798 Risk Management Liabilities 69,939 46,375 Other 51,934 36,790 TOTAL CURRENT LIABILITIES 600,142 709,470 DEFERRED INCOME TAXES 448,836 437,771 DEFERRED INVESTMENT TAX CREDITS 33,144 33,907 LONG-TERM RISK MANAGEMENT LIABILITIES 46,967 29,926 DEFERRED CREDITS AND REGULATORY LIABILITIES 21,213 20,416 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $2,857,425 $2,753,240 See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, (in thousands) 2003 2002 OPERATING ACTIVITIES: Net Income $ 65,642 $ 33,858 Adjustments for Noncash Items: Cumulative Effect of Accounting Changes (27,283) - Depreciation and Amortization 33,737 32,786 Deferred Income Taxes (3,095) (313) Deferred Investment Tax Credits (763) (778) Mark to Market of Risk Management Contracts 10,958 (5,849) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 10,966 (42,207) Fuel, Materials and Supplies 8,498 3,636 Accrued Utility Revenues 5,707 (5,247) Accounts Payable (39,247) 7,349 Taxes Accrued 11,817 (19,947) Interest Accrued 3,894 3,607 Change in Other Assets (5,740) 992 Change in Other Liabilities 6,991 3,505 Net Cash Flows From Operating Activities 82,082 11,392 INVESTING ACTIVITIES: Construction Expenditures (27,269) (24,807) Proceeds from Sale of Property 190 389 Net Cash Flows Used For Investing Activities (27,079) (24,418) FINANCING ACTIVITIES: Issuance of Long-term Debt 500,000 - Advances from (to) Affiliates (56,203) 29,106 Retirement of Long-term Debt (204,000) - Change in Short-term Debt (250,000) - Dividends Paid on Common Stock (38,311) (21,766) Dividends Paid on Cumulative Preferred Stock (175) Net Cash Flows From (Used For) Financing Activities (48,514) 7,165 Net Increase (Decrease) in Cash and Cash Equivalents 6,489 (5,861) Cash and Cash Equivalents at Beginning of Period 1,479 12,358 Cash and Cash Equivalents at End of Period $ 7,968 $ 6,497 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $9,219,000 and $9,725,000 and for income taxes was ($16,019,000) and $11,198,000 in 2003 and 2002, 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 FIRST QUARTER 2003 vs. FIRST QUARTER 2002 I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 571,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among the AEP Power Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is each company's member load ratio (MLR) which determines each company's percentage share of revenues and costs. Under the terms of unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity. If AEP's restructuring settlement agreement filed with the FERC becomes operative, the KPCo agreement extends until December 31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant Unit 2. Results of Operations Net Income Before Cumulative Effect of Accounting Change increased $20 million or 178% due primarily to increased sales as a result of higher availability of I&M's Cook Plant and Rockport Plant in 2003 as compared to 2002. In addition, an improvement in earnings from retail and AEP Power Pool sales resulted from the interaction of plant availability, the more severe winter conditions and higher margins. I&M, as a member of the AEP Power Pool, shares in the revenues and costs of the marketing activities conducted on its behalf by the AEP Power Pool. Changes in Operating Revenues Operating Revenues increased 19% due primarily to higher Electric Generation sales and Sales to AEP Affiliates reflecting the colder winter weather of 2003, an increase in AEP Power Pool transactions shared with I&M and an increase in sales to the AEP Power Pool. The following analyzes the increases in Operating Revenues: (in millions) % Electric Generation $38.6 16 Electric Transmission and Distribution 6.2 9 Sales to AEP Affiliates 21.6 46 Total Operating Revenues $66.4 19 The increase in Electric Generation revenues was due to an increase in sales reflecting a colder winter. Heating degree days were up 28% over the prior year which resulted in an increase in Residential KWH sales of 13% as well as a 5% increase in total retail sales. I&M's share of the AEP Power Pool revenues (as well as expenses) during 2003 increased over the prior year as a result of an increase in the volume of the AEP Power Pool. Revenues from Sales to AEP Affiliates increased significantly reflecting more power being available for sale in 2003 as one unit of the Cook Nuclear Plant was shutdown for refueling and both units of Rockport Plant were scheduled for planned boiler maintenance in 2002. AEP Power Pool members are compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. With the outages in 2002, I&M's available generation increased in 2003 resulting in more power being delivered to the AEP Power Pool. Changes in Operating Expenses Operating Expenses increased 12% in 2003. The changes in the components of Operating Expenses were: Increase (Decrease) (in millions) % Fuel for Electric Generation $18.9 35 Purchased Electricity for Resale 1.0 19 Purchased Electricity from AEP Affiliates 12.4 23 Other Operation (10.4) (9) Maintenance 0.3 1 Depreciation and Amortization 1.9 4 Taxes Other Than Income Taxes (1.4) (8) Income Taxes 15.0 250 Total Operating Expenses $37.7 12 Fuel for Electric Generation increased primarily due to an increase in generation reflecting the plant outages in 2002. Purchased Electricity from AEP Affiliates increased due to higher availability of the Rockport Plant in 2002, as I&M is required to purchase a portion of AEGCo's Rockport Plant generation under their unit power agreement. AEGCo's share of generation at the Rockport Plant increased 50% in 2003. Other Operation expense decreased due to cost reduction efforts instituted in the fourth quarter of 2002 and costs incurred during the outages occurring during the first quarter of 2002. The decrease in Taxes Other Than Income Taxes reflects a favorable tax law change in Indiana effective March 2002 and a lower estimate for Cook Plant's assessed value which reduced real and personal property tax estimates on which 2003 accruals are based. Income Taxes attributable to operations increased significantly due to an increase in pre-tax operating income. Other Changes The decrease in Nonoperating Income is due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to exit those risk management activities in areas outside of its traditional market area. The decrease in Nonoperating Income Tax Expense is a result of the decline in pre-tax nonoperating income. Cumulative Effect of Accounting Change The Cumulative Effect of Accounting Change is due to the implementation of the requirements of EITF 02-3 (see Notes 2 and 3).
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $273,008 $234,446 Electric Transmission and Distribution 76,779 70,580 Sales to AEP Affiliates 68,811 47,209 TOTAL OPERATING REVENUES 418,598 352,235 OPERATING EXPENSES: Fuel for Electric Generation 73,094 54,156 Purchased Electricity for Resale 6,282 5,282 Purchased Electricity from AEP Affiliates 65,898 53,507 Other Operation 101,381 111,766 Maintenance 31,367 31,043 Depreciation and Amortization 43,726 41,866 Taxes Other Than Income Taxes 16,821 18,241 Income Taxes 21,039 6,011 TOTAL OPERATING EXPENSES 359,608 321,872 OPERATING INCOME 58,990 30,363 NONOPERATING INCOME 3,619 17,004 NONOPERATING EXPENSES 12,935 13,310 NONOPERATING INCOME TAX EXPENSE (CREDIT) (4,451) (425) INTEREST CHARGES 23,438 23,424 NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 30,687 11,058 CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (3,160) - NET INCOME 27,527 11,058 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,149 1,155 EARNINGS APPLICABLE TO COMMON STOCK $ 26,378 $ 9,903 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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $56,584 $733,216 $ 74,605 $(3,835) $ 860,570 Preferred Stock Dividends (1,122) (1,122) Capital Stock Expense 33 (33) - 859,448 Comprehensive Income: Other Comprehensive Income, Net of Taxes: Cash Flow Interest Rate Hedge 1,259 1,259 Net Income 11,058 11,058 Total Comprehensive Income 12,317 MARCH 31, 2002 $56,584 $733,249 $ 84,508 $(2,576) $ 871,765 JANUARY 1, 2003 $56,584 $858,560 $143,996 $(40,487) $1,018,653 Common Stock Dividends (10,000) (10,000) Preferred Stock Dividends (1,115) (1,115) Capital Stock Expense 34 (34) - 1,007,538 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (7,857) (7,857) Net Income 27,527 27,527 Total Comprehensive Income 19,670 MARCH 31, 2003 $56,584 $858,594 $160,374 $(48,344) $1,027,208 See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $2,858,230 $2,768,463 Transmission 979,559 971,599 Distribution 928,699 921,835 General (including nuclear fuel) 208,856 220,137 Construction Work in Progress 148,218 147,924 Total Electric Utility Plant 5,123,562 5,029,958 Accumulated Depreciation and Amortization 2,645,331 2,568,604 NET ELECTRIC UTILITY PLANT 2,478,231 2,461,354 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 870,689 870,754 LONG-TERM RISK MANAGEMENT ASSETS 80,073 83,265 OTHER PROPERTY AND INVESTMENTS 115,837 120,941 CURRENT ASSETS: Cash and Cash Equivalents 6,520 3,237 Advances to Affiliates 228,775 191,226 Accounts Receivable: Customers 77,278 67,333 Affiliated Companies 131,332 122,489 Miscellaneous 18,401 30,468 Allowance for Uncollectible Accounts (574) (578) Fuel 30,586 32,731 Materials and Supplies 96,875 95,552 Risk Management Assets 85,221 68,148 Prepayments and Other 16,213 18,410 TOTAL CURRENT ASSETS 690,627 629,016 REGULATORY ASSETS 304,988 348,212 DEFERRED CHARGES 85,494 73,649 TOTAL ASSETS $4,625,939 $4,587,191 See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 858,594 858,560 Accumulated Other Comprehensive Income (Loss) (48,344) (40,487) Retained Earnings 160,374 143,996 Total Common Shareowner's Equity 1,027,208 1,018,653 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 8,101 8,101 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,333,013 1,587,062 TOTAL CAPITALIZATION 2,433,267 2,678,761 OTHER NONCURRENT LIABILITIES: Asset Retirement Obligations 525,116 - Nuclear Decommissioning - 620,672 Other 131,140 138,965 TOTAL OTHER NONCURRENT LIABILITIES 656,256 759,637 CURRENT LIABILITIES: Long-term Debt Due Within One Year 285,000 30,000 Accounts Payable: General 108,331 125,048 Affiliated Companies 60,845 93,608 Taxes Accrued 90,725 71,559 Interest Accrued 25,786 21,481 Obligations Under Capital Leases 6,258 8,229 Risk Management Liabilities 73,799 48,568 Other 95,692 92,822 TOTAL CURRENT LIABILITIES 746,436 491,315 DEFERRED INCOME TAXES 326,438 356,197 DEFERRED INVESTMENT TAX CREDITS 95,874 97,709 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 72,958 73,885 LONG-TERM RISK MANAGEMENT LIABILITIES 48,402 32,261 DEFERRED CREDITS AND REGULATORY LIABILITIES 246,308 97,426 CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $4,625,939 $4,587,191 See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $ 27,527 $ 11,058 Adjustments for Noncash Items: Cumulative Effect of Accounting Change 3,160 - Depreciation and Amortization 43,726 42,184 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) 9,410 (24,130) Unrecovered Fuel and Purchased Power Costs 9,375 9,375 Amortization of Nuclear Outage Costs 10,000 10,000 Deferred Income Taxes (12,367) (7,132) Deferred Investment Tax Credits (1,835) (1,845) Mark-to-Market of Risk Management Contracts 10,543 (3,708) Deferred Property Taxes (9,116) (8,409) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (6,725) (58,316) Fuel, Materials and Supplies 822 5,522 Accounts Payable (49,480) (10,779) Taxes Accrued 19,166 21,391 Rent Accrued - Rockport Plant Unit 2 18,464 18,464 Change in Other Assets 21,178 8,328 Change in Other Liabilities (13,679) 675 Net Cash Flows From Operating Activities 80,169 12,678 INVESTING ACTIVITIES: Construction Expenditures (28,234) (26,398) Other 12 - Net Cash Flows Used For Investing Activities (28,222) (26,398) FINANCING ACTIVITIES: Change in Advances from (to) Affiliates (net) (37,549) 8,887 Dividends Paid on Common Stock (10,000) - Dividends Paid on Cumulative Preferred Stock (1,115) (1,122) Net Cash Flows From (Used For) Financing Activities (48,664) 7,765 Net Increase (Decrease) in Cash and Cash Equivalents 3,283 (5,955) Cash and Cash Equivalents at Beginning of Period 3,237 16,804 Cash and Cash Equivalents at End of Period $ 6,520 $ 10,849 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $18,211,000 and $15,090,000 and for income taxes was $20,011,000 and $(470,000) in 2003 and 2002, respectively. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 174,000 retail customers in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to neighboring utility systems and power marketing transactions. KPCo also sells wholesale power to municipalities. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for their out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve-month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. KPCo has a unit power agreement with AEGCo, an affiliated company, which expires in 2004. The agreement provides for KPCo to purchase 15% of the total output of the two unit 2,600-mw capacity Rockport Plant. Under the unit power agreement, there is a demand charge for the right to receive the power, which is payable even if the power is not taken. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its fixed expenses including a FERC-approved rate of return on common equity. Results of Operations Net Income of $9.9 million in the first quarter of 2003 included a loss from the Cumulative Effect of Accounting Change of $1.1 million due to the adoption of EITF 02-3. Income Before Cumulative Effect of Accounting Change increased $0.8 million or 8% primarily due to an improvement in earnings from retail and AEP Power Pool sales resulting from the interaction of plant availability, the more severe winter weather and higher margins in 2003 versus 2002. KPCo, a member of the Power Pool, shares in the revenues and costs of marketing and activities conducted on its behalf by the AEP Power Pool. Changes in Operating Revenues The following analyzes the increase in operating revenues: (in millions) % Electric Generation $10.3 17 Electric Transmission and Distribution 0.5 2 Sales to AEP Affiliates 2.1 35 Total Operating Revenues $12.9 13 The increase in Operating Revenues is due to an increase in residential sales reflecting increased demand due to the more severe weather in 2003 versus 2002 and higher volume in the AEP Power Pool of transactions. Heating degree days were up approximately 18% resulting in a 12% increase in Residential KWH sold. This increase was partially offset by reduced industrial sales reflecting the slowdown in the economy. Overall retail sales were up 3% over 2002. Changes in Operating Expenses Changes in the components of Operating Expenses were: Increase (Decrease) (in millions) % Fuel for Electric Generation $(3.8) (18) Purchased Electricity from AEP Affiliates 8.5 29 Other Operation (0.2) (2) Maintenance 2.2 49 Depreciation and Amortization 0.5 6 Taxes Other Than Income Taxes 0.2 11 Income Taxes 1.2 22 Total Operating Expenses $ 8.6 10 Fuel for Electric Generation decreased due to unplanned outages in 2003 at KPCo's Big Sandy Plant resulting in a 26% decline in net generation. Purchased Electricity from AEP Affiliates increased primarily to support Electric Generation sales. Increased purchases of electricity from the Rockport Plant, which had been in an outage during the first quarter of 2002, also contributed to the increased expense. Maintenance expense increased primarily due to distribution line maintenance resulting from a major ice storm in February 2003. A three week outage at the Big Sandy plant also contributed to increased Maintenance expenses. The increase in operating Income Taxes is due to an increase in pre-tax Operating Income. Other Changes The decrease in Nonoperating Income is due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to reduce those types of transactions. The increase in Nonoperating Income Tax Credits reflects the tax benefits associated with the reduction in Nonoperating Income. Cumulative Effect of Accounting Change The Cumulative Effect of Accounting Change is due to the implementation of the requirements of EITF 02-3 (see Notes 2 and 3).
KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $ 69,165 $ 58,887 Electric Transmission and Distribution 34,794 34,276 Sales to AEP Affiliates 8,135 6,022 TOTAL OPERATING REVENUES 112,094 99,185 OPERATING EXPENSES: Fuel for Electric Generation 17,947 21,767 Purchased Electricity from AEP Affiliates 37,395 28,941 Other Operation 12,137 12,351 Maintenance 6,765 4,549 Depreciation and Amortization 8,712 8,257 Taxes Other Than Income Taxes 2,365 2,135 Income Taxes 6,939 5,701 TOTAL OPERATING EXPENSES 92,260 83,701 OPERATING INCOME 19,834 15,484 NONOPERATING INCOME (LOSS) (2,415) 1,642 NONOPERATING EXPENSES 232 570 NONOPERATING INCOME TAX CREDIT 558 190 INTEREST CHARGES 6,724 6,500 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 11,021 10,246 CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX) (1,134) - NET INCOME $ 9,887 $ 10,246 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 COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $50,450 $158,750 $48,833 $(1,903) $256,130 Common Stock Dividends (7,044) (7,044) 249,086 Comprehensive Income: Other Comprehensive Income, Net of Taxes: Unrealized Gain on Cash Flow Power Hedges 516 516 Net Income 10,246 10,246 Total Comprehensive Income 10,762 MARCH 31, 2002 $50,450 $158,750 $52,035 $(1,387) $259,848 JANUARY 1, 2003 $50,450 $208,750 $48,269 $(9,451) $298,018 Common Stock Dividends (5,482) (5,482) 292,536 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (2,865) (2,865) Net Income 9,887 9,887 Total Comprehensive Income 7,022 MARCH 31, 2003 $50,450 $208,750 $52,674 $(12,316) $299,558 See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $ 284,401 $ 275,121 Transmission 374,120 373,639 Distribution 415,725 414,281 General 67,296 67,449 Construction Work in Progress 179,635 165,129 Total Electric Utility Plant 1,321,177 1,295,619 Accumulated Depreciation and Amortization 396,014 397,304 NET ELECTRIC UTILITY PLANT 925,163 898,315 OTHER PROPERTY AND INVESTMENTS 6,585 6,904 LONG-TERM RISK MANAGEMENT ASSETS 29,686 29,871 CURRENT ASSETS: Cash and Cash Equivalents 1,465 2,304 Accounts Receivable: Customers 25,156 22,044 Affiliated Companies 13,692 23,802 Miscellaneous 3,254 2,889 Allowance for Uncollectible Accounts (563) (192) Fuel 12,158 10,817 Materials and Supplies 16,125 16,127 Accrued Utility Revenues 6,529 5,301 Accrued Tax Benefit - 1,253 Risk Management Assets 30,853 24,320 Prepayments and Other 2,110 2,127 TOTAL CURRENT ASSETS 110,779 110,792 REGULATORY ASSETS 102,689 101,976 DEFERRED CHARGES 16,084 16,818 TOTAL ASSETS $1,190,986 $1,164,676 See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 208,750 208,750 Accumulated Other Comprehensive Income (Loss) (12,316) (9,451) Retained Earnings 52,674 48,269 Total Common Shareowner's Equity 299,558 298,018 Long-term Debt 391,665 391,632 Long-term Debt - Affiliated Companies 60,000 60,000 TOTAL CAPITALIZATION 751,223 749,650 OTHER NONCURRENT LIABILITIES 27,220 27,319 CURRENT LIABILITIES: Long-term Debt Due Within One Year - Affiliated Companies 15,000 15,000 Advances from Affiliates 46,071 23,386 Accounts Payable: General 40,294 46,515 Affiliated Companies 25,052 44,035 Customer Deposits 10,345 8,048 Interest Accrued 7,987 6,471 Accrued Taxes 8,679 - Risk Management Liabilities 27,076 17,803 Other 10,351 14,322 TOTAL CURRENT LIABILITIES 190,855 175,580 DEFERRED INCOME TAXES 179,059 178,313 DEFERRED INVESTMENT TAX CREDITS 8,871 9,165 LONG-TERM RISK MANAGEMENT LIABILITIES 18,183 11,488 REGULATORY LIABILITIES AND DEFERRED CREDITS 15,575 13,161 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $1,190,986 $1,164,676 See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $ 9,887 $ 10,246 Adjustments for Noncash Items: Cumulative Effect of Accounting Change 1,134 - Depreciation and Amortization 8,712 8,257 Deferred Income Taxes 2,766 (556) Deferred Investment Tax Credits (294) (295) Deferred Fuel Costs (net) (388) 1,542 Mark-to-Market of Risk Management Contracts 3,500 (1,858) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 7,004 (14,598) Fuel, Materials and Supplies (1,339) (1,759) Accrued Utility Revenues (1,228) (2,921) Accounts Payable (25,204) 5,618 Taxes Accrued 9,932 1,710 Change in Other Assets (474) 4,997 Change in Other Liabilities 2,765 435 Net Cash Flows From Operating Activities 16,773 10,818 INVESTING ACTIVITIES: Construction Expenditures (35,025) (15,898) Proceeds from Sales of Property and Other 210 - Net Cash Flow Used for Investing Activities (34,815) (15,898) FINANCING ACTIVITIES: Change in Advances from Affiliates (net) 22,685 10,594 Dividends Paid (5,482) (7,044) Net Cash Flows From Financing Activities 17,203 3,550 Net Decrease in Cash and Cash Equivalents (839) (1,530) Cash and Cash Equivalents at Beginning of Period 2,304 1,947 Cash and Cash Equivalents at End of Period $ 1,465 $ 417 Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $7,975,000 and $6,328,000 in 2003 and 2002, respectively. Cash paid (received) for income taxes was $(6,435,000) and $3,053,000 in 2003 and 2002, respectively. Noncash acquisitions under capital leases were $22,000 in 2002. See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 Ohio Power Company (OPCo) is a public utility engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 702,000 customers in the northwestern, east central, eastern and southern sections of Ohio. As a member of the AEP Power Pool, OPCo shares in the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketing transactions. OPCo also sells wholesale power to Wheeling Power Company, municipalities and electric cooperatives. The cost of the AEP Power Pool's generating capacity is allocated among the Pool members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve month peak demand relative to the total peak demand of all member companies as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR) which determines each company's percentage share of AEP Power Pool revenues and costs. Results of Operations Net Income for the first quarter of 2003 increased $129 million or 201% compared to the same quarter last year. This increase was due primarily to a $125 million Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note 3). Net Income Before Cumulative Effect of Accounting Changes increased $4 million or 7% primarily due to an improvement in earnings from retail and AEP Power Pool sales resulting from the interactions of plant availability, the colder weather and higher margins. OPCo, as a member of the Power Pool, shares in the revenues and costs of marketing and activities conducted on its behalf by the AEP Power Pool. Changes in Operating Revenues The following analyzes the increases in operating revenue components: (in millions) % Electric Generation $35.1 13 Electric Transmission and Distribution 4.8 3 Sales to AEP Affiliates 30.1 27 Total Operating Revenues $70.0 13 The increase in Operating Revenues is due to a rise in revenue from Electric Generation and Sales to AEP Affiliates. The increase was driven largely by an increased demand due to more severe winter conditions in 2003 as compared to 2002, and an increase in the volume of AEP Power Pool transactions. Heating degree days were up 25% over the prior year which resulted in 13% higher residential KWH sales. OPCo's share of the AEP Power Pool revenues and expenses for first quarter 2003 increased over the prior year as a result of an increase in the overall volume of the AEP Power Pool. OPCo's share of AEP Power Pool sales increased 19%. Changes in Operating Expenses Operating Expenses increased 13% in 2003. The changes in the components of Operating Expenses were: Increase (Decrease) (in millions) % Fuel for Electric Generation $11.3 8 Purchased Electricity for Resale 1.8 10 Purchased Electricity from AEP Affiliates 8.5 60 Other Operation 2.9 3 Maintenance 6.5 22 Depreciation and Amortization (1.1) (2) Taxes Other Than Income Taxes 1.3 3 Income Taxes 23.6 67 Total Operating Expenses $54.8 13 Fuel for Electric Generation increased in the first quarter of 2003 to meet the demand of the higher Electric Generation sales as net KWH generation increased 30%. Purchased Electricity for Resale increased due to the 4% increase in KWH purchased to meet demand. Purchased Electricity from AEP Affiliates increased as a result of additional MWH purchases and increased prices. Maintenance expense increased primarily due to an increase in boiler plant maintenance and distribution line maintenance caused by severe storm damage in 2003. The increase in operating Income Taxes is due to an increase in pre-tax operating book income and federal income tax adjustments. Other Changes The decrease in Nonoperating Income (Loss) is due to lower margins for power sold outside of AEP's traditional marketing area reflecting reduced demand and AEP's plan to reduce those types of transactions. Nonoperating Expenses increased predominately as a result of costs incurred related to the sale of our Switch Water Heater program. The decrease in Nonoperating Income Tax Expense (Credit) is due to a decrease in pre-tax nonoperating book income. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3).
OHIO POWER COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $305,035 $269,978 Electric Transmission and Distribution 145,852 141,040 Sales to AEP Affiliates 139,744 109,634 TOTAL OPERATING REVENUES 590,631 520,652 OPERATING EXPENSES: Fuel for Electric Generation 153,648 142,336 Purchased Electricity for Resale 19,392 17,629 Purchased Electricity from AEP Affiliates 22,783 14,227 Other Operation 92,981 90,114 Maintenance 35,457 28,988 Depreciation and Amortization 61,551 62,621 Taxes Other Than Income Taxes 47,155 45,839 Income Taxes 58,794 35,182 TOTAL OPERATING EXPENSES 491,761 436,936 OPERATING INCOME 98,870 83,716 NONOPERATING INCOME (LOSS) (3,811) 12,925 NONOPERATING EXPENSES 10,623 7,407 NONOPERATING INCOME TAX EXPENSE (CREDIT) (4,656) 3,722 INTEREST CHARGES 20,742 21,461 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 68,350 64,051 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 124,632 - NET INCOME 192,982 64,051 PREFERRED STOCK DIVIDEND REQUIREMENTS 314 314 EARNINGS APPLICABLE TO COMMON STOCK $192,668 $ 63,737 The common stock of OPCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $321,201 $462,483 $401,297 $ (196) $1,184,785 Common Stock Dividends (32,582) (32,582) Preferred Stock Dividends (314) (314) 1,151,889 Comprehensive Income: Other Comprehensive Income (Loss) (201) (201) Net Income 64,051 64,051 Total Comprehensive Income 63,850 MARCH 31, 2002 $321,201 $462,483 $432,452 $ (397) $1,215,739 JANUARY 1, 2003 $321,201 $462,483 $522,316 $(72,886) $1,233,114 Common Stock Dividends (41,934) (41,934) Preferred Stock Dividends (314) (314) 1,190,866 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (4,115) (4,115) Net Income 192,982 192,982 Total Comprehensive Income 188,867 MARCH 31, 2003 $321,201 $462,483 $673,050 $(77,001) $1,379,733 See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $3,135,098 $3,116,825 Transmission 907,021 905,829 Distribution 1,122,732 1,114,600 General 227,014 260,153 Construction Work in Progress 307,842 288,419 Total Electric Utility Plant 5,699,707 5,685,826 Accumulated Depreciation and Amortization 2,331,793 2,566,828 NET ELECTRIC UTILITY PLANT 3,367,914 3,118,998 OTHER PROPERTY AND INVESTMENTS 58,084 61,686 LONG-TERM RISK MANAGEMENT ASSETS 101,736 103,230 CURRENT ASSETS: Cash and Cash Equivalents 32,412 5,285 Accounts Receivable: Customers 112,495 95,100 Affiliated Companies 98,926 124,244 Miscellaneous 25,567 19,281 Allowance for Uncollectible Accounts (898) (909) Fuel 75,920 87,409 Materials and Supplies 83,327 85,379 Risk Management Assets 114,581 92,108 Prepayments and Other 36,370 12,083 TOTAL CURRENT ASSETS 578,700 519,980 REGULATORY ASSETS 549,421 568,641 DEFERRED CHARGES AND OTHER ASSETS 126,564 84,497 TOTAL ASSETS $4,782,419 $4,457,032 See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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) (77,001) (72,886) Retained Earnings 673,050 522,316 Total Common Shareholder's Equity 1,379,733 1,233,114 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,648 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 1,175,676 917,649 TOTAL CAPITALIZATION 2,580,907 2,176,261 OTHER NONCURRENT LIABILITIES 237,011 227,689 CURRENT LIABILITIES: Long-term Debt Due Within One Year - General 89,665 89,665 Long-term Debt Due Within One Year - Affiliated Companies 60,000 60,000 Short-term Debt - Affiliated Companies - 275,000 Advances from Affiliates 239,328 129,979 Accounts Payable - General 139,007 170,563 Accounts Payable - Affiliated Companies 68,551 145,718 Customer Deposits 19,994 12,969 Taxes Accrued 165,222 111,778 Interest Accrued 24,644 18,809 Obligations Under Capital Leases 10,348 14,360 Risk Management Liabilities 93,511 61,839 Other 54,233 80,608 TOTAL CURRENT LIABILITIES 964,503 1,171,288 DEFERRED INCOME TAXES 875,344 794,387 DEFERRED INVESTMENT TAX CREDITS 17,986 18,748 LONG-TERM RISK MANAGEMENT LIABILITIES 62,313 39,702 DEFERRED CREDITS 44,355 28,957 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $4,782,419 $4,457,032 See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $192,982 $ 64,051 Adjustments for Noncash Items: Cumulative Effect of Accounting Changes (124,632) - Depreciation and Amortization 61,551 62,621 Deferred Income Taxes (1,563) (4,649) Deferred Property Taxes 14,878 14,717 Mark to Market of Risk Management Contracts 14,156 (16,055) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) 1,626 (2,618) Fuel, Materials and Supplies 13,541 (6,416) Accrued Utility Revenues 4,429 (5,368) Prepayments and Other (24,288) (11,822) Accounts Payable (108,723) (75,824) Customer Deposits 7,025 509 Taxes Accrued 53,444 21,498 Interest Accrued 5,835 7,171 Other Operating Assets (54,220) 1,388 Other Operating Liabilities (26,276) (8,819) Net Cash Flows From Operating Activities 29,765 40,384 INVESTING ACTIVITIES: Construction Expenditures (56,372) (66,312) Proceeds from Sale of Property and Other 1,633 154 Net Cash Flows Used For Investing Activities (54,739) (66,158) FINANCING ACTIVITIES: Issuance of Long-term Debt 500,000 - Change in Advances to Affiliates (net) 109,349 89,173 Retirement of Long-term Debt (240,000) - Changes in Short-term Debt (net) (275,000) - Dividends Paid on Common Stock (41,934) (32,582) Dividends Paid on Cumulative Preferred Stock (314) (314) Net Cash Flows From Financing Activities 52,101 56,277 Net Increase in Cash and Cash Equivalents 27,127 30,503 Cash and Cash Equivalents at Beginning of Period 5,285 8,848 Cash and Cash Equivalents at End of Period $ 32,412 $ 39,351 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $14,551,000 and $13,900,000 and for income taxes was $(22,475,000) and $(5,574,000) in 2003 and 2002, respectively. Noncash acquisitions under capital leases were $98,000 in 2002. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS FIRST QUARTER 2003 vs. FIRST QUARTER 2002 Public Service Company of Oklahoma (PSO) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electricity to approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO sells electric power to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing activities are conducted on PSO's behalf by AEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. Results of Operations In 2003, Net Income increased by $2.3 million primarily resulting from increased wholesale margins and increased transmission revenues, partially offset by higher Interest Charges. Changes in Operating Revenues Increase (Decrease) (in millions) % Electric Generation 85.8 92 Electric Transmission and Distribution 5.6 10 Sales to AEP Affiliates 2.3 110 Total Operating Revenues $93.7 63 Electric Generation revenues increased in 2003 as a result of increased fuel related revenues and retained wholesale margins. The increase in Electric Transmission & Distribution revenues is due to increased transmission revenues, as distribution revenues were virtually flat. Sales to AEP Affiliates increased primarily due to higher prices. Changes in Operating Expenses Increase (Decrease) (in millions) % Fuel for Electric Generation $45.1 78 Purchased Electricity for Resale 14.8 N.M. Purchased Electricity from AEP Affiliates 25.2 150 Other Operation 5.0 19 Maintenance (4.8) (34) Depreciation and Amortization 0.6 3 Taxes Other Than Income Taxes 1.8 23 Income Taxes (Credits) 1.2 74 Total Operating Expenses $88.9 63 N.M. = Not Meaningful The increase in Fuel for Electric Generation in 2003 was primarily due to higher market prices for natural gas and increased MWH generation. The increase in purchased electricity expenses was due to higher prices offset in part by reduced MWH purchases. Other Operation expense increased in 2003 primarily due to increased customer related expenses and a credit posted in 2002 related to a true-up of rents received from affiliates. Maintenance expense decreased in 2003 largely as a result of the absence of expenses to repair damage to overhead lines caused by a winter storm in 2002. Taxes Other Than Income Taxes increased in 2003 primarily due to an increase in ad valorem taxes. Income Taxes increased in 2003 primarily due to an increase in pre-tax income. Other Changes Interest Charges increased due to increases in average long-term debt balances and higher average interest rates.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $179,149 $ 93,337 Electric Transmission and Distribution 59,118 53,555 Sales to AEP Affiliates 4,395 2,094 TOTAL OPERATING REVENUES 242,662 148,986 OPERATING EXPENSES: Fuel for Electric Generation 103,174 58,097 Purchased Electricity for Resale 12,491 (2,344) Purchased Electricity from AEP Affiliates 42,107 16,845 Other Operation 31,618 26,639 Maintenance 9,394 14,169 Depreciation and Amortization 21,494 20,916 Taxes Other Than Income Taxes 9,646 7,848 Income Taxes (Credits) (408) (1,594) TOTAL OPERATING EXPENSES 229,516 140,576 OPERATING INCOME 13,146 8,410 NONOPERATING INCOME 650 106 NONOPERATING EXPENSES 439 595 NONOPERATING INCOME TAX CREDIT 200 141 INTEREST CHARGES 12,866 9,710 NET INCOME (LOSS) 691 (1,648) LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 638 $ (1,701) The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $157,230 $180,016 $142,994 $ - $480,240 Common Stock Dividends (22,455) (22,455) Preferred Stock Dividends (53) (53) 457,732 Comprehensive Income (Loss): Other Comprehensive Income - - Net Income (Loss) (1,648) (1,648) Total Comprehensive Income (Loss) (1,648) MARCH 31, 2002 $157,230 $180,016 $118,838 $ - $456,084 JANUARY 1, 2003 $157,230 $180,016 $116,474 $(54,473) $399,247 Common Stock Dividends (7,500) (7,500) Preferred Stock Dividends (53) (53) Distribution of Investment in AEMT, Inc. Preferred Shares to Parent (548) (548) 391,146 Comprehensive Income (Loss): Other Comprehensive Income (Loss), Net of Taxes: Minimum Pension Liability (58) (58) Unrealized Loss on Cash Flow Power Hedges (1,197) (1,197) Net Income 691 691 Total Comprehensive Income (Loss) (564) MARCH 31, 2003 $157,230 $180,016 $109,064 $(55,728) $390,582 See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,040,642 $1,040,520 Transmission 431,553 432,846 Distribution 991,688 990,947 General 200,630 206,747 Construction Work in Progress 95,186 88,444 Total Electric Utility Plant 2,759,699 2,759,504 Accumulated Depreciation and Amortization 1,241,480 1,239,855 NET ELECTRIC UTILITY PLANT 1,518,219 1,519,649 OTHER PROPERTY AND INVESTMENTS 4,931 5,383 LONG-TERM RISK MANAGEMENT ASSETS 7,484 4,481 CURRENT ASSETS: Cash and Cash Equivalents 15,975 16,774 Accounts Receivable: Customers 30,626 31,687 Affiliated Companies 15,939 14,139 Allowance for Uncollectible Accounts (54) (84) Fuel Inventory 18,941 19,973 Materials and Supplies 38,178 37,375 Under-recovered Fuel Costs 77,701 76,470 Risk Management Assets 7,100 3,841 Prepayments and Other 3,643 2,735 TOTAL CURRENT ASSETS 208,049 202,910 REGULATORY ASSETS 25,417 26,150 DEFERRED CHARGES 45,755 18,117 TOTAL ASSETS $1,809,855 $1,776,690 See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $15 Par Value: Authorized Shares: 11,000,000 Issued Shares: 10,482,000 Outstanding Shares: 9,013,000 $ 157,230 $ 157,230 Paid-in Capital 180,016 180,016 Accumulated Other Comprehensive Income (Loss) (55,728) (54,473) Retained Earnings 109,064 116,474 Total Common Shareholder's Equity 390,582 399,247 Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,267 5,267 PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 445,514 445,437 TOTAL CAPITALIZATION 916,363 924,951 OTHER NONCURRENT LIABILITIES 54,853 54,761 CURRENT LIABILITIES: Long-term Debt Due Within One Year 100,000 100,000 Advances from Affiliates 119,820 86,105 Accounts Payable - General 74,807 61,169 Accounts Payable - Affiliated Companies 59,616 78,076 Customer Deposits 23,863 21,789 Taxes Accrued 22,732 6,854 Interest Accrued 9,384 6,979 Risk Management Liabilities 6,658 3,260 Other 15,210 24,957 TOTAL CURRENT LIABILITIES 432,090 389,189 DEFERRED INCOME TAXES 342,529 341,396 DEFERRED INVESTMENT TAX CREDITS 31,754 32,201 REGULATORY LIABILITIES AND DEFERRED CREDITS 27,392 32,611 LONG-TERM RISK MANAGEMENT LIABILITIES 4,874 1,581 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $1,809,855 $1,776,690 See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income (Loss) $ 691 $ (1,648) Adjustments to Reconcile Net Income (Loss) to Net Cash Flows Used For Operating Activities: Depreciation and Amortization 21,494 20,916 Deferred Income Taxes 1,309 1,886 Deferred Investment Tax Credits (447) (448) Changes in Certain Assets and Liabilities: Accounts Receivable (net) (769) (3,733) Fuel, Materials and Supplies 229 (1,346) Accounts Payable (4,822) (31,427) Taxes Accrued 15,878 9,407 Deferred Property Taxes (24,413) (21,210) Fuel Recovery (1,231) 2,380 Changes in Other Assets (11,662) (7,606) Changes in Other Liabilities (5,606) 4,032 Net Cash Flows Used For Operating Activities (9,349) (28,797) INVESTING ACTIVITIES: Construction Expenditures (17,612) (10,559) Net Cash Flows Used For Investing Activities (17,612) (10,559) FINANCING ACTIVITIES: Change in Advances from Affiliates (net) 33,715 63,910 Dividends Paid on Common Stock (7,500) (22,455) Dividends Paid on Cumulative Preferred Stock (53) (53) Net Cash Flows From Financing Activities 26,162 41,402 Net Increase (Decrease) in Cash and Cash Equivalents (799) 2,046 Cash and Cash Equivalents at Beginning of Period 16,774 5,795 Cash and Cash Equivalents at End of Period $ 15,975 $ 7,841 Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $9,653,000 and $5,157,000 and for income taxes was $(959,000) and $1,783,000 in 2003 and 2002, respectively. There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company. 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 FIRST QUARTER 2003 vs. FIRST QUARTER 2002 Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 437,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas. SWEPCo sells electric power to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC. SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP's electric power transactions with other utility systems and power marketers. Results of Operations Net Income increased $10.8 million or 133% for the quarter. The increase resulted primarily from the cumulative effect of accounting changes due to the adoption of SFAS 143. Changes in Operating Revenues Increase (Decrease) (in millions) % Electric Generation $24.9 19 Electric Transmission and Distribution (1.3) (2) Sales to AEP Affiliates 9.4 41 Total Operating Revenues $33.0 15 Electric Generation revenues increased in 2003 due to higher wholesale revenues, a slight increase in customers, coupled with a more profitable mix of sales in higher rate categories. Sales to AEP Affiliates increased primarily due to higher prices. Changes in Operating Expenses Increase (Decrease) (in millions) % Fuel for Electric Generation $14.1 16 Purchased Electricity for Resale 8.5 209 Purchased Electricity from AEP Affiliates 5.3 97 Other Operation (1.3) (3) Maintenance 1.0 8 Depreciation and Amortization (2.1) (7) Taxes Other Than Income Taxes 1.4 10 Income Taxes 2.5 91 Total Operating Expenses $29.4 15 Fuel for Electric Generation increased in 2003 due to both increased generation and higher fuel costs. In 2003, Purchased Electricity increased overall due to higher costs for purchased power offset in part by reduced MWHs purchased. Maintenance expense increased in 2003 as a result of scheduled maintenance at several power plants. The decrease in Depreciation and Amortization expense was due primarily to the restoration of a regulatory asset for recovery of a fuel related cost allowed in a fuel proceeding for the Arkansas portion of SWEPCo's operations. In 2003, Taxes Other Than Income Taxes increased due to increased payroll and state gross receipts taxes. Income Taxes attributable to operations increased in 2003 due to increased pre-tax income. Other Changes Nonoperating Income increased in 2003 due primarily to increased interest income and AFUDC. In 2003, Interest Charges increased due to increased levels of debt outstanding and higher average interest rates. Cumulative Effect of Accounting Changes The Cumulative Effect of Accounting Changes is due to the one-time after-tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Notes 2 and 3).
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING REVENUES: Electric Generation $156,681 $131,761 Electric Transmission and Distribution 66,242 67,539 Sales to AEP Affiliates 32,355 22,959 TOTAL OPERATING REVENUES 255,278 222,259 OPERATING EXPENSES: Fuel for Electric Generation 103,010 88,883 Purchased Electricity for Resale 12,567 4,070 Purchased Electricity from AEP Affiliates 10,810 5,485 Other Operation 40,857 42,151 Maintenance 12,817 11,838 Depreciation and Amortization 28,035 30,140 Taxes Other Than Income Taxes 15,873 14,466 Income Taxes 5,265 2,757 TOTAL OPERATING EXPENSES 229,234 199,790 OPERATING INCOME 26,044 22,469 NONOPERATING INCOME 872 102 NONOPERATING EXPENSES 521 566 NONOPERATING INCOME TAX EXPENSE 50 28 INTEREST CHARGES 15,854 13,818 NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 10,491 8,159 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX) 8,517 - NET INCOME 19,008 8,159 PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57 EARNINGS APPLICABLE TO COMMON STOCK $ 18,951 $ 8,102 The common stock of SWEPCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Comprehensive Common Paid-in Retained Income (Loss) Stock Capital Earnings Total (in thousands) JANUARY 1, 2002 $135,660 $245,003 $308,915 $ - $689,578 Common Stock Dividends (18,964) (18,964) Preferred Stock Dividends (57) (57) 670,557 Comprehensive Income: Other Comprehensive Income - - Net Income 8,159 8,159 Total Comprehensive Income 8,159 MARCH 31, 2002 $135,660 $245,003 $298,053 $ - $678,716 JANUARY 1, 2003 $135,660 $245,003 $334,789 $(53,683) $661,769 Common Stock Dividends (18,199) (18,199) Preferred Stock Dividends (57) (57) 643,513 Comprehensive Income: Other Comprehensive Income (Loss), Net of Taxes: Unrealized Loss on Cash Flow Power Hedges (1,367) (1,367) Net Income 19,008 19,008 Total Comprehensive Income 17,641 MARCH 31, 2003 $135,660 $245,003 $335,541 $(55,050) $661,154 See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (in thousands) ASSETS ELECTRIC UTILITY PLANT: Production $1,503,521 $1,503,722 Transmission 575,856 575,003 Distribution 1,040,007 1,063,564 General 402,229 378,130 Construction Work in Progress 85,836 75,755 Total Electric Utility Plant 3,607,449 3,596,174 Accumulated Depreciation and Amortization 1,702,196 1,697,338 NET ELECTRIC UTILITY PLANT 1,905,253 1,898,836 OTHER PROPERTY AND INVESTMENTS 5,793 5,978 LONG-TERM RISK MANAGEMENT ASSETS 8,549 5,119 CURRENT ASSETS: Cash and Cash Equivalents 7,163 2,069 Accounts Receivable: Customers 62,237 62,359 Affiliated Companies 20,651 19,253 Allowance for Uncollectible Accounts (2,116) (2,128) Fuel Inventory 58,814 61,741 Materials and Supplies 33,806 33,539 Under-recovered Fuel Costs - 2,865 Risk Management Assets 8,110 4,388 Prepayments and Other 18,565 17,851 TOTAL CURRENT ASSETS 207,230 201,937 REGULATORY ASSETS 52,645 49,233 DEFERRED CHARGES 74,034 47,572 TOTAL ASSETS $2,253,504 $2,208,675 See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) March 31, 2003 December 31, 2002 (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 245,003 245,003 Accumulated Other Comprehensive Income (Loss) (55,050) (53,683) Retained Earnings 335,541 334,789 Total Common Shareholder's Equity 661,154 661,769 Preferred Stock 4,700 4,701 SWEPCo-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCo 110,000 110,000 Long-term Debt 637,496 637,853 TOTAL CAPITALIZATION 1,413,350 1,414,323 OTHER NONCURRENT LIABILITIES 80,142 78,494 CURRENT LIABILITIES: Long-term Debt Due Within One Year 595 55,595 Advances from Affiliates, net 103,123 23,239 Accounts Payable - General 56,856 62,139 Accounts Payable - Affiliated Companies 46,762 58,773 Customer Deposits 22,220 20,110 Taxes Accrued 60,263 19,081 Interest Accrued 12,367 17,051 Risk Management Liabilities 7,606 3,724 Over-recovered Fuel 17,090 17,226 Other 19,781 34,565 TOTAL CURRENT LIABILITIES 346,663 311,503 DEFERRED INCOME TAXES 341,398 341,064 DEFERRED INVESTMENT TAX CREDITS 43,109 44,190 REGULATORY LIABILITIES AND DEFERRED CREDITS 23,274 17,295 LONG-TERM RISK MANAGEMENT LIABILITIES 5,568 1,806 COMMITMENTS AND CONTINGENCIES (Note 7) TOTAL CAPITALIZATION AND LIABILITIES $2,253,504 $2,208,675 See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Three Months Ended March 31, 2003 2002 (in thousands) OPERATING ACTIVITIES: Net Income $19,008 $8,159 Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: Depreciation and Amortization 28,035 30,140 Deferred Income Taxes (4,034) (3,930) Deferred Investment Tax Credits (1,081) (1,131) Cumulative Effect of Accounting Changes (8,517) - Mark-to-Market of Risk Management Contracts (1,462) 7,695 Changes in Certain Assets and Liabilities: Accounts Receivable (net) (1,288) (9,762) Fuel, Materials and Supplies 2,660 (18,504) Accounts Payable (17,294) (2,646) Taxes Accrued 41,182 27,254 Deferred Property Taxes (27,945) (27,217) Fuel Recovery 2,729 10,391 Change in Other Assets 1,461 9,511 Change in Other Liabilities (9,120) (7,260) Net Cash Flows From Operating Activities 24,334 22,700 INVESTING ACTIVITIES: Construction Expenditures (25,702) (11,715) Proceeds from Sale of Assets and Other 284 - Net Cash Flows Used For Investing Activities (25,418) (11,715) FINANCING ACTIVITIES: Retirement of Long-term Debt (55,450) (150,450) Change in Advances from Affiliates (net) 79,884 154,959 Dividends Paid on Common Stock (18,199) (18,964) Dividends Paid on Cumulative Preferred Stock (57) (57) Net Cash Flows From (Used For) Financing Activities 6,178 (14,512) Net Increase (Decrease) in Cash and Cash Equivalents 5,094 (3,527) Cash and Cash Equivalents at Beginning of Period 2,069 5,415 Cash and Cash Equivalents at End of Period $ 7,163 $ 1,888 Supplemental Disclosure: Cash (received) paid for interest net of capitalized amounts was $17,963,000 and $10,203,000 and for income taxes was ($755,000) and $8,581,000 in 2003 and 2002, respectively. See Notes to Financial Statements beginning on page L-1.
COMBINED NOTES TO FINANCIAL STATEMENTS MARCH 31, 2003 (UNAUDITED) The notes to financial statements that follow are a combined presentation for AEP and its subsidiary registrants. The following list indicates the registrants to which the footnotes apply: 1. General AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 2. Significant Accounting Policies and New Accounting Pronouncements AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 3. Extraordinary Items and Cumulative Effect AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 4. Goodwill and Other Intangible Assets AEP, SWEPCo 5. Rate Matters AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 6. Customer Choice and Industry Restructuring AEP, APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC 7. Commitments and Contingencies AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 8. Guarantees AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, 9. Sustained Earnings Improvement Initiative AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 10. Dispositions, Discontinued Operations and Assets Held for Sale AEP, APCo, CSPCo, I&M, KPCo, OPCo 11. Business Segments AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC 12. Leases AEP, OPCo 13. Minority Interest in Finance Subsidiary AEP 14. Financing and Related Activities AEP, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
1. GENERAL The accompanying unaudited interim financial statements should be read in conjunction with the 2002 Annual Report as incorporated in and filed with the Form 10-K. Certain prior period financial statement items have been reclassified to conform to current period presentation. These items include the effects of discontinued operations, gains and losses associated with derivative trading contracts presented on a net basis in accordance with EITF 02-3, and counterparty netting in accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" and EITF Topic D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No. 39". Such reclassifications had no effect of previously reported Net Income. In addition, management determined that certain amounts were misclassified in AEP's 2002 Consolidated Statement of Operations resulting from errors in the coding of certain intercompany transactions and transactions associated with our UK operations. As a result, in the first quarter of 2002 Gas Pipeline and Storage revenues decreased by $47 million, Investments revenue decreased by $10 million, Fuel for Electric Generation decreased by $27 million, and Purchased Gas for Resale decreased by $58 million. Expenses for Maintenance and Other Operation increased by $21 million and Taxes Other Than Income Taxes increased by $7 million. These revisions had no effect on Operating Income or Net Loss. In the opinion of management, the unaudited interim 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. SIGNIFICANT ACCOUNTING POLICIES AND NEW ACCOUNTING PRONOUNCEMENTS Significant Accounting Policies Components of Accumulated Other Comprehensive Income (Loss) - Other comprehensive income (loss) is included on the balance sheet in the equity section. The following table provides the components that comprise the balance sheet amount in Accumulated Other Comprehensive Income (Loss) for AEP: March 31, December 31, 2003 2002 Components (in millions) Foreign Currency Translation Adjustments $ 17 $ 4 Unrealized Losses on Securities (1) (2) Unrealized Losses on Cash Flow Hedges (38) (16) Minimum Pension Liability (580) (595) $(602) $(609) Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as of March 31, 2003, and December 31, 2002 is shown in the following table. March 31, December 31, 2003 2002 Components (in thousands) Unrealized Losses on Cash Flow Hedges: APCo $ (14,438) $ (1,920) CSPCo (7,610) (267) I&M (8,143) (286) KPCo (2,543) 322 OPCo (10,477) (738) PSO (1,239) (42) SWEPCo (1,415) (48) TCC (1,054) (36) TNC (436) (15) Non-Registrants 9,220 (13,368) $ (38,135) $(16,398) Minimum Pension Liability: APCo $(70,162) $(70,162) CSPCo (59,090) (59,090) I&M (40,201) (40,201) KPCo (9,773) (9,773) OPCo (66,524) (72,148) PSO (54,489) (54,431) SWEPCo (53,635) (53,635) TCC (73,124) (73,124) TNC (30,755) (30,748) Non-Registrants (121,879) (131,898) $(579,632) $(595,210)
The following tables represent the activity in Other Comprehensive Income (Loss) related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at March 31, 2003: Domestic Domestic Foreign AEP Power Gas Currency Interest Rate Consolidated (in millions) Accumulated OCI, December 31, 2002 $ (1) $ - $(3) $(12) $(16) Changes in Fair Value (a) (65) 8 5 6 (46) Reclassifications from OCI to Net Income (b) 23 - - 1 24 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(43) $ 8 $ 2 $ (5) $(38)
APCo Domestic Foreign APCo Power Currency Interest Rate Consolidated (in thousands) Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920) Changes in Fair Value (a) (19,201) - (104) (19,305) Reclassifications from OCI to Net Income (b) 6,649 2 136 6,787 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(12,946) $(188) $(1,304) $(14,438)
CSPCo Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (267) Changes in Fair Value (a) (11,251) Reclassifications from OCI to Net Income (b) 3,908 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(7,610) I&M Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (286) Changes in Fair Value (a) (12,039) Reclassifications from OCI to Net Income (b) 4,182 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(8,143)
KPCo Domestic KPCo Power Interest Rate Consolidated (in thousands) Accumulated OCI, December 31, 2002 $ (103) $425 $ 322 Changes in Fair Value (a) (4,357) (43) (4,400) Reclassifications from OCI to Net Income (b) 1,513 22 1,535 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(2,947) $404 $(2,543)
OPCo Domestic Foreign OPCo Power Currency Consolidated (in thousands) Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738) Changes in Fair Value (a) (14,928) - (14,928) Reclassifications from OCI to Net Income (b) 5,186 3 5,189 Accumulate OCI Derivative Gain (Loss) March 31, 2003 (c) $(10,096) $(381) $(10,477)
PSO Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (42) Changes in Fair Value (a) (1,833) Reclassifications from OCI to Net Income (b) 636 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(1,239) SWEPCo Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (48) Changes in Fair Value (a) (2,094) Reclassifications from OCI to Net Income (b) 727 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(1,415) TCC Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (36) Changes in Fair Value (a) (1,559) Reclassifications from OCI to Net Income (b) 541 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $(1,054) TNC Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (15) Changes in Fair Value (a) (645) Reclassifications from OCI to Net Income (b) 224 Accumulated OCI Derivative Gain (Loss) March 31, 2003 (c) $ (436) (a) Changes in fair value - Changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (b) Reclassifications from AOCI to net income - Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. (c) Accumulated OCI Derivative Gain (Loss) March 31, 2003 - Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders' equity on the balance sheet. Approximately $31 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at March 31, 2003 are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is five years. Common Stock Options and Restricted Shares - AEP has two stock-based employee compensation plans with outstanding stock options. AEP accounts for these plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related Interpretations. No stock-based employee compensation expense is reflected in AEP's earnings, as all options granted under these plans had exercise prices equal to or above the market value of the underlying common stock on the date of grant. AEP awarded 102,513 restricted stock units to certain AEP employees in March 2003. The units vest in equal one-third increments in January 2004, 2005 and 2006. At each vesting date, shares will be issued at no cost to the employee. In accordance with APB 25, the compensation expense of approximately $2.3 million will be expensed over the vesting period of the units. The value of the units was based on a $21.95 per share value at the grant date. The amount of compensation expense recognized during the first quarter of 2003 in AEP's Consolidated Statements of Operations was $463 thousand, pre-tax. The following table illustrates the effect on AEP's Net Income (Loss) and earnings (loss) per share as if AEP had applied the fair value recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based Compensation", to stock-based employee compensation awards:
Three Months Ended March 31, 2003 2002 (in millions, except per share data) Net Income (loss), as reported $ 440 $(169) Add: Stock-based compensation expense included in reported net income, net of related tax effects - (a) - Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (1) (2) Pro Forma Net Income (Loss) $ 439 $ (171) Earnings (Loss) per Share: Basic - as Reported $1.24 $(0.52) Basic - Pro Forma 1.23 (0.53) Diluted - as Reported $1.24 $(0.52) Diluted - Pro Forma 1.23 (0.53) (a) Compensation expense related to restricted units during the first quarter of 2003 was $301 thousand, net of tax.
New Accounting Pronouncements AEP implemented SFAS 143, "Accounting for Asset Retirement Obligations", effective January 1, 2003 which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred. Upon establishment of a legal liability, SFAS 143 requires a corresponding asset to be established which will be depreciated over its useful life. SFAS 143 requires that a cumulative effect of change in accounting principle be recognized for the cumulative accretion and accumulated depreciation that would have been recognized had SFAS 143 been applied to existing legal obligations for asset retirements. In addition, the cumulative effect of change in accounting principle is favorably affected by the reversal of accumulated removal cost that had previously been recorded for generation that does not qualify as a legal obligation which was collected in depreciation rates by certain formerly regulated subsidiaries. AEP has completed a review of its asset retirement obligations and concluded that at present, it has related legal liabilities for nuclear decommissioning costs for its Cook Plant and its partial ownership in the South Texas Project, as well as liabilities for the retirement of certain ash ponds, wind farms, the U.K. Plants, and certain coal mining facilities. Since AEP presently recovers its nuclear decommissioning costs in its regulated cash flow and thus had existing balances recorded for such nuclear retirement obligations, it recognized the cumulative difference in the amount already provided through rates versus the new methodology of SFAS 143, as a regulatory asset or liability. Similarly, a regulatory asset was recorded for the cumulative effect of certain retirement costs for ash ponds related to AEP's regulated operations. AEP recorded an unfavorable cumulative effect of $45.4 million after tax for the non-regulated operations ($38.0 million related to Ash Ponds and $7.4 million related to U.K. Plants, Wind Mills and Coal Operations). Certain of AEP's operating companies have recorded in Accumulated Depreciation and Amortization, removal costs collected from rate payers for certain assets that do not have associated legal asset retirement obligations. To the extent that such operating companies have now been deregulated, AEP reversed the balance of such removal costs, totaling $287.2 million after tax, from accumulated depreciation which resulted in a net favorable cumulative effect. However, AEP did not adjust the balance of such removal costs for its regulated operations, and in accordance with the present method of recovery, will continue to record such amounts through depreciation expense and accumulated depreciation. AEP estimates that it has approximately $1.2 billion of such regulatory liabilities recorded in Accumulated Depreciation and Amortization as of both March 31, 2003 and December 31, 2002. The following is a summary by registrant of the regulatory liabilities for removal costs included in Accumulated Depreciation and Amortization: March 31, 2003 December 31,2002 (in millions) AEGCo $ 28.4 $ 28.0 APCo 94.5 94.6 CSPCo 96.7 96.0 I&M 252.7 250.5 KPCo 21.9 23.7 OPCo 96.2 97.0 PSO 198.9 202.6 SWEPCo 220.7 219.5 TCC 97.7 97.5 TNC 74.7 75.0 Non-Registrants 0.5 0.5 $1,182.9 $1,184.9 The net favorable cumulative effect of the change in accounting principle consists of the following: Pre-tax After-tax Income (Loss) Income (Loss) (in millions) Ash Ponds $ (62.8) $ (38.0) UK Plants, Wind Mills and Coal Operations (11.3) (7.4) Reversal of Cost of Removal 472.6 287.2 Total $ 398.5 $ 241.8
The following is a summary by registrant of the cumulative effect of changes in accounting principles: Pre-tax Income (Loss) After-tax Income(Loss) U. K. Plants, U. K. Plants, Wind Mills Reversal of Wind Mills Reversal of and Coal Cost of and Coal Cost of Removal Ash Ponds Operations Removal Ash Ponds Operations (in millions) AEGCo $ - $ - $ - $ - $ - $ - APCo (18.2) - 146.5 (11.4) - 91.7 CSPCo (7.8) - 56.8 (4.7) - 33.9 I&M - - - - - - KPCo - - - - - - OPCo (36.8) - 250.4 (21.9) - 149.3 SWEPCo - - 13.0 - - 8.4 TCC - - - - - - TNC - - 4.7 - - 3.1 Other - (11.3) 1.2 - (7.4) 0.8 $(62.8) $(11.3) $ 472.6 $(38.0) $(7.4) $287.2
AEP has identified, but not recognized, asset retirement obligation liabilities related to electric transmission and distribution and gas distribution assets, as a result of certain easements on property on which AEP has assets. Generally, such easements are perpetual and require only the retirement and removal of AEP's assets upon the cessation of the property's use. The retirement obligation is not estimable for such easements since AEP plans to use its properties indefinitely. The retirement obligation would only be recognized if and when AEP abandons or ceases the use of specific easements.
The following is a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations: U.K. Plants, Wind Mills Nuclear Ash and Coal Decommissioning Ponds Operations Total (in millions) Asset Retirement Obligation Liability at January 1, 2003 $718.3 $69.8 $37.2 $825.3 Accretion expense 12.7 1.4 0.4 14.5 Asset Retirement Obligation Liability at March 31, 2003 $731.0 $71.2 $37.6 $839.8
The following is a reconciliation of beginning and ending aggregate carrying amounts of asset retirement obligations by registrant following the adoption of SFAS 143: Balance At Balance at January 1, 2003 Accretion March 31, 2003 (in millions) AEGCo (a) $ 1.1 $ - $ 1.1 APCo (a) 20.1 0.4 20.5 CSPCo (a) 8.1 0.2 I&M (b) 516.1 9.0 525.1 OPCo (a) 39.5 0.8 40.3 TCC (c) 203.2 3.8 207.0 Other (d) 37.2 0.3 37.5 $825.3 $14.5 $839.8 (a) Consists of asset retirement obligations related to ash ponds. (b) Consists of asset retirement obligations related to ash ponds ($1.1 million at March 31, 2003) and nuclear decommissioning costs for the Cook Plant ($524 million at March 31, 2003). (c) Consists of asset retirement obligations related to nuclear decommissioning costs for STP. (d) Consists of asset retirement obligations related to wind farms, the U.K. plants and certain coal mining facilities.
Accretion expense is included in Maintenance and Other Operation in AEP's accompanying Consolidated Statements of Operations and in Other Operation expense in the Income Statements of the other individual registrants. As of March 31, 2003 and December 31, 2002, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $706 million and $716 million, respectively, recorded in Other Assets on AEP's Consolidated Balance Sheets. Pro forma net income and earnings per share have not been presented for the quarter ended March 31, 2002 or the years ended December 31, 2002, 2001 and 2000 because the pro forma application of SFAS 143 would result in pro forma net income and earnings per share not materially different from the actual amounts reported for those periods. The following is a summary by registrant of the pro forma liability for asset retirement obligations which has been calculated as if SFAS 143 had been adopted as of the beginning of each period presented: December 31, 2002 December 31,2001 (in millions) AEGCo $ 1.0 $ 1.0 APCo 20.2 18.7 CSPCo 8.1 7.5 I&M 516.1 481.4 KPCo - - OPCo 39.5 36.5 PSO - - SWEPCo - - TCC 203.2 188.8 TNC - - Non-Registrants 37.2 35.3 $825.3 $769.2 Rescission of EITF 98-10 In October 2002, the Emerging Issues Task Force of the FASB reached a final consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Contracts under Issue No. 98-10 and 00-17" (EITF 02-3). See Note 3. FASB Stock-based Compensation Project In March 2003, the FASB added a project to address issues related to share-based payments. In April 2003, the FASB decided that goods and services, including employee stock options, received in exchange for stock-based compensation should be recognized in the income statement as an expense, with the cost measured at fair value. An exposure draft is expected by the end of this year and a final statement could be effective in 2004. SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends SFAS 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 also amends certain other existing pronouncements. SFAS 149 is effective for AEP for contracts entered into or modified after June 30, 2003. AEP and its subsidiaries are evaluating the impact of adopting the requirements of SFAS 149. 3. EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT Cumulative Effect of Accounting Changes - SFAS 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment. The implementation of SFAS 142 resulted in a $350 million after tax net transitional loss in 2002 for the U.K. and Australian operations and is reported in AEP's Consolidated Statements of Operations as a cumulative effect of accounting change. SFAS 143, "Accounting for Asset Retirement Obligations", (see Note 2) is effective for AEP on January 1, 2003. SFAS 143 generally applies to legal obligations associated with the retirement of long-lived assets. A company is required to recognize an estimated liability for any legal obligations associated with the future retirement of its long-lived assets. The liability is measured at fair value and is capitalized as part of the related asset's capitalized cost. The increase in the capitalized cost is included in determining depreciation expense over the expected useful life of the asset. The catch-up effect of adopting SFAS 143 will be recorded as a cumulative effect of an accounting change. Additionally, because the asset retirement obligation is recorded initially at fair value, accretion expense (similar to interest) will be recognized each period as an operating expense in the statement of operations. AEP has recorded $242 million in after tax income related to the recording of Asset Retirement Obligations in AEP's Consolidated Statements of Operations as a cumulative effect of accounting change. EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also eliminate any basis for recognizing physical inventories at fair value other than as provided by GAAP. The consensus to rescind EITF 98-10 is effective for all new contracts entered into (and physical inventory purchased) after October 25, 2002. The consensus is effective for fiscal periods beginning after December 15, 2002, and applies to all energy trading contracts that existed on or before October 25, 2002 that remain in effect as of the date of implementation, January 1, 2003. Effective January 2003, nonderivative energy contracts entered into prior to October 25, 2002 are required to be accounted for on a settlement basis and inventory is required to be presented at the lower of cost or market. The effect of implementing this consensus is reported as a cumulative effect of an accounting change. Such contracts and inventory are accounted for at fair value through December 31, 2002. Energy contracts that qualify as derivatives were accounted for at fair value under SFAS 133. AEP has recorded a $49 million after tax charge against net income as Accounting for Risk Management Contracts in AEP's Consolidated Statements of Operations in Cumulative Effect of Accounting Changes. This amount will be recognized when the positions settle.
See table below for details of the Cumulative Effect of Accounting Changes. Three Months Ended March 31, Description 2003 2002 (in millions) Accounting for Risk Management Contracts (EITF 02-3) $(49) $ - Asset Retirement Obligations (SFAS 143) 242 - Goodwill and Other Intangible Assets - (350) Total $193 $(350) The following is a summary by registrant of the cumulative effect of changes in accounting principles for the adoptions of SFAS 143 and EITF 02-3: SFAS 143 Cumulative Effect EITF 02-3 Cumulative Effect Pre-tax After-tax After-tax Income Income Income (Loss) (Loss) Pre-tax (Loss) Income (Loss) (in millions) (in millions) APCo $128.3 $ 80.3 $ (4.7) $ (3.0) CSPCo 49.0 29.3 (3.1) (2.0) I&M - - (4.9) (3.2) KPCo - - (1.7) (1.1) OPCo 213.6 127.3 (4.2) (2.7) SWEPCo 13.0 8.4 0.2 0.1 TCC - - 0.2 0.1 TNC 4.7 3.1 - - Other (10.1) (6.6) (49.5) (37.3) $398.5 $241.8 $(67.7) $(49.1)
4. GOODWILL AND OTHER INTANGIBLE ASSETS Goodwill The changes in the carrying amount of goodwill for the three months ended March 31, 2003 by operating segment are: Investments Utility Gas U.K. AEP Operations Operations Operations Other Consolidated (in millions) Balance January 1, 2003 $37.1 $306.3 $11.1 $41.5 $396.0 Foreign currency exchange rate changes - - (0.3) - (0.3) Balance March 31, 2003 $37.1 $306.3 $10.8 $41.5 $395.7 Acquired Intangible Assets The gross carrying amount, accumulated amortization and amortization life by major asset class are shown in the following table: March 31, 2003 December 31, 2002 Gross Carrying Gross Amortization Amount Accumulated Carrying Accumulated Life Amortization Amount Amortization (in millions) Software and customer list 2 $ 0.5 $0.3 $ 0.5 $0.2 Software acquired 3 0.4 - 0.5 - Patent 5 0.1 - 0.1 - administration of contracts 7 2.4 0.6 2.4 0.6 Purchased technology 10 10.3 1.3 10.3 1.0 Advanced royalties 10 29.4 5.4 29.4 4.7 Total $43.1 $7.6 $43.2 $6.5 Amortization of intangible assets was $1.2 million ($1.1 million net of foreign currency translation) and $1.0 million (no foreign currency translation) for the three months ended March 31, 2003 and March 31, 2002. Estimated aggregate amortization expense is $4.4 million for each year 2004 through 2006, $4.3 million in 2007, $4.1 million in 2008 and $4.0 million in 2009. Fluctuations in the gross carrying values since December 31, 2002 represent changes in the foreign currency exchange rate. Intangible assets subject to amortization are recorded in Other Assets in the AEP Consolidated Balance Sheets.
5. RATE MATTERS Fuel in SPP - Affecting AEP, SWEPCo and TNC As discussed in Note 6 of the 2002 Annual Report, in 2001, the PUCT delayed the start of customer choice in the SPP area of Texas. In May 2003, the PUCT approved a stipulation that delays competition in the SPP areas of Texas until no sooner than January 1, 2007. All of SWEPCo's Texas service territory and a small portion of TNC's service territory are in the SPP. SWEPCo's existing Texas fuel cost recovery procedures will continue until competition begins. SWEPCo will continue to set fuel factors and determine final fuel costs in fuel reconciliation proceedings during the SPP delay period. The PUCT has ruled that TNC fuel factors in the SPP area will be based upon the price-to-beat fuel factors offered by the retail electric provider (REP) in the ERCOT portion of TNC's service territory. TNC filed with the PUCT in 2002 to determine the most appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the PUCT issued an order adopting the methodology proposed in TNC's filing, with adjustments, should be used to reconcile fuel costs in its SPP area. The adjustments removed $3.71 per MWH from reconcilable fuel expense. This adjustment will reduce revenues received from TNC's SPP customers by approximately $400,000 annually. These customers are now served by SWEPCo's REP. TNC Fuel Reconciliation - Affecting AEP and TNC In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 2000 through December 2001 will be the final fuel reconciliation for TNC's ERCOT service territory. At December 31, 2001, the under-recovery balance associated with TNC's ERCOT service area was $27.5 million including interest. During the reconciliation period, TNC incurred $293.7 million of eligible fuel costs serving both ERCOT and SPP retail customers. TNC also requested authority to surcharge its SPP customers. TNC's SPP customers will continue to be subject to fuel reconciliations until competition begins in SPP. The under-recovery balance at December 31, 2001 for TNC's service within SPP was $0.7 million including interest. In March 2003, the Administrative Law Judges (ALJ) in this proceeding filed their Proposal for Decision (PFD). The PFD recommends that TNC's under-recovered retail fuel balance be reduced by approximately $12.5 million. In March 2003, TNC established a reserve of $13 million, including interest, based on the PFD's recommendations. On April 22, 2003, TNC and intervenors in this proceeding filed exceptions to the PFD. The PUCT is scheduled to consider the PFD on May 22, 2003 and is expected to issue a final order by mid 2003. Any further adverse ruling from the PUCT could have a material impact on future results of operations, cash flows and financial condition. TCC Fuel Reconciliation - Affecting AEP and TCC In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This reconciliation for the period of July 1998 through December 2001 will be the final fuel reconciliation. At December 31, 2001, the over-recovery balance for TCC was $63.5 million including interest. During the reconciliation period, TCC incurred $1.6 billion of eligible fuel and fuel-related expenses. Recommendations from intervening parties were received in April 2003 with hearings scheduled in May 2003. Intervening parties have recommended disallowances totaling $170 million. In March 2003, the ALJ hearing the TNC final fuel reconciliation, discussed above, issued a PFD in the TNC proceeding. Various issues addressed in TNC's proceeding may also be applicable to TCC's proceeding. Consequently, TCC established a reserve for potential adverse rulings of $27 million during the first quarter of 2003. A final order is expected in late 2003. An adverse ruling from the PUCT in excess of the reserve could have a material impact on future results of operations, cash flows and financial condition. Additional information regarding the 2004 true-up proceeding for TCC can be found in Note 6 "Customer Choice and Industry Restructuring". FERC Wholesale Fuel Complaints - Affecting AEP and TNC As discussed in the 2002 Annual Report, certain TNC wholesale customers filed a complaint with FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997. Negotiations to settle the complaint and update the contracts have resulted in new contracts. Consequently, an offer of settlement will be filed at FERC regarding the fuel complaint. Management is unable to predict whether FERC will approve this offer of settlement which is not expected to have a significant impact on TNC's financial condition. In March 2002, TNC recorded a provision for refund of $2.2 million before income taxes. The actual refund and final resolution of this matter could differ materially from this estimate and may have a negative impact on future results of operations, cash flow and financial condition. Environmental Surcharge Filing - Affecting AEP and KPCo In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff (annual revenue increase of approximately $21 million) to recover the cost of emissions control equipment being installed at Big Sandy Plant. See NOx Reductions in Note 7. In March 2003, the KPSC granted approximately $18 million of the request. Rate relief of $1.7 million annually will be effective in May 2003. In July 2003, additional annual rate relief of $16.2 million will become effective. The recovery of such amounts is intended to offset KPCo's cost of compliance with the Clean Air Act. PSO Rate Review - Affecting AEP and PSO In February 2003, the Director of the OCC filed an application requiring PSO to file all documents necessary for a general rate review before August 1, 2003. Management is unable to predict the ultimate effect of this review on PSO's rates. FERC Long-term Contracts - Affecting AEP and AEP East and AEP West companies In September 2002, the FERC voted to hold hearings to consider requests from certain wholesale customers located in Nevada and Washington to break long-term contracts which they allege are "high-priced". At issue are long-term contracts entered during the California energy price spike in 2000 and 2001. The complaints allege that AEP sold power at unjust and unreasonable prices. The FERC delayed hearings to allow the parties to hold settlement discussions. In January 2003, the FERC settlement judge assigned to the case indicated that the parties' settlement efforts were not progressing and he recommended that the complaint be placed back on the schedule for a hearing. In February 2003, AEP and one of the customers agreed to terminate their contract. The customer withdrew its FERC complaint and paid $59 million to AEP. As a result of the contract termination, AEP reversed $69 million of unrealized mark-to-market gains previously recorded, resulting in a $10 million pre-tax loss. In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery. In late 2001, the utilities filed complaints that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were consummated. The ALJ rejected the utilities' complaint, held that the markets for future delivery were not dysfunctional, and that the utilities had failed to demonstrate that the public interest required that changes be made to the contracts. The ALJ's order is preliminary and is subject to review by the FERC. At a hearing held in April 2003, the utilities asked FERC to void the long-term contracts. The FERC will likely rule on the ALJ's order in 2003. Management is unable to predict the outcome of these proceedings or their impact on future results of operations. 6. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING As discussed in the 2002 Annual Report, customer choice began in four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events occurring in 2003 related to customer choice and industry restructuring. Ohio Restructuring - Affecting AEP, CSPCo and OPCo On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users-Ohio and American Municipal Power-Ohio filed a complaint with the PUCO alleging that CSPCo and OPCo have violated the PUCO's orders regarding implementation of their transition plan and violated other applicable law by failing to participate in an RTO. The complaintants seek, among other relief, an order from the PUCO: o suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred o pricing standard offer electric generation effective January 1, 2006 at the market price used by CSPCo and OPCo in their 1999 transition plan filings to estimate transition costs and o imposing a $25,000 per company forfeiture for each day AEP fails to comply with its commitment to transfer control of transmission assets to an RTO Due to the FERC's reversal of its previous approval of our RTO filings and state legislative and regulatory developments, CSPCo and OPCo have been delayed in the implementation of their RTO participation plans. We continue to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In this regard on December 19, 2002, CSPCo and OPCo filed an application with the PUCO for approval of the transfer of functional control over certain of their transmission facilities to PJM. In February 2003, the PUCO consolidated the June complaint with our December application. CSPCo's and OPCo's motion to dismiss the complaint has been denied by the PUCO and the PUCO affirmed that ruling in rehearing. All further action in the consolidated case has been stayed "until more clarity is achieved regarding matters pending at the FERC and elsewhere". Management is unable to predict the timing of the AEP's East companies' participation in PJM, or the outcome of these proceedings before the PUCO. On March 20, 2003, the PUCO commenced a statutorily-required investigation concerning the desirability, feasibility and timing of declaring retail ancillary, metering or billing and collection service supplied to customers within the certified territories of electric utilities a competitive retail electric service. The PUCO sent out a list of questions and set June 6, 2003 and July 7, 2003, as the dates for initial responses and replies, respectively. Management is unable to predict the timing or the outcome of this proceeding. Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC As discussed in the 2002 Annual Report, on January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in other areas of Texas including the SPP area in which SWEPCo operates. In May 2003, the PUCT approved a stipulation that delays competition in the SPP area until at least January 1, 2007. A 2004 true-up proceeding will determine the amount of stranded costs, final fuel balance, net regulatory assets, certain environmental costs, accumulated excess earnings, excess of price-to-beat revenues over market prices subject to certain conditions and limitations (Retail clawback), and the difference between the price of power obtained through the legislatively-mandated capacity auctions and the power costs used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and other restructuring issues. The Texas Legislation allows for several alternative methods to be used to value stranded costs in the final 2004 true-up proceeding including the sale or exchange of generation assets, stock valuation or the use of an ECOM model. Only TCC has stranded costs under the Texas Legislation. In late 2002, TCC decided to obtain a market value of generating assets for purposes of determining stranded costs for the 2004 true-up proceeding and filed a plan of divestiture with the PUCT seeking approval of a sales process for all of its generating facilities. Such sales would quantify the actual stranded costs. The amount of stranded costs under this market valuation methodology will be the amount by which net book value of TCC's generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets. It is anticipated that any such sale will result in significant stranded costs for purposes of TCC's 2004 true-up proceeding. The filing included a request for the PUCT to issue a declaratory order that TCC's 25.2% ownership interest in its nuclear plant, STP, can be sold to value stranded costs. Intervenors to this proceeding, including the PUCT Staff, made filings to dismiss TCC's filing claiming that the PUCT does not have the authority to issue a declaratory order. The intervenors also argued that the proper time to address the sales process is after the plants are sold during the 2004 true-up proceeding. Since the bidding process is not expected to be completed before mid-2004, TCC requested that the 2004 true-up proceeding be scheduled after completion of the divestiture of the generating assets. In March 2003, the PUCT dismissed TCC's divestiture filing, determining that it was more appropriate to address the nuclear asset stranded costs valuation in a rulemaking proceeding. The PUCT approved a rule, in May 2003, that allows the value obtained by selling nuclear assets to be used in determining stranded costs. Since the PUCT also dismissed the request to certify the proposed divestiture plan, the divestiture plan utilized by TCC will still be subject to a prudency review in the 2004 true-up proceedings. The PUCT also initiated a rulemaking regarding the timing of the 2004 true-up proceedings scheduling TNC's filing in May 2004 and TCC's filing in September 2004. Texas Legislation also requires that electric utilities and their affiliated power generation companies (PGC) sell at auction in 2002 and 2003 at least 15% of the PGC's Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation and liquidity. Actual market power prices received in the state mandated auctions will replace the PUCT's earlier estimates of those market prices used in the ECOM model to calculate the stranded cost for TCC for the 2004 true-up proceeding. The decision to determine stranded costs using market prices, instead of using the PUCT's ECOM model estimates, enabled TCC to record a $262 million regulatory asset and related revenues which represents the quantifiable amount of stranded costs for the year 2002 related to the wholesale prices. In the first quarter of 2003, TCC recorded an additional $56 million regulatory asset and related revenues for stranded costs. Prior to the decision to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited the recognition of the regulatory assets and revenues as there was no way to quantify stranded costs. As discussed above, a defined process is required in order to determine the amount of stranded costs related to generation facility for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT during 2002 provided such a process. When the divestiture and the 2004 true-up proceeding are completed, TCC can securitize stranded costs that are in excess of current securitized amounts. The annual costs of securitization will be recovered through a non-bypassable rate surcharge by the regulated transmission and distribution (T&D) utility over the life of the securitization bonds. Any stranded costs and other true-up amounts not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable competitive transition charge to T&D utility customers. In the event TCC and TNC are unable after the 2004 true-up proceeding to recover all or a portion of 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. Arkansas Restructuring - Affecting AEP and SWEPCo In February 2003, Arkansas repealed customer choice legislation originally enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71 regulatory accounting which had been discontinued in 1999. The reapplication of SFAS 71 had an insignificant effect on results of operations for the first quarter of 2003. As a result of reapplying SFAS 71, derivative contract gains/losses for transactions within AEP's traditional marketing area allocated to Arkansas will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. West Virginia Restructuring - Affecting AEP and APCo APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first quarter of 2003 after new developments during the quarter prompted an analysis of the probability of deregulation becoming effective. In 2000, the WVPSC issued an order approving an electricity restructuring plan, which the WV Legislature approved by joint resolution. The joint resolution provided that the WVPSC could not implement the plan until the WV legislature made tax law changes necessary to preserve the revenues of state and local governments. In the 2001 and 2002 legislative sessions, the WV Legislature failed to enact the required legislation that would allow the WVPSC to implement the restructuring plan. Due to this lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring during the summer of 2002. 475 In the 2003 legislative session, the WV Legislature failed to enact the required tax legislation. Also, a March 2003 WV Legislative Bill clarified the jurisdiction of the WVPSC over electric generation facilities in WV. In March 2003, APCo's outside counsel advised us that deregulation in West Virginia was no longer probable and confirmed facts relating to the WVPSC's jurisdiction and rate authority over APCo's WV generation. APCo has concluded that deregulation of the WV generation business is no longer probable and operations in WV meet the requirements to apply SFAS 71. The result of reapplying SFAS 71 in WV had an insignificant effect on results of operations for the first quarter of 2003. As a result, derivative contract gains/losses related to transactions within AEP's traditional marketing area allocated to WV will not affect income until settled. That is, such positions will be recorded on the balance sheet as either a regulatory asset or liability until realized. Positions outside AEP's traditional marketing area will continue to be market-to-market. 7. COMMITMENTS AND CONTINGENCIES Power Generation Facility - Affecting AEP AEP has entered into agreements with Katco Funding L.P. (Katco), an unrelated unconsolidated special purpose entity. Katco has an aggregate financing commitment of $525 million and a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. Katco was formed to develop, construct, finance and lease a power generation facility to AEP. Katco will own the power generation facility and lease it to AEP after construction is completed. The lease was originally intended to be accounted for as an operating lease, therefore neither the facility nor the related obligations would be reported on AEP's balance sheet (see discussion of potential consolidation issues later in this note). Payments under the operating lease are expected to commence in the first quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW). The use of Katco allows AEP to limit its risk associated with the power generation facility once the construction phase has been completed. AEP is the construction agent for Katco. Construction is currently scheduled to be completed by the first quarter of 2004, subject to unforeseen events beyond AEP's control. In the event the project is terminated before completion of construction, AEP has the option to either purchase the facility for 100% of project costs or terminate the project and make a payment to Katco for 89.9% of project costs. DOW will use a portion of the energy produced by the facility and sell the excess energy. AEP has agreed to purchase approximately 800 MW of such excess energy from DOW. AEP will resell that energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years. Beginning May 1, 2003, AEP has certain contractual rights and obligations in connection with providing replacement energy and other products to TEM. If the project is not completed by April 30, 2004, TEM may claim that it can terminate the purchase agreement and is owed liquidating damages of approximately $17.5 million. The operating lease between Katco and AEP commences on the commercial operation date of the facility and continues until November 2006. The lease contains extension options subject to the approval of Katco, and if all extension options were exercised, the total term of the lease would be 30 years. AEP's lease payments to Katco are sufficient for Katco to make required debt payments and provide a return to the investors of Katco. At the end of each lease term, AEP may renew the lease at fair market value subject to Katco's approval, purchase the facility at its original construction cost, or sell the facility, on behalf of Katco, to an independent third party. If the facility is sold and the proceeds from the sale are insufficient to repay Katco, AEP may be required to make a payment to Katco for the difference between the proceeds from the sale and the obligations of Katco, up to 82% of the project's cost. AEP has guaranteed a portion of the obligations of its subsidiaries to Katco during the construction and post-construction periods. As of March 31, 2003, project costs subject to these agreements totaled $403 million, and total costs for the completed facility are expected to be approximately $510 million. For the 30-year extended lease term, the lease rental is a variable rate obligation indexed to three-month LIBOR. Consequently as market interest rates increase, the payments under this operating lease will also increase. Annual payments of approximately $12 million represent future minimum payments during the initial term calculated using the indexed LIBOR rate (1.38% at December 31, 2002). The Power Generation Facility collateralizes the debt obligation of Katco. AEP's maximum exposure to loss as a result of its involvement with Katco is 100% during the construction phase and up to 82% once the construction is completed. Maximum loss is deemed to be remote due to the collateralization. It is reasonably possible that under this operating lease structure AEP will consolidate Katco in the third quarter of 2003, as a result of the issuance of FASB Interpretation No. 46 "Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP would record the assets, liabilities, depreciation expense, minority interest and debt interest expense. AEP would eliminate operating lease expense. The sublease to DOW would not be affected by this consolidation. AEP is currently in the process of reviewing restructuring options for this operating lease, which could replace Katco with a new lease facility. Under these new leasing options, in accordance with FIN 46, AEP would not consolidate the assets or debt of the Power Generation Facility. Nuclear Plant Outages - Affecting AEP, I&M and TCC In April 2003, engineers at STP found a small quantity of powdery residue during inspections conducted regularly as part of refueling outages. STP officials are working closely with the NRC to safely return the unit to service. The NRC will review any corrective action prior to its implementation and restart of the unit. In April 2003, both units of Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. Management is unable to predict the length of time that the STP and Cook Plant units may be unavailable or the costs of corrective actions at this time. Cook Unit 2 was already planned for a refueling outage starting May 5. We have commitments to provide power to customers during the outages. Therefore, we will be subject to fluctuations in the market prices of electricity and purchased replacement energy could be a significant cost. Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in Note 9 of the Combined Notes to Financial Statements in the 2002 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities modified certain units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. 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 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. Management believes its maintenance, repair and replacement activities were in conformity with the Clean Air Act and intends to vigorously pursue its defense. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. 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 unless such costs can be recovered through regulated rates and market prices for electricity. In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties 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 results of operations and cash flows. NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and TCC Federal EPA issued a 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 has been upheld on appeal. The compliance date for the NOx Rule is May 31, 2004. In 2000, 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. Affected utilities, including certain AEP operating companies, petitioned the D.C. Circuit Court to review the Section 126 Rule. After review, the D.C. Circuit Court instructed Federal EPA to justify the methods it used to allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP subsidiaries and other utilities requested that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responds to the Court's remand. On April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date for the Section 126 Rule. Federal EPA published a notice in the Federal Register on May 1, 2002 advising that no changes in the growth factors used to set the NOx budgets were warranted. In June 2002, AEP subsidiaries joined other utilities and industrial organizations in seeking a review of Federal EPA's actions in the D.C. Circuit Court. This action is pending. In 2000, the Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including TCC and SWEPCo. The compliance date is May 2003 for TCC and May 2005 for SWEPCo. AEP is installing a variety of emission control technologies to reduce NOx emissions to comply with the applicable state and Federal NOx requirements. This includes selective catalytic reduction (SCR) technology on certain units and non-SCR technologies on a larger number of units. During 2001 SCR technology commenced operations on OPCo's Gavin Plant. Installation of SCR technology on Amos and Mountaineer plants was completed and commenced operation in May 2002. Construction of SCR technology at certain other AEP generating units continues. Non-SCR technologies have been installed and commenced operation on a number of units across the AEP System and additional units will be equipped with these technologies. The AEP NOx compliance plan is a dynamic plan that is continually reviewed and revised as new information becomes available on the performance of installed technologies and the cost of planned technologies. Certain compliance steps may or may not be necessary as a result of this new information. Consequently, the plan has a range of possible outcomes. Our current estimates indicate that AEP's compliance with the NOx Rule, the Texas Commission on Environmental Quality rule and the Section 126 Rule could result in required capital expenditures in the range of $1.3 billion to $1.7 billion, of which $918 million has been spent through March 31, 2003. Estimated compliance cost ranges and amounts spent by registrant subsidiaries are as follows: Estimated Amount Compliance Costs Spent (in millions) AEGCo $ 24 $ 5 APCo 463 250 CSPCo 87 54 I&M 34 8 KPCo 176 164 OPCo 495-824 404 SWEPCo 37 23 TCC 5 5 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the 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. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding filed by the Enron entities which are pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities remained unsettled at the date of Enron's bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court is not certain. In connection with the 2001 acquisition of HPL, we acquired exclusive rights to use and operate the underground Bammel gas storage facility pursuant to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years and includes the use of the Bammel storage facility and the appurtenant pipelines. We have engaged in preliminary discussions with Enron concerning the possible purchase of the Bammel storage facility and related assets, the possible resolution of outstanding issues between AEP and Enron relating to our acquisition of HPL and the possible resolution of outstanding energy trading issues. We are unable to predict whether these discussions will lead to an agreement on these subjects. If these discussions do not lead to an agreement, there may be a dispute with Enron concerning our ability to continue utilization of the Bammel storage facility and certain appurtenant pipelines under the existing agreements. We also entered into an agreement with BAM Lease Company which grants HPL the right to use approximately 65 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the Bammel gas storage facility. The Bammel Gas Trust, which purportedly owned approximately 55 billion cubic feet of the gas, had entered into a financing arrangement in 1997 with Enron and a group of banks. These banks purported to have certain rights to the gas in certain events of default. In connection with AEP's acquisition of HPL, the banks entered into an agreement granting HPL's exclusive use of the cushion gas and released HPL from liabilities and obligations under the financing arrangement. HPL was thereafter informed by the banks of a purported default by Enron under the terms of the referenced financing arrangement. In July 2002, the banks filed a lawsuit against HPL seeking a declaratory judgment that they have a valid and enforceable security interest in this cushion gas which would permit them to cause the withdrawal of this gas from the storage facility. In September 2002, HPL filed a general denial and certain counterclaims against the banks. HPL also filed a motion to dismiss. Management is unable to predict the outcome of this lawsuit or its impact on AEP's financial position, results of operations and cash flows. During 2002 and 2001, AEP expensed a total of $53 million ($34 million net of tax) for our estimated loss from the Enron bankruptcy. The amount expensed was based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management's analysis of the HPL related purchase contingencies and indemnifications. Enron has recently instituted proceedings against other energy trading counterparties challenging the practice of utilizing offsetting receivables and payables and related collateral across various Enron entities. We believe that we have the right to utilize similar procedures in dealing with payables, receivables and collateral with Enron entities by offsetting trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. An additional expense of up to $110 million may be incurred without such offsets. We believe we have legal defenses to any challenge that may be made to the utilization of such offsets but at this time are unable to predict the ultimate resolution of this issue. Shareholder Lawsuits - Affecting AEP In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging securities law violations and seeking class action certification were filed in federal District Court, Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits, members of the AEP Board of Directors and certain investment banking firms. The lawsuits claim that AEP failed to disclose that alleged "round trip" trades resulted in an overstatement of revenues, that AEP failed to disclose that AEP traders falsely reported energy prices to trade publications that published gas price indices and that AEP failed to disclose that it did not have in place sufficient management controls to prevent round trip trades or false reporting of energy prices. The plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. Also, in the first quarter of 2003, a lawsuit making essentially the same allegations and demands was filed in state Common Pleas Court, Columbus, Ohio against AEP, certain AEP executives, members of the AEP Board of Directors and AEP's independent auditor. AEP intends to vigorously defend against these actions. Also in the fourth quarter of 2002, two shareholder derivative actions were filed in state court in Columbus, Ohio against AEP and its Board of Directors alleging a breach of fiduciary duty for failure to establish and maintain adequate internal controls over AEP's gas trading operations; and, in the fourth quarter of 2002 and the first quarter of 2003, three lawsuits were filed against AEP, certain AEP executives and AEP's Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions are pending in federal District Court, Columbus, Ohio. The derivative actions and the ERISA actions are in the initial pleading stage. AEP intends to vigorously defend against these actions. California Lawsuit -Affecting AEP In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a lawsuit in Los Angeles County, California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. This case is in the initial pleading stage. AEP has filed a motion to dismiss. AEP intends to vigorously defend against this action. Bank of Montreal Claim - Affecting AEP In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals and has claimed approximately $25 million is owed to BOM by AEP which BOM subsequently has changed to approximately $34 million. In April 2003, AEP filed a lawsuit against BOM claiming BOM had acted contrary to industry practice in calculating termination and liquidation amounts and that BOM had acknowledged in March 2003 that it owed AEP approximately $68 million. Alternatively, AEP is claiming that BOM owes approximately $45 million to AEP. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Arbitration of Williams Claim - Affecting AEP In October 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries by AEP. Consequently, both parties claimed default and terminated all outstanding natural gas and electric power trading deals among the various Williams and AEP affiliates. Williams claimed that AEP owes approximately $130 million in connection with the termination and liquidation of all trading deals. AEP believes it has valid claims arising from Williams' actions and is seeking, in part, a determination that either no amount is due or that a lesser amount is due from AEP to Williams (which lesser amount is fully reserved by AEP) and the extent of any other damages and legal or equitable relief available. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Arbitration of PG&E Energy Trading, LLC Claim - Affecting AEP In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22 million was owed by AEP in connection with the termination and liquidation of all trading deals. In February 2003, PGET initiated arbitration proceedings. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial conditions. Energy Market Investigation - Affecting AEP As discussed in the 2002 Annual Report, AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission, the U.S. Department of Justice and the California attorney general during 2002. AEP's management responded to the inquiries and provided the requested information. In March 2003, AEP received a subpoena from the SEC as part of the SEC's ongoing investigation of energy trading activities. In August 2002, AEP had received an informal data request from the SEC seeking that AEP voluntarily provide information. The subpoena seeks additional information and is part of the SEC's formal investigation. AEP will continue to cooperate with the SEC. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2002 Annual Report. 8. GUARANTEES In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to recognize a liability related to issuing a guarantee, as well as additional disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of FIN 34. The initial recognition and initial measurement provisions of FIN 45 is effective on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements of FIN 45 were effective for financial statements of interim or annual periods ending after December 15, 2002. There are no liabilities recorded for all of the guarantees described below in accordance with FIN 45 as these guarantees were entered into prior to December 31, 2002 or have immaterial values which were not recorded. There is no collateral held in relation to these guarantees and there is no recourse to third parties in the event these guarantees are drawn. Certain AEP subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity trading contracts, construction contracts, insurance programs, security deposits, debt service reserves, drilling funds and credit enhancements for issued bonds. All of these LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary course of business. TCC issued one of the LOCs for credit enhancement of issued bonds. At March 31, 2003, the maximum future payments of all the LOCs are approximately $158 million with maturities ranging from April 2003 to January 2011. TCC's LOC was for approximately $40.9 million with a maturity date of November 2003. I&M's LOC was approximately $2 million with a maturity date of March 2003. Since AEP is the parent to all these subsidiaries, it holds all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn. The following AEP subsidiaries have entered into guarantees of third parties obligations: CSW Energy and CSW International have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $3.7 million, which expires June 2020. Additionally, CSW guaranteed 50% of the required debt service reserve for Polk Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk Power does not make the required debt payments, CSW has a maximum future payment exposure of approximately $4.7 million, which expires July 2010. In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to assume the revolving credit agreement, capital lease obligations, and term loan payments of the mining contractor. In the event the mining contractor defaults under any of these agreements, SWEPCo's total future maximum payment exposure is approximately $73 million with maturity dates ranging from April 2003 to February 2012. As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At March 31, 2003, the cost to reclaim the mine is estimated to be approximately $36 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation. See Note 13 "Minority Interest in Finance Subsidiary" for disclosure for the guaranteed support of AEP for Caddis Partners, LLC. AEP and its subsidiaries enter into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, AEP's exposure generally does not exceed the sale price. AEP cannot estimate the maximum potential exposure for any of these indemnifications entered prior to December 31, 2002 due to the uncertainty of future events. In the first quarter of 2003, AEP entered into several sale agreements as discussed in Note 10. These sale agreements include indemnifications with a maximum exposure of approximately $60 million. There are no liabilities recorded for any indemnifications due to the insignificant fair value of the indemnification or due to the fact that they were entered prior to December 31, 2002. AEP and its subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At March 31, 2003, the maximum potential loss for these lease agreements was approximately $25 million assuming the fair market value of the equipment is zero at the end of the lease term. The maximum potential loss by registrant is as follows: Maximum Potential Loss Subsidiary (in millions) APCo $ 0.7 CSPCo 0.5 I&M 3.3 KPCo 0.7 OPCo 2.7 PSO 2.9 SWEPCo 3.1 TCC 5.8 TNC 2.2 Other AEP Subsidiaries 3.5 Total $25.4 9. SUSTAINED EARNINGS IMPROVEMENT INITIATIVE In response to difficult conditions in AEP's business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth. Termination benefits expense relating to 1,120 terminated employees totaling $75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this amount, AEP paid $9.5 million and $51.2 million to these terminated employees in the fourth quarter of 2002 and the first quarter of 2003, respectively. The termination benefits expense was classified as Maintenance and Other Operation expense on AEP's Consolidated Statements of Operations and as Other Operation expense on the other registrants' statements of operations. No additional termination benefits expense related to the SEI initiative was recorded during the first quarter of 2003.
The following table shows the beginning and ending termination benefits accrual amounts and the total termination related payments made during the first quarter 2003. Total Termination Total Termination Payments Made During Benefits Total Termination the Accrued at 3/31/03 Benefits Three Months (in millions) Subsidiary Accrued at 12/31/02 Ended 3/31/03 Company (in millions) (in millions) AEGCo $ 0.3 $ 0.3 $ - APCo 12.2 9.3 2.9 CSPCo 4.5 3.8 0.7 I&M 13.1 9.3 3.8 KPCo 2.5 1.8 0.7 OPCo 7.1 5.4 1.7 PSO 3.0 2.4 0.6 SWEPCo 3.1 2.8 0.3 TCC 5.5 5.5 - TNC 1.6 1.6 - Other Subsidiaries 13.0 9.0 4.0 Totals $65.9 $51.2 $14.7
10. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE DISPOSITIONS In the first quarter of 2003, AEP completed a number of asset dispositions determined not to be part of its core Utility Operations: Disposition of Assets of C3 Communications On February 28, 2003, C3 Communications sold the majority of its assets for a sales price of $7.25 million. C3 received $7 million in cash and a one-year non-interest bearing note receivable of $250,000 from the purchaser. AEP provided for an $82 million pre-tax asset impairment in the fourth quarter 2002, and the effect of the sale on first quarter 2003 results of operations was not significant. Disposition of Mutual Energy Companies On December 23, 2002, AEP received PUCT regulatory approval on a sale of two of its Texas retail energy providers (REP's). As part of the REP sale, MESC received a prepayment of approximately $30 million from the purchaser. The prepaid service revenue was deferred on the books of MESC to be amortized over the two-year term of the back office service agreement. On February 28, 2003, AEP completed the sale of Mutual Energy Service Company, LLC (MESC) for $30.4 million dollars and realized a pre-tax gain of approximately $12.2 million dollars. In addition, the $27.2 million pre-tax gain which was previously deferred and was being recognized over the two-year term of a back office service agreement was recognized as part of the gain calculation in the first quarter of 2003 as no further service obligations existed for MESC.
Disposition of Water Heater Assets AEP sold its water heater rental program for $38 million and recorded a pre-tax loss of $3.9 million in the first quarter of 2003 based upon final terms of the sale agreement. AEP had provided for a $7.1 million pre-tax charge in the fourth quarter 2002 based on an estimated sales price ($3.2 million asset impairment charge and $3.9 million lease prepayment penalty). AEP, APCo, CSPCo, I&M, KPCo, and OPCo operated a program to lease electric water heaters to residential and commercial customers until a decision was reached in the fourth quarter of 2002 to discontinue the program and offer the assets for sale. See table below for detail of charges by Company: Asset Impairment Lease Prepayment Loss on Sale Charge Recorded Penalty Recorded Recorded in First Quarter Subsidiary in Fourth Quarter in Fourth Quarter 2003 (Pre-tax) Company 2002 (Pre-tax) 2002 (Pre-tax) (in millions) APCo $0.050 $0.062 $0.056 CSPCo 0.615 0.758 0.740 I&M 0.643 0.792 0.787 KPCo 0.011 0.011 0.011 OPCo 1.757 2.163 2.165 Other Non- Registrant Subsidiaries 0.126 0.156 0.161 Total $3.202 $3.942 $3.920
Disposition of AEP Gas Power Systems In 2001, AEP acquired a 75% interest in a startup company, seeking to develop low-cost peaking generator sets powered by surplus jet turbine engines. In January 2003, AEP Gas Power Systems, LLC (Gas Power) sold its assets. AEP recognized a goodwill impairment loss of $12.2 million in the first quarter of 2002, and the effect of the asset sale on the first quarter 2003 results of operations was not significant. DISCONTINUED OPERATIONS The results of operations of the entities shown below, affecting AEP, have been classified as Discontinued Operations for all periods presented. The assets and liabilities of Pushan Power Plant and Eastex were aggregated on AEP's Consolidated Balance Sheets as Assets Held for Sale and Liabilities Held for Sale (see table at the end of the Assets Held For Sale section below for more detailed information):
Pushan Power SEEBOARD CitiPower Plant Total Eastex (in millions) 2003 Revenue $ - $ - $15 $31 $ 46 2002 Revenue 383 97 15 12 507 2003 Earnings (Loss) After Tax $ - $ - $ - $(9) $(9) 2002 Earnings (Loss) After Tax 33 (11) 2 (2) 22
ASSETS HELD FOR SALE As discussed in the 2002 Annual Report, during 2002, AEP (and its registrant subsidiaries, as applicable) recorded an estimated loss on disposal of assets held for sale. Eastex In 1998, CSW began construction of a natural gas-fired cogeneration facility (Eastex) located near Longview, Texas and commercial operations commenced in December 2001. In June 2002, AEP requested that the FERC allow it to modify the FERC Merger Order and substitute Eastex as a required divestiture under the order, due to the fact that the agreed upon market-power related divestiture of a plant in Oklahoma was no longer feasible. The FERC approved the request at the end of September 2002. Subsequently, in the fourth quarter of 2002, AEP solicited bids for the sale of Eastex and several interested buyers were identified by December 2002. We still anticipate that the sale of assets will be completed by the end of 2003. The estimated pre-tax loss on sale of $218.7 million, which was based on the estimated fair value of the facility and indicative bids by interested buyers, was recorded in Discontinued Operations in AEP's Consolidated Statements of Operations during the fourth quarter 2002. Results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144. The assets and liabilities of Eastex have been included on AEP's Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Pushan Power Plant In the fourth quarter of 2002, AEP began active negotiations to sell its interest in the Pushan Power Plant (Pushan) in Nanyang, China to one of the minority interest partners. We currently anticipate negotiations to be completed by the end of 2003 with an estimated pre-tax loss on disposal of $20.0 million, based on an indicative price expression. This estimated loss was recorded in Discontinued Operations in AEP's Consolidated Statements of Operations during the fourth quarter of 2002. Results of operations of Pushan have been reclassified as Discontinued Operations in accordance with SFAS 144. The assets and liabilities of Pushan have been classified on AEP's Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Telecommunications AEP had developed businesses to provide telecommunication services to businesses and to other telecommunication companies through broadband fiber optic networks operated in conjunction with AEP's electric transmission and distribution lines. The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the difficult economic conditions in these businesses and the overall telecommunications industry, and other operating problems, the AEP Board approved in December 2002 a plan to cease operations of these businesses. AEP initiated steps to market the assets of the businesses to potential interested buyers in the fourth quarter of 2002. As a result, the assets of C3 were sold in February 2003. See "Disposition of Assets of AEP Communications" earlier in this note for further information. The sale of all telecommunication assets is expected by the end of 2003 with an estimated pre-tax impairment loss of $76 million related to AEPC and an estimated pre-tax loss in value of the investment in AFN of $13.8 million. The estimated losses are based on indicative bids by potential buyers. The estimated losses were recorded in Investment Value and Other Impairment Losses in AEP's Consolidated Statements of Operations during the fourth quarter 2002. Newgulf Facility In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility located near Newgulf, Texas (Newgulf). In October 2002, AEP began negotiations with a likely buyer of the facility. AEP still expects a sale to be completed by the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on an indicative bid by the likely buyer. This loss was recorded as Asset Impairments on AEP's Consolidated Statements of Operations during the fourth quarter 2002. Newgulf's Property, Plant and Equipment, net of accumulated depreciation, has been classified on AEP's Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Nordic Trading In October 2002, AEP announced that its ongoing energy trading operations would be centered around its generation assets. As a result, AEP took steps to exit its coal, gas, and electricity trading activities in Europe, except for those activities necessary to support the U.K. Generation operations. The Nordic Trading business acquired earlier in 2002, was made available for sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3 million consisted of impairment of goodwill of $4.0 million and impairment of assets of $1.3 million, and was included in Asset Impairments on AEP's Consolidated Statements of Operations during the fourth quarter of 2002. Management's determination of a zero fair value at the end of 2002 was based on discussions with a potential buyer. The assets and liabilities of Nordic Trading have been classified on AEP's Consolidated Balance Sheets as held for sale. The transfer of the Nordic Trading business, including the trading portfolio, to new owners was completed during the second quarter of 2003 and the impact on earnings during the second quarter of 2003 will not be significant. Excess Equipment In November 2002, as a result of a cancelled development project, AEP obtained title to a surplus gas turbine generator. AEP has been unsuccessful in finding potential buyers of the unit, including its own internal generation operators, due to an over-supply of generation equipment available for sale. Sale of the turbine is currently still projected before the end of 2003 with an estimated 2002 pre-tax loss on disposal of $23.9 million, based on market prices of similar equipment. This estimated loss was recorded in Asset Impairments on AEP's Consolidated Statements of Operations during the fourth quarter of 2002. The Other Assets have been classified on AEP's Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information. Excess Real Estate In the fourth quarter of 2002, AEP began to market an under-utilized office building in Dallas, TX obtained through the merger with CSW. Sale of the facility is still projected by the end of 2003 and an estimated pre-tax loss on disposal of $15.7 million was recorded during the fourth quarter of 2002 based on an estimated sales price. This estimated loss was included in Asset Impairments on AEP's Consolidated Statements of Operations. The property asset has been classified on AEP's Consolidated Balance Sheets as held for sale. See the tables at the end of this section for more detailed information.
The assets and liabilities of the entities held for sale at March 31, 2003 and December 31, 2002 are as follows: Pushan Power Plant Newgulf Nordic Excess Excess Eastex Facility Trading Real Estate Equipment Total At March 31, 2003 (in millions) Assets: Current Assets $20 $ 16 $ - $50 $ - $ - $ 86 Property, Plant and Equipment, Net - 149 6 - 18 - 173 Deferred Income Taxes - - - 6 - - 6 Other Assets - - - 3 - 12 15 Total Assets Held for Sale $20 $165 $ 6 $59 $18 $12 $280 Liabilities: Current Liabilities $ 6 $ 22 $ - $56 $ - $ - $ 84 Long-term Debt - 22 - - - - 22 Other Liabilities 4 49 - 2 - - 55 Total Liabilities Held For Sale $10 $ 93 $ - $58 $ - $ - $161
Pushan Excess Water Tele- Power Newgulf Nordic Real Excess Heater communica- Eastex Plant Facility Trading Estate Equipment Program tions Total At December 31, 2002 (in millions) Assets: Current Assets $15 $ 19 $ - $35 $ - $ - $ 1 $ - $ 70 Property, Plant and Equipment, Net - 132 6 - 18 - 38 6 200 Other Assets - - - 10 - 12 - - 22 Total Assets Held for Sale $15 $151 $ 6 $45 $18 $12 $39 $ 6 $292 Liabilities: Current Liabilities $ 8 $ 28 $ - $48 $ - $ - $ - $ - $ 84 Long-term Debt - 25 - - - - - - 25 Other Liabilities 4 26 - 3 - - - - 33 Total Liabilities Held For Sale $12 $ 79 $ - $51 $ - $ - $ - $ - $142
11. BUSINESS SEGMENTS In October 2002, AEP announced that it was exiting wholesale markets where it does not own assets and announced certain reassignment changes in members of the Office of the Chairman group. A further decision was later made in 2003 by the Board of Directors and management to focus on AEP's core electric utility businesses. Assets outside of domestic generation, distribution and transmission of electricity are considered to be non-core and are being evaluated and may be sold when market conditions are more favorable. In the fourth quarter of 2002, as more fully described in Note 13 of the 2002 Annual Report, management recognized pre-tax impairments totaling $1.4 billion, principally related to non-regulated assets and investments and characterized $247 million of assets and investments as Held for Sale. During 2001 and most of 2002, AEP was in the process of restructuring into two main businesses, i.e. the regulated business and the non-regulated business. The extent to which these were to be further divided into business segments was dependent on how the businesses were to be managed and how the chief operating decision maker of each business would monitor the performance of such businesses. However, until deregulation developed further, regulatory hurdles were cleared and corporate separation was achieved, management was unable to determine precisely what segments would exist for the various businesses after corporate separation. As a result of the changes in AEP's business strategy noted above, management's desire to concentrate on its core businesses, delays in corporate separation and the repeal of and/or delay of competition and deregulation in AEP's jurisdictions, a decision was made to realign the segments for financial reporting purposes in the first quarter of 2003 to reflect the manner in which AEP's chief operating decision makers (the Office of the Chairman group) now manage the business. Assets have been identified as either being core or non-core investments and are being managed as such and the results of operations are reported to senior management in this format as well as to AEP's investors in its earning releases and presentations to financial analysts. Throughout 2002, AEP's segments for financial reporting purposes were Wholesale, Energy Delivery and Other. The business activities were as follows: Wholesale - Generation of electricity for sale to retail and wholesale customers - Gas pipeline and storage facilities - Marketing and trading of electricity, gas, coal and other commodities - Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery - Domestic electricity transmission - Domestic electricity distribution Other - Energy services - Telecommunication services (reclassified as Held for Sale as of December 31, 2002) As a result of the Board of Director's and management's decision to concentrate on its core asset base and exit wholesale operations where AEP does not own assets, Wholesale will no longer be a reporting segment. AEP's core operations are now managed as vertically integrated electricity generation and energy delivery businesses. The operations are managed on an integrated basis because of the substantial impact of bundled, primarily cost-based rates and regulatory oversight on the business process, cost structure and operating results. Assets not meeting the Board of Director's and management's core strategy are classified into three Investments segments. AEP's current segments, for which discrete financial information is available, engage in business activities for which AEP earns revenues and incurs expenses. The operating results of these segments are regularly reviewed by AEP's chief operating decision maker. The segments and their related business activities are as follows: Utility Operations o Domestic generation of electricity for sale to retail and wholesale customers o Domestic electricity transmission and distribution Investments - Gas Operations o Gas pipeline and storage services Investments - UK Operations o International generation of electricity for sale to wholesale customers Investments - Other o Coal mining, bulk commodity barging operations and other energy supply businesses Management has aggregated electricity transmission, distribution and generation within Utility Operations because their economic characteristics are similar and their revenue is substantially determined by regulated jurisdictions. AEP's electricity transmission and distribution operations are entirely regulated by FERC and state regulatory jurisdictions. Electric generation sales to retail customers are determined by the respective state jurisdictions, even for customers in Ohio, Texas and Virginia which are in transition to deregulation, and whose transition rates are still determined by the respective state jurisdictions. With respect to Investments, management has aggregated data into three separate reporting groupings, due to the significance of each business and the manner in which they are operated. The Investments-Gas Operations segment includes two intra-state gas pipeline and storage operations located in Louisiana and Texas and also includes risk management activities around these assets. The Investments-UK Operations segment includes the generation of electricity for sale to wholesale customers in the UK. Investments-Other includes the coal mining operations and commodity barging operations, all of which share similar economic characteristics.
The tables below present the reformatted reportable segment information for the three months ended March 31, 2003 and 2002 based on the changes in business strategy in the first quarter of 2003. These amounts include certain estimates and allocations where necessary. Investments Utility Gas UK Reconciling Operations Operations Operations Other Adjustments Consolidated March 31, 2003 (in millions) Revenues from: External Customers $ 2,773 $1,102 $ 50 $ 155 $- $ 4,080 Other Operating Segments - 44 - 13 (57) - Net Income (Loss) 528 (37) (55) 4 - 440 Total Assets 28,840 4,513 1,493 1,775 280 (a) 36,901 March 31, 2002 Revenues from: External Customers $ 2,258 $433 $ 101 $ 200 $- $ 2,992 Other Operating Segments - 44 - 33 (77) - Net Income (Loss) 213 (48) 29 (363) - (169) Total Assets 25,056 6,241 1,648 6,905 793 (a) 40,643 (a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or Assets of Discontinued Operations. All of the registrant subsidiaries have one reportable segment. The one reportable segment is a vertically integrated electricity generation, transmission and distribution business except AEGCo, an electricity generation business, which remains unchanged. All of the registrants' other activities are insignificant. The registrant subsidiaries' operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on the business processes, cost structures and operating results.
12. LEASES OPCo has entered into an agreement with JMG Funding LLP (JMG), an unrelated unconsolidated special purpose entity. JMG has a capital structure of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from pollution control bonds and other bonds. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an operating lease. Payments under the operating lease are based on JMG's cost of financing (both debt and equity) and include an amortization component plus the cost of administration. OPCo and AEP do not have an ownership interest in JMG and do not guarantee JMG's debt. At any time during the lease, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial 15-year lease term is non-cancelable. At the end of the initial term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition cost, OPCo must pay the difference to JMG. The use of JMG allows OPCo to enter into an operating lease while keeping the tax benefits otherwise associated with a capital lease. As of March 31, 2003, unless the structure of this arrangement is changed, it is reasonably possible that OPCo will consolidate JMG in the third quarter of 2003 as a result of the issuance of FIN 46. Upon consolidation, OPCo would record the assets, liabilities, depreciation expense, minority interest and debt interest expense of JMG. OPCo would eliminate operating lease expense. OPCo's maximum exposure to loss as a result of its involvement with JMG is approximately $460 million of outstanding debt and equity of JMG as of March 31, 2003. On March 31, 2003, OPCo made a prepayment of $90 million under this operating lease structure. AEP recognizes lease expense on a straight-line basis over the remaining lease term, in accordance with SFAS 13 "Accounting for Leases". On March 31, 2003, due to the $90 million prepayment, the net lease liability became an asset of $67.8 million. The asset is comprised of $16.7 million included in Other current assets and $51.1 million in Other Assets on AEP's Consolidated Balance Sheets ($16.7 million in Prepayments and Other and $51.1 million in Deferred Charges and Other Assets on OPCo's Balance Sheets) . The asset will be amortized over the remaining lease term, which ends in the first quarter of 2010. 13. MINORITY INTEREST IN FINANCE SUBSIDIARY In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated subsidiary of AEP that was capitalized with the assets of Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne) preferred stock, that is convertible into AEP common stock at market price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash and a subscription agreement that represents an unconditional obligation to fund $83 million from SubOne and $750 million from Steelhead Investors LLC ("Steelhead" - non-controlling preferred member interest). As managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated special purpose entity and has a capital structure of $750 million of which 3% is equity from investors with no relationship to AEP or any of its subsidiaries and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to limit its risk associated with Houston Pipe Line Company and Louisiana Intrastate Gas Company. Under the provisions of the Caddis formation agreements, Steelhead receives a quarterly preferred return equal to an adjusted floating reference rate (4.7426% and 4.4349% for the quarters ended March 31, 2003 and 2002, respectively). Caddis has the right to redeem Steelhead's interest at any time. The $750 million invested in Caddis by Steelhead was loaned to SubOne. This intercompany loan to SubOne is due August 2006, and is supported by the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The preferred stock is convertible into AEP common stock upon the occurrence of certain events including AEP's stock price closing below $18.75 for ten consecutive trading days. AEP can elect not to have the transaction supported by such preferred stock if SubOne were to reduce its loan with Caddis by $225 million (see below). The credit agreement between Caddis and SubOne contains covenants that restrict certain incremental liens and indebtedness, asset sales, investments, acquisitions, and distributions. The credit agreement also contains covenants that impose minimum financial ratios. Non-performance of these covenants may result in an event of default under the credit agreement. Through March 31, 2003, AEP has complied with the covenants contained in the credit agreement. In addition, a default under any other agreement or instrument relating to AEP and certain subsidiaries' debt outstanding in excess of $50 million is an event of default under the credit agreement. The initial period of Steelhead's investment in Caddis is through August 2006. At the end of the initial period, Caddis will either reset Steelhead's return rate, re-market Steelhead's interests to new investors, redeem Steelhead's interests, in whole or in part including accrued return, or liquidate Caddis in accordance with the provisions of applicable agreements. Steelhead has certain rights as a preferred member in Caddis. Upon the occurrence of certain events including a default in the payment of the preferred return, Steelhead's rights include: forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the AEP Gas Holding preferred stock into AEP common stock. If Steelhead exercised its rights to force Caddis to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the intercompany loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity. Caddis and SubOne are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and SubOne are consolidated with AEP for financial reporting purposes. Steelhead's investment in Caddis and payments made to Steelhead from Caddis are currently reported on AEP's Consolidated Statements of Operation and Consolidated Balance Sheets as Minority Interest in Finance Subsidiary. On May 9, 2003, SubOne borrowed $225 million from AEP and reduced the outstanding balance of the loan from Caddis, which Caddis then used to reduce the preferred interest held by Steelhead. This payment will allow the convertible preferred stock of AEP Gas Holding and the stock price trigger discussed above to be eliminated. AEP's maximum exposure to loss as a result of its involvement with Steelhead is a $2 million capital investment, $83 million under the subscription agreement to Caddis for any losses incurred by Caddis and the cash reserve fund balance of approximately $42 million (as of March 31, 2003) due Caddis for default under the intercompany loan agreement. Of the remaining $525 million financing, the recourse to AEP for the first quarter will increase in the second quarter 2003 by $165 million to comply with the covenants. As of March 31, 2003, AEP is continuing to review the application of FIN 46 as it relates to the Steelhead transaction.
14. FINANCING AND RELATED ACTIVITIES Long-term debt and other securities issuances and retirements during the first three months of 2003 were: Type Principal Interest Due Company of Debt Amount Rate Date Issuances (in millions) (%) AEP Senior Unsecured Notes $500 5.375 2010 CSPCo Senior Unsecured Notes 250 5.50 2013 CSPCo Senior Unsecured Notes 250 6.60 2033 OPCo Senior Unsecured Notes 250 5.50 2013 OPCo Senior Unsecured Notes 250 6.60 2033 TCC Senior Unsecured Notes 150 3.00 2005 TCC Senior Unsecured Notes 100 Variable 2005 TCC Senior Unsecured Notes 275 5.50 2013 TCC Senior Unsecured Notes 275 6.65 2033 TNC Senior Unsecured Notes 225 5.50 2013 Company Retirements AEP Bank Facility 1,300 Variable 2003 AEP Senior Unsecured Notes 49 6.125 2006 CSPCo First Mortgage Bonds 2 8.70 2022 CSPCo First Mortgage Bonds 15 8.55 2022 CSPCo First Mortgage Bonds 14 8.40 2022 CSPCo First Mortgage Bonds 13 8.40 2022 SWEPCo First Mortgage Bonds 55 6.625 2003 TCC First Mortgage Bonds 16 6.875 2003 TCC Securitization Bonds 32 3.54 2005 Non-Registrant: AEP Subsidiaries Notes Payable 2 Variable 2007 AEP Subsidiaries Revolving Credit Agreement 291 Variable 2003 AEP Subsidiaries Senior Unsecured Notes 17 6.50 2003 In addition to the transactions reported in the table above, the following table lists intercompany retirements of debt due to AEP. Type Principal Interest Due Company of Debt Amount Rate Date Retirements (in millions) (%) CSPCo Notes Payable $160 6.501 2006 OPCo Notes Payable 240 6.501 2006
Other Matters In April 2003, AEP announced that they will have an early redemption on May 30, 2003 of the following: o $125.5 million of CSPCo's First Mortgage Bonds o $165 million of I&M's Junior Subordinated Debentures o $90 million of I&M's First Mortgage Bonds Consequently, the debt has been classified as Long-term Debt Due Within One Year on their respective Balance Sheets due to the refinancing debt having been issued prior to March 31, 2003. Common Stock In March 2003, AEP issued 56 million shares of common stock at $20.95 per share through an equity offering and received net proceeds of $1,141 million (net of issuance costs of $36 million). Proceeds from the sale of common stock were used to pay down both short-term and long-term debt with the balance being held in cash. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS This is our combined presentation of management's discussion and analysis of financial condition, accounting policies and other matters for AEP and its registrant subsidiaries. Management's discussion and analysis of results of operations for AEP and each of its registrant subsidiaries for the quarter ended March 31, 2003 is presented with their financial statements earlier in this document. FINANCIAL CONDITION Credit Ratings As discussed in the 2002 Annual Report, the rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries. In February 2003, Moody's Investors Service (Moody's) completed their review of AEP and its rated subsidiaries. The results of that review were downgrades of the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1 and TCC from Baa1 to Baa2. TNC, which had no senior unsecured notes outstanding at the time of the ratings action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also downgraded from P-2 to P-3. The completion of this review was a culmination of ratings action started during 2002. With the completion of the reviews, Moody's has placed AEP and its rated subsidiaries on stable outlook. In March 2003, S&P lowered AEP and its subsidiaries senior unsecured ratings from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. S&P placed AEP on stable rating and closed their review. In March 2003, Fitch Ratings Service downgraded the parent company (AEP) to BBB from BBB+ with stable outlook. Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch APCo Baa1 BBB A- CSPCo A3 BBB A I&M Baa1 BBB BBB+ KPCo Baa1 BBB BBB+ OPCo A3 BBB A- PSO A3 BBB A SWEPCO A3 BBB A TCC Baa1 BBB A TNC A3 BBB A Current short-term ratings are as follows: Company Moody's S&P Fitch AEP P-3 A-2 F-2 The current ratings for senior unsecured debt are listed in the following table: Company Moody's S&P Fitch AEP Baa3 BBB BBB AEP Resources* Baa3 BBB BBB+ APCo Baa2 BBB BBB+ CSPCo A3 BBB A- I&M Baa2 BBB BBB KPCo Baa2 BBB BBB OPCo A3 BBB BBB+ PSO Baa1 BBB A- SWEPCO Baa1 BBB A- TCC Baa2 BBB A- TNC Baa1 BBB A- * The rating is for a series of senior notes issued with a Support Agreement from AEP. Liquidity Liquidity, or access to cash, has become a more critical factor in determining the financial stability of a company due to volatility in wholesale power markets and the potential limitations that credit rating downgrades place on a company's ability to raise capital. Management is committed to preserving an adequate liquidity position and addressing AEP and its subsidiaries' financial needs. At March 31, 2003, we had an available liquidity position of $5.3 billion as illustrated in the table below: Credit Facilities (in millions) Maturity Commercial Paper Backup Lines of Credit $2,500* 5/03 Commercial Paper Backup Lines of Credit 1,000 5/05 Euro Revolving Credit Facilities 315 10/03 Total 3,815 Cash Liquidity Reserves 300** Additional Unrestricted Cash including Cash on Hand for Operational Needs 1,464** Total Credit Facilities and Cash 5,579 Less: Commercial Paper Outstanding 225 Euro Revolving Credit Loans 16 Total Available Liquidity $5,338 * Contains one year term-out provision. ** These components comprise the Cash and Cash Equivalents balance on AEP's Consolidated Balance Sheet at March 31, 2003. The Ohio and Texas subsidiaries issued $2.025 billion of senior unsecured notes in February 2003 with maturity dates ranging from 2005 to 2033. The commercial paper balance outstanding decreased due to its repayment with proceeds from these issuances. At December 31, 2002, AEP also had a $1.725 billion bank facility maturing in April 2003 that was available for debt refinancing with $1.3 billion outstanding. With the issuance of the permanent financing for the Ohio and Texas subsidiaries, mentioned above, this facility was repaid and cancelled in February 2003. AEP also maintains a minimum $300 million cash liquidity reserve fund to support its marketing operations in the U.S. and keeps additional cash on hand as market conditions change. At March 31, 2002, AEP had $1.8 billion of available cash. In total, as shown in the table above, we had approximately $5.6 billion in liquidity sources of which $5.3 billion were unused and available at March 31, 2003. In April 2003, AEP's Board of Directors declared a common stock dividend of $0.35 per share for the second quarter of 2003, which is a 42% decrease from the previous quarter's dividend of $0.60 per share. This reduction will result in annual cash savings of approximately $395 million (based on the outstanding common shares at April 30, 2003). Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements. We operate a money pool and sell accounts receivables to provide liquidity for the domestic electric subsidiaries. Short-term borrowings are supported by a bank-sponsored receivables purchase agreement and two revolving credit agreements. Cash flows from operating activities during the first quarter of 2003 were $775 million, including $335 million from depreciation, amortization, deferred income taxes and deferred investment tax credits. This represents an increase of $795 million when compared to first quarter results of 2002, largely due to the year-over-year increase in net income of $609 million ($440 million and $(169) million in 2003 and 2002, respectively) and an increase in cash from working capital items of $985 million ($376 million in 2003 and $(609) million in 2002). The aforementioned increases were partially offset by a $(193) million cumulative effect of accounting change in 2003 (see Note 3). Cash flows used for investing activities during the first quarter of 2003 were $289 million compared to $332 million during the first quarter of 2002. The major reason for the year-over-year variance was proceeds of $35 million from the sale of assets in 2003 (see Note 10). During the first quarter of 2003, major construction expenditures continued for emission control technology at several coal-fired generating plants (see Note 7). Cash flows from financing activities in the first quarter of 2003 decreased by $284 million when compared to the first quarter of 2002 ($65 million compared to $349 million during 2003 and 2002, respectively), primarily as the result of AEP's retirement and restructuring of its short-term and long-term debt during 2003. During the first quarter of 2003, AEP was able to retire $3,434 million of debt ($2,925 million short-term and $509 million of long-term) and increase available cash primarily through the issuance of long-term financing ($2,525 million), issuance of common stock ($1,177 million) and the generation of cash from operating activities. Total consolidated plant and property additions for the first quarter 2003 were $324 million. The following table shows the plant and property additions by certain registrant subsidiaries: Company Amount (in millions) APCo $ 57 I&M 28 OPCo 56 SWEPCo 26 TCC 22 Financing Activity Common Stock Offering On February 27, 2003, AEP priced its offering of 50 million shares of common stock at a public offering price of $20.95 per share. AEP granted the underwriters an option to purchase an additional 7.5 million shares of common stock to cover over allotments. The underwriters exercised their over allotment option to purchase an additional 6 million shares. The net proceeds of approximately $1.1 billion from the sale of these securities were used to reduce debt and for other corporate purposes. Debt During March 2003, AEP completed an offering of 5.375% Series C Senior Notes which have a principal amount of $500 million and a maturity date of March 15, 2010. The net proceeds of $494 million from the offering were used to repay or redeem current maturities of long-term debt and for other corporate purposes. In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a variable rate, $150 million of unsecured senior notes due 2005 at a coupon of 3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and $275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued $225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The proceeds from the bond issuances were used to repay the bank facility due to mature in April 2003, mentioned above, short-term debt and for other corporate purposes. During the first quarter of 2003, CSPCo retired $44 million of first mortgage bonds due 2022 with rates ranging from 8.4% to 8.7%. SWEPCo and TCC retired $55 million and $16 million, respectively, of first mortgage bonds at maturity. TCC also retired $32 million of securitization bonds due 2005. In April 2003, SWEPCo issued $100 million of senior unsecured debt due 2015 at a coupon of 5.375%.
In April 2003, certain AEP subsidiaries called the following First Mortgage Bonds (FMB) or Junior Subordinated Debentures (JSD) for early redemption on May 30, 2003: Coupon Subsidiary Type of Or Stated Call Principal Company Debt Rate Rate Due Date Amounts % % (in millions) APCo FMB 8.50 100 2022 $70 APCo FMB 7.15 100 2023 20 APCo FMB 7.80 103.90 2023 30 CSPCo FMB 6.55 100 2004 27 CSPCo FMB 6.75 100 2004 26 CSPCo FMB 7.75 104.27 2023 33 CSPCo FMB 7.90 103.95 2023 40 I&M FMB 8.50 100 2022 75 I&M FMB 7.35 100 2023 15 I&M JSD 8.00 100 2026 40 I&M JSD 7.60 100 2038 125 KPCo JSD 8.72 100 2025 40
In May 2003, a third party exercised its option to call $250 million of 5.50% putable callable notes, issued by AEP in May 2001, for purchase and remarketing. Management is evaluating alternatives and plans to exchange the notes. During May 2003, APCo issued $200 million of unsecured senior notes due 2008 at a coupon of 3.60% and $200 million of unsecured senior notes due 2033 at a coupon of 5.95%. The proceeds of these bond issuance will be used to redeem the aforementioned early redemptions for APCo, a floating rate note due in August 2003 and for other corporate purposes. Possible Divestitures We have a strong commitment to continually evaluate the need to reallocate resources to areas that effectively match investments with our strategy, provide greater potential for financial returns, and to dispose of investments that no longer meet these principles. Assets we are seeking to divest consist of domestic and international unregulated generation, gas pipelines, a coal business and a communications business. The ultimate timing for a disposition of one or more of these assets will depend upon market conditions and the value of any buyer's proposal. If we choose to dispose of these assets, we may realize non-recurring losses in the aggregate that could have a material impact on our results of operations. Corporate Separation As discussed in the 2002 Annual Report, we have filed with the FERC and SEC seeking approval to separate our regulated and unregulated operations. With the changes in AEP's business strategy in response to current energy market and business conditions, management continues to evaluate corporate separation plans, including determining whether legal corporate separation is appropriate. RTO Formation As discussed in the 2002 Annual Report, the FERC's AEP-CSW merger approval and many of the settlement agreements with the state regulatory commissions to approve the AEP-CSW merger required the transfer of functional control of the subsidiaries' transmission systems to RTOs. In 2002, AEP announced an agreement with PJM to pursue terms for participation in its RTO for AEP East companies with final agreements to be negotiated. AEP subsidiaries, which operate in the states of Indiana, Kentucky, Ohio and Virginia, filed for state regulatory commission approval of their plans to transfer functional control of their transmission assets to PJM based on statutory or regulatory requirements in those states. Those proceedings remain pending. In February 2003, the Virginia Legislature enacted legislation, which the Governor of Virginia signed, that prohibited the transfer of transmission assets in its jurisdiction to an RTO, until at least July 2004. In April 2003, FERC approved AEP's transfer of functional control of the AEP East companies' transmission system to PJM. FERC also accepted AEP's proposed rates for joining PJM, but set a number of rate issues for resolution through settlement proceedings or FERC hearings. AEP West companies are members of ERCOT or the SPP. In 2002, FERC conditionally accepted filings related to a proposed consolidation of MISO and the SPP. AEP's SPP companies are also regulated by state public utility commissions, and the Louisiana and Arkansas commissions filed responses to the FERC's RTO order indicating that additional analysis was required. Subsequently, the proposed SPP/MISO combination was terminated. Regulatory activities concerning various RTO issues are ongoing in Arkansas and Louisiana. Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, our transmission operations or results of operations and cash flows. ACCOUNTING POLICIES Critical Accounting Policies - Revenue Recognition Regulatory Accounting - The consolidated financial statements of AEP and the financial statements of electric operating subsidiary companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, CSPCo, OPCo, SWEPCo, TCC and TNC) reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers through regulated revenues in the same accounting period. Regulatory liabilities are also recorded to provide for refunds to customers that have not yet been made. When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write-off that regulatory asset as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Electric Generation - We record operating revenues from electric generation activities using accrual, hedge and mark-to-market methods of accounting. We use accrual accounting for electricity sales to residential, industrial and institutional customers who have not signed a contract or have entered into long-term power sales contracts that are not subject to mark-to-market accounting. Under accrual accounting we record revenues when energy has been delivered. All of the registrant subsidiaries except AEGCo are allocated a portion of the revenues and costs associated with AEP's electric generation activities that have been recognized on an accrual basis. Some contracts for the sale of electricity at fixed prices for future delivery are used to mitigate the risk associated with anticipated sales of electricity from our generation assets and have been designated and accounted for as cash flow hedges under SFAS 133. Prior to settlement, we record changes in the fair value of contracts designated as cash flow hedges in the Consolidated Statements of Common Shareholders' Equity as Accumulated Other Comprehensive Income (AOCI). When the anticipated sale of electricity occurs, the settlement amount of the cash flow hedge is recorded in revenues. See Derivatives below. Revenues recognized under the mark-to-market method of accounting include realized revenue on electricity contracts, net of related costs of sales, and unrealized gains and losses on electricity contracts accounted for as derivatives under SFAS 133. We also recognize revenues under the mark-to-market method of accounting for non-derivative energy trading contracts as required by EITF Issue No. 98-10. Beginning October 25, 2002 for new contracts and January 1, 2003 for pre-existing contracts, in accordance with a new accounting pronouncement that is discussed further in Note 2, we discontinued the mark-to-market method of accounting for all unsettled electricity contracts that are not considered derivatives under SFAS 133. See Derivatives below. All of the registrant subsidiaries except AEGCo are allocated a portion of the revenues and costs associated with AEP's electric generation activities; however, PSO, SWEPCo, TCC and TNC are only allocated a portion of the forward transactions that are accounted for using the mark-to-market method of accounting. We defer, as regulatory liabilities (unrealized gains) or regulatory assets (unrealized losses), changes in the fair value of derivative contracts for the forward sale and purchase of electricity in AEP's traditional marketing area to the extent that a jurisdiction is regulated. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. For contracts which are outside of AEP's traditional marketing area, the change in fair value is included in nonoperating income on a net basis. Electric Transmission and Distribution - Revenues from electricity transmission and distribution services include realized revenue for electricity and delivery services provided to residential, industrial and institutional customers. These revenues are recognized when delivery services are provided. Gas Sales, Pipeline and Storage Activities - Revenue from gas sales activities includes realized revenue on contracts for the sale of gas, and unrealized gains and losses on gas contracts accounted for as derivatives under SFAS 133. See Derivatives below. Revenues from gas pipeline and storage services are recognized when gas is delivered to contractual meter points or when services are provided. Transportation and storage revenues also include the accrual of earned, but unbilled and/or not yet metered gas. Substantially all of the forward gas purchase and sale contracts (excluding wellhead purchases of natural gas), swaps and options for the pipeline operations, qualify as derivative financial instruments as defined by SFAS 133. Accordingly, net gains and losses resulting from revaluation of these contracts to fair value during the period are recognized currently in results of operations and are appropriately discounted, net of applicable credit and liquidity adjustments. Derivatives - We use derivative instruments such as futures, swaps, forwards and options to manage the commodity, currency exchange and financial market risks of our business operations. We also manage a portfolio of commodity contracts held for trading purposes as part of our strategy to market excess generation capacity. All derivative instruments not qualifying for the normal purchase normal sale exemption under SFAS 133 are recorded in the Consolidated Balance Sheets as Risk Management Assets and Liabilities. On the date a derivative instrument is entered into, we designate the derivative as either a normal purchase or sale contract; as held for trading purposes (trading contract); and/or a hedge of a forecasted transaction or future cash flows (cash flow hedge). Derivative instruments that provide for the purchase or sale of energy commodities that will settle physically in the normal course of business qualify for the normal purchase and sale exemption under SFAS 133. If the exemption has been elected, no amount associated with these contracts is included in the Consolidated Financial Statements until the commodity is actually delivered. Derivative instruments used to mitigate the risks of variability in expected cash flows attributable to a forecasted transaction are designated and accounted for as cash flow hedges under SFAS 133. Cash flow hedges are recorded at fair value on the Consolidated Balance Sheets as either an asset or liability with unrealized gains and losses recorded on the Consolidated Statements of Common Shareholders' Equity as AOCI until the hedged item affects earnings. We formally document the hedging relationship at the inception of the cash flow hedge and assess whether the hedging relationship is highly effective in achieving offsetting cash flows on an ongoing basis. We discontinue hedge accounting prospectively when the cash flow hedge is determined to be ineffective in achieving offsetting cash flows of the hedged item or it is not probable that the hedged transaction will occur. Settled amounts and ineffective portions of cash flow hedges are removed from AOCI and recorded in the Consolidated Statements of Operations in the same accounts as the hedged item. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative instrument will continue to be recorded at fair value on the Consolidated Balance Sheets as either an asset or liability with subsequent changes in fair value recognized in the Consolidated Statements of Operations. Derivative instruments entered into for trading purposes are recorded at fair value on the Consolidated Balance Sheets as either an asset or liability with all realized and unrealized gains and losses presented on a net basis in the Consolidated Statements of Operations. Energy options, futures and swaps represent financial transactions with unrealized gains and losses from changes in fair values reported net in revenues. APCo, CSPCo, I&M, KPCo and OPCo also have financial transactions, but record the unrealized gains and losses, as well as the net proceeds upon settlement, in Nonoperating Income. The fair values of derivative contracts are based on exchange prices and broker quotes. We mark-to-market long-term derivative contracts based primarily on valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing us to market risk and causing our results of operations to be subject to volatility. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and at the time contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if our current estimates of future market prices are not representative of actual future market prices. Differences between actual market prices in the future and our estimated future prices are more likely to occur for long-term contracts. See the "Quantitative and Qualitative Disclosures About Risk Management Activities" section of this report for a discussion of the policies and procedures used to manage our exposure to market and other risks from trading activities. New Accounting Pronouncements See Note 2 for a discussion of significant accounting policies and new accounting pronouncements. OTHER MATTERS Industry Restructuring As discussed in the 2002 Annual Report, restructuring and customer choice were effective in four of the eleven state retail jurisdictions in which the AEP electric utility companies operate. Restructuring legislation provides for a transition from cost-based rate regulation of bundled electric service to customer choice and market pricing for the supply of electricity. The status of our transition plans, regulatory issues and proceedings and accounting issues in the state regulatory jurisdictions impacted by restructuring and customer choice is presented in Note 6. Nuclear Plant Outages - Affecting AEP, I&M and TCC In April 2003, engineers at STP found a small quantity of powdery residue during inspections conducted regularly as part of refueling outages. STP officials are working closely with the NRC to safely return the unit to service. The NRC will review any corrective action prior to its implementation and restart of the unit. In April 2003, both units of Cook Plant were taken offline due to an influx of fish in the plant's cooling water system which caused a reduction in cooling water to essential plant equipment. Management is unable to predict the length of time that the STP and Cook Plant units may be unavailable or the costs of corrective actions at this time. Cook Unit 2 was already planned for a refueling outage starting May 5. We have commitments to provide power to customers during the outages. Therefore, we will be subject to fluctuations in the market prices of electricity and purchased replacement energy could be a significant cost. Litigation Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in the 2002 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation since 1999 regarding generating plant emissions under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo and eleven unaffiliated utilities made modifications to generating units at coal-fired generating plants in violation of the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. 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. Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the Clear Air Act proceedings and is unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. 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 unless such costs can be recovered through regulated rates and market prices for electricity. See Note 7 for further discussion. NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and TCC Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule) under the Clean Air Act 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 compliance date for the rules is May 31, 2004. The Texas Commission on Environmental Quality adopted rules requiring significant reductions in NOx emissions from utility sources, including SWEPCo and TCC. The compliance date is May 2003 for TCC and May 2005 for SWEPCo. AEP is installing selective catalytic reduction (SCR) technology and non-SCR technology to reduce NOx emissions on certain units to comply with these rules. Our estimates indicate that compliance with the rules could result in required capital expenditures in a range of approximately $1.3 billion to $1.7 billion for the AEP System. The actual cost to comply could be significantly different than the 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. See Note 7 for further discussion. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding of the Enron Corporation and its subsidiaries which is pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron's bankruptcy, AEP and its subsidiaries had open trading contracts and trading accounts receivables and payables with Enron and various HPL related contingencies and indemnities including issues related to the underground Bammel gas storage facility and the cushion gas (or pad gas) required for its normal operation. Management believes that AEP entities have the right to utilize offsetting receivables and payables and related collateral across various Enron entities by offsetting trading payables owed to various Enron entities against trading receivables due to us. Management believes we have legal defenses to any challenge that may be made to the utilization of such offsets. An additional expense of up to $110 million may be incurred without such offsets. At this time management is unable to predict the ultimate resolution of these issues or their impact on results of operations and cash flows. See Note 7 for further discussion. Bank of Montreal Claim - Affecting AEP In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals and has claimed approximately $25 million is owed to BOM by AEP which BOM subsequently has changed to approximately $34 million.In April 2003, AEP filed a lawsuit against BOM claiming BOM had acted contrary to industry practice in calculating termination and liquidation amounts and that BOM had acknowledged in March 2003 that it owed AEP approximately $68 million. Alternatively, AEP is claiming that BOM owes approximately $45 million to AEP. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. Arbitration of Williams Claim - Affecting AEP In 2002, AEP filed its demand for arbitration with the American Arbitration Association to initiate formal arbitration proceedings in a dispute with the Williams Companies (Williams). The proceeding results from Williams' repudiation of its obligations to provide physical power deliveries to AEP and Williams' failure to provide the monetary security required for natural gas deliveries. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition. See Note 7 for further discussion. Arbitration of PG&E Energy Trading, LLC Claim - Affecting AEP In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22 million was owed by AEP in connection with the termination and liquidation of all trading deals. In February 2003, PGET initiated arbitration proceedings. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial conditions. Energy Market Investigations - Affecting AEP As discussed in the 2002 Annual Report, the FERC, the California attorney general, the PUCT, the SEC, the Department of Justice and the U.S. Commodity Futures Trading Commission (CFTC) initiated investigations into whether any entity, including Enron Corporation, manipulated short-term prices in electric energy or natural gas markets, exercised undue influence over wholesale prices or participated in fraudulent trading practices. In March 2003, the SEC subpoenaed information from its August 2002 request for us to voluntarily provide certain trading information. AEP and its subsidiaries have and will continue to provide information to the FERC, the SEC, state officials and the CFTC as required. See Note 7 for further discussion. Shareholders' Litigation - Affecting AEP In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty for failure to establish and maintain adequate internal controls and violations of the Employee Retirement Income Security Act were filed against AEP, certain AEP executives, members of the AEP Board of Directors and certain investment banking firms. These cases are in the initial pleading stage. AEP intends to vigorously defend against these actions. See Note 7 for further discussion. California Lawsuit - Affecting AEP In 2002, the Lieutenant Governor of California filed a lawsuit in California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP intends to vigorously defend against this action. See Note 7 for further discussion. COLI Litigation A decision by the U.S. District Court for the Southern District of Ohio in February 2001 that denied AEP's deduction of interest claimed on AEP's consolidated federal income tax returns related to a COLI program resulted in a $319 million reduction in AEP's Net Income for 2000. We filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6th Circuit. In April 2003, the Appeals Court ruled against AEP. Management is reviewing this opinion and will evaluate AEP's options. Other Litigation AEP and its subsidiaries continue to be involved in certain other legal matters discussed in the 2002 Annual Report. Snohomish Settlement - Affecting AEP In February 2003, AEP and the Public Utility District No. 1 of Snohomish County, Washington (Snohomish) agreed to terminate their long-term contract signed in January 2001. Snohomish also agreed to withdraw its complaint before the FERC regarding this contract and paid $59 million to AEP. As a result of the contract termination, AEP reversed $69 million of unrealized mark-to-market gains previously recorded, resulting in a $10 million pre-tax loss. Other Management Matters - Affecting AEP On April 9, 2003, Dr. E. Linn Draper Jr., AEP's chairman, president and chief executive officer, announced that he plans to retire in 2004. AEP's board of directors will soon begin the process of identifying Dr. Draper's successor. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC Market Risks As a major power producer and marketer of wholesale electricity and natural gas, AEP has certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact AEP due to changes in the underlying market prices or rates. Policies and procedures have been established to identify, assess, and manage market risk exposures in AEP's day to day operations. AEP's risk policies have been reviewed with the Board of Directors, approved by a Risk Executive Committee and administered by a Chief Risk Officer. The Risk Executive Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels. This committee receives daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. The committee meets monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior financial and operating managers. AEP has actively participated in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around energy trading contracts. The CCRO is composed of the chief risk officers of major electricity and gas companies in the United States. Recently the CCRO adopted disclosure standards for energy contracts to improve clarity, understanding and consistency of information reported. Implementation of the new disclosures is voluntary. AEP supports the work of the CCRO and has embraced the new disclosures. The following tables provide information on AEP's risk management activities.
Roll-Forward of MTM Risk Management Contract Net Assets This table provides detail on changes in AEP's MTM net asset or liability balance sheet position from one period to the next. TABLE 1 Part I Roll-Forward of MTM Risk Management Contract Net Assets Three Months Ended March 31, 2003 Domestic Domestic AEP AEP Consolidated Power Gas International Consolidated (in millions) Beginning Balance December 31, 2002 $360 (155) 45 250 (Gain) Loss from Contracts Realized/Settled During the Period (a) (89) (23) (22) (134) Fair Value of New Contracts When Entered Into During the Period (day one gains) (b) - - - - Net Option Premiums Paid/(Received) (c) (2) 24 (2) 20 Change in Fair Value Due to Valuation Methodology Changes - 1 - 1 Effect of 98-10 Rescission (19) 1 (14) (32) Changes in Fair Value of Risk Management Contracts (e) 27 24 (28) 23 Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (d) 17 - - 17 Ending Balance March 31, 2003 $294 $(128) $(21) $145 Domestic Power APCo CSPCo I&M KPCO (in thousands) Beginning Balance December 31, 2002 $96,852 $65,117 $70,861 $24,998 (Gain) Loss from Contracts Realized/Settled During the Period (a) (25,745) (17,307) (16,202) (5,691) Fair Value of New Contracts When Entered Into During the Period (day one gains) (b) - - - - Net Option Premiums Paid/(Received) (c) (466) (274) (293) (106) Change in Fair Value Due to Valuation Methodology Changes - - - - Effect of 98-10 Rescission (4,664) (3,135) (4,861) (1,744) Changes in Fair Value of Risk Management Contracts (e) 14,451 6,623 (296) (163) Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (d) 6,377 - 6,249 2,459 Ending Balance March 31, 2003 $ 86,805 $51,024 $55,458 $19,753 Domestic Power OPCo PSO SWEPCo TCC (in thousands) Beginning Balance December 31, 2002 $ 94,106 $ 3,545 $ 4,050 $ 5,414 (Gain) Loss from Contracts Realized/Settled During the Period (a) (24,661) 220 (18) (670) Fair Value of New Contracts When Entered Into During the Period (day one - - - - gains) (b) Net Option Premiums Paid/(Received) (c) (363) - - - Change in Fair Value Due to Valuation Methodology Changes - - - - Effect of 98-10 Rescission (4,159) - 151 187 Changes in Fair Value of Risk Management Contracts (e) 10,868 - 595 (4,527) Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (d) - 1,192 885 - Ending Balance March 31, 2003 $ 75,791 $ 4,957 $ 5,663 $ 404 Domestic Power TNC (in thousands) Beginning Balance December 31, 2002 $ 2,043 (Gain) Loss from Contracts Realized/Settled During the Period (a) (41) Fair Value of New Contracts When Entered Into During the Period (day one - gains) (b) Net Option Premiums Paid/(Received) (c) - Change in Fair Value Due to Valuation Methodology Changes - Effect of 98-10 Rescission 20 Changes in Fair Value of Risk Management Contracts (e) (269) Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (d) (298) Ending Balance March 31, 2003 $ 1,455 (a) "(Gain) Loss from Contracts Realized/Settled During the Period" include realized gains from risk management contracts and related derivatives that settled during 2003 that were entered into prior to 2003. (b) The "Fair Value of New Contracts When Entered Into During the Period" represents the fair value of long-term contracts entered into with customers during 2003. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location. (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered into in 2003. (d)"Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions" relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. (e)"Changes in Fair Value of Risk Management Contracts" represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
TABLE 1 Part II Detail on MTM Risk Management Contract Net Assets As of March 31, 2003 Domestic Domestic AEP Power Gas International Consolidated (in millions) Current Assets $ 473 $ 465 $ 157 $ 1,095 Non Current Assets 426 285 57 768 Total MTM Energy Assets $ 899 $ 750 $ 214 $ 1,863 Current Liabilities $(367) $(688) $(183) $(1,238) Non Current Liabilities (238) (190) (52) (480) Total MTM Risk Management Contract Liabilities $(605) $(878) $(235) $(1,718) Total MTM Risk Management Contract Net Assets $ 294 $(128) $ (21) 145 Assets Held for Sale (Nordic) 17 Less Non-Trading Related Derivative Liabilities (56) Net Fair Value of Risk Management and Derivative Contracts $ 106
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information. o The source of fair value used in determining the carrying amount of AEP's total MTM asset or liability (external sources or modeled internally) o The maturity, by year, of AEP's net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash TABLE 2 Part I Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets Fair Value of Contracts as of March 31, 2003 Remainder After US POWER: 2003 2004 2005 2006 2007 2007 Total (in millions) Prices Actively Quoted - Exchange Traded Contracts $ (5) $(6) $ (2) $(2) $ - $ - $(15) Prices Provided by Other External Sources - OTC Broker Quotes (a) 52 58 21 14 7 - 152 Prices Based on Models and Other Valuation Methods (b) 33 19 11 20 17 57 157 Total $ 80 $71 $ 30 $32 $24 $57 $294 U.S. GAS: Prices Actively Quoted - Exchange Traded Contracts (a) $ (39) $101 $ (6) $(1) $ - $ - $ 55 Prices Provided by Other External Sources - OTC Broker Quotes (a) 41 - - - - - 41 Prices Based on Models and Other Valuation Methods (b) (193) (41) (4) 9 8 (3) (224) Total $(191) $ 60 $(10) $ 8 $ 8 $(3) $(128) International: Prices Actively Quoted - Exchange Traded Contracts (a) $ (14) $ (1) $ - $ - $ - $ - $(15) Prices Provided by Other External Sources - OTC Broker Quotes (a) (12) 6 - (1) - - (7) Prices Based on Models and Other Valuation Methods (b) (1) - - - 1 1 1 Total $ (27) $ 5 $ - $(1) $ 1 $ 1 $(21) AEP Consolidated: Prices Actively Quoted - Exchange Traded Contracts $ (58) $ 94 $ (8) $(3) $ - $ - $ 25 Prices Provided by Other External Sources - OTC Broker Quotes (a) 81 64 21 13 7 - 186 Prices Based on Models and Other Valuation Methods (b) (161) (22) 7 29 26 55 (66) Total $(138) $136 $ 20 $39 $33 $55 $145 APCo Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $16,282 $16,967 $5,722 $4,278 $1,949 $ - $45,198 Prices Based on Models and Other Valuation Methods (b) 10,597 2,984 2,203 4,988 4,581 16,254 41,607 Total $26,879 $19,951 $7,925 $9,266 $6,530 $16,254 $86,805 CSPCo Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $ 9,569 $ 9,974 $3,364 $2,514 $1,145 $ - $26,566 Prices Based on Models and Other Valuation Methods (b) 6,229 1,754 1,295 2,932 2,693 9,555 24,458 Total $15,798 $11,728 $4,659 $5,446 $3,838 $9,555 $51,024 I&M Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $11,490 $10,513 $3,599 $2,690 $1,226 $ - $29,518 Prices Based on Models and Other Valuation Methods (b) 6,438 1,872 1,386 3,138 2,882 10,224 25,940 Total $17,928 $12,385 $4,985 $5,828 $4,108 $10,224 $55,458 KPCo Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $3,705 $3,860 $1,302 $ 974 $ 443 $ - $10,284 Prices Based on Models and Other Valuation Methods (b) 2,411 679 502 1,135 1,043 3,699 9,469 Total $6,116 $4,539 $1,804 $2,109 $1,486 $3,699 $19,753 OPCo Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $19,450 $15,232 $4,462 $3,336 $1,520 $ - $44,000 Prices Based on Models and Other Valuation Methods (b) 7,652 2,281 1,718 3,890 3,573 12,677 31,791 Total $27,102 $17,513 $6,180 $7,226 $5,093 $12,677 $75,791 PSO Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $ 943 $ 928 $330 $247 $112 $ - $2,560 Prices Based on Models and Other Valuation Methods (b) 611 172 127 286 264 937 2,397 Total $1,554 $1,100 $457 $533 $376 $937 $4,957 SWEPCo Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $1,077 $1,060 $377 $282 $128 $ - $ 2,924 Prices Based on Models and Other Valuation Methods (b) 698 196 145 328 302 1,070 2,739 Total $1,775 $1,256 $522 $610 $430 $1,070 $ 5,663 TCC Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $ 77 $76 $27 $20 $ 9 $ - $209 Prices Based on Models and Other Valuation Methods (b) 50 14 10 23 22 76 195 Total $127 $90 $37 $43 $31 $76 $404 TNC Remainder After 2003 2004 2005 2006 2007 2007 Total (in thousands) Prices Provided by Other External Sources - OTC Broker Quotes (a) $277 $272 $ 97 $ 72 $ 33 $ - $ 751 Prices Based on Models and Other Valuation Methods (b) 179 51 37 85 77 275 704 Total $456 $323 $134 $157 $ 110 $275 $1,455 (a) Prices provided by other external sources - Reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. (b) Modeled - In the absence of pricing information from external sources, modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled.
The determination of the point at which a market is no longer liquid for placing it in the Modeled category in Table 2 Part I varies by market. Table 2 Part II reports an estimate of the maximum tenors of the liquid portion of each energy market used to complete Table 2 Part I. Table 2 Part II Maximum Domestic Tenor of the Liquid Portion of Risk Management Contracts As of March 31, 2003 TENOR (in months) Natural Gas Forward Purchase and Sales NYMEX Henry Hub Gas 72 Gas East - Northeast, Mid-continent Gulf Coast, Texas 12 Gas West - Permian Basin, San Juan, Rocky Mtns, Kern, Cdn Border(Sumas), Malin, PGE Citygate, AECO 12 Power (Peak) Over the Counter Options Power East - Cinergy 33 Power East - PJM 33 Power East - First Energy 21 Power East - NEPOOL 21 Power East - ERCOT 21 Power East - TVA 9 Power East - Com Ed 9 Power East - Entergy 33 Power West - PV, NP15,SP15,MidC,Mead 57 Peak Power Volatility (Options) ECAR, MidCon, NYPP, PJM, West Ercot NEPOOL 21 OffPeak Power Volatility All Regions 0 Natural Gas Liquids 14 Emissions 33 Coal 33
Cash Flow Hedges Included in Accumulated Other Comprehensive Income on the Balance Sheet AEP employs fair value hedges and cash flow hedges to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. AEP does not hedge all interest rate risk. AEP employs forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations of debt denominated in foreign currencies. AEP does not hedge all foreign currency exposure. Table 3 provides detail on effective cash flow hedges under SFAS 133 included in the balance sheet. The data in the table will indicate the magnitude of SFAS 133 hedges AEP has in place. (However, given that under SFAS 133 not all hedges are recorded in AOCI, the table does not provide an all-encompassing picture of AEP's hedges). The table further indicates what portions of these hedges are expected to roll off into the income statement in the next 12 months. The table also includes a roll-forward of the AOCI balance sheet account, providing insight into the drivers of the changes (new hedges placed during the period, changes in value of existing hedges and roll off of hedges).
Information on energy merchant activities is presented separately from interest rate, foreign currency risk management activities and other hedging activities. In accordance with GAAP, all amounts are presented net of related income taxes. TABLE 3 Cash Flow Hedges included in Accumulated Other Comprehensive Income On the Balance Sheet as of March 31, 2003 Portion Expected to Accumulated Other Be Reclassified to Comprehensive Income Earnings During the (Loss) After Tax (a) Next 12 Months (b) AEP Consolidated (in millions) Domestic Power $(43) $(31) Domestic Gas 8 (3) Foreign Currency 2 2 Interest Rate (5) 1 Total AEP $(38) $(31)
Total Other Comprehensive Income Activity Three Months Ended March 31, 2003 Domestic Domestic Foreign AEP Power Gas Currency Interest Rate Consolidated (in millions) Accumulated OCI, December 31, 2002 $ (1) $ - $(3) $(12) $(16) Changes in Fair Value (c) (65) 8 5 6 (46) Reclassifications from OCI to Net Income (d) 23 - - 1 24 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(43) $ 8 $ 2 $ (5) $(38)
APCo Domestic Foreign AEP Power Currency Interest Rate Consolidated (in thousands) Accumulated OCI, December 31, 2002 $ (394) $(190) $(1,336) $(1,920) Changes in Fair Value (c) (19,201) - (104) (19,305) Reclassifications from OCI to Net Income (d) 6,649 2 136 6,787 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(12,946) $(188) $(1,304) $(14,438) CSPCo Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (267) Changes in Fair Value (c) (11,251) Reclassifications from OCI to Net Income (d) 3,908 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(7,610) I&M Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (286) Changes in Fair Value (c) (12,039) Reclassifications from OCI to Net Income (d) 4,182 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(8,143) KPCo Domestic KPCo Power Interest Rate Consolidated (in thousands) Accumulated OCI, December 31, 2002 $ (103) $425 $ 322 Changes in Fair Value (c) (4,357) (43) (4,400) Reclassifications from OCI to Net Income (d) 1,513 22 1,535 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(2,947) $404 $(2,543) OPCo Domestic Foreign OPCo Power Currency Consolidated (in thousands) Accumulated OCI, December 31, 2002 $ (354) $(384) $ (738) Changes in Fair Value (c) (14,928) - (14,928) Reclassifications from OCI to Net Income (d) 5,185 3 5,188 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(10,097) $(381) $(10,478) PSO Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (42) Changes in Fair Value (c) (1,833) Reclassifications from OCI to Net Income (d) 636 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(1,239) SWEPCo Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (48) Changes in Fair Value (c) (2,094) Reclassifications from OCI to Net Income (d) 727 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(1,415) TCC Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (36) Changes in Fair Value (c) (1,559) Reclassifications from OCI to Net Income (d) 541 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $(1,054) TNC Domestic Power (in thousands) Accumulated OCI, December 31, 2002 $ (15) Changes in Fair Value (c) (645) Reclassifications from OCI to Net Income (d) 224 Accumulated OCI Derivative Gain (Loss) March 31, 2003 $ (436) (a) Accumulated other comprehensive income (loss) after tax - Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders' equity on the balance sheet. (b) Portion expected to be reclassified to earnings during the next 12 months - Amount of gains or losses (realized or unrealized) from derivatives used as hedging instruments that have been deferred and are expected to be reclassified into net income during the next 12 months at the time the hedged transaction affects net income. (c) Changes in fair value - Changes in the fair value of derivatives designated as hedging instruments in cash flow hedges during the reporting period not yet reclassified into net income, pending the hedged item's affecting net income. Amounts are reported net of related income taxes. (d) Reclassifications from AOCI to net income - Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above.
Credit Risk AEP limits credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Only after an entity has met AEP's internal credit rating criteria will we extend unsecured credit. AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis. AEP's independent analysis, in conjunction with the rating agencies information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business. AEP has risk management contracts with numerous counterparties. Since AEP's open risk management contracts are valued based on changes in market prices of the related commodities, AEP's exposures change daily. AEP believes that credit and market exposures with any one counterparty is not material to AEP's financial condition at March 31, 2003. At March 31, 2003 approximately 6% of AEP's exposure was below investment grade as expressed in terms of net MTM assets. Net MTM assets represents the aggregate difference between the forward market price for the remaining term of the contract and the contractual price per counterparty. As of March 31, 2003 the following table approximates counterparty credit quality and exposure for AEP based on netting across AEP entities, commodities and instruments: TABLE 4 Futures, Forward and Counterparty Swap Credit Quality: Contracts Options Total (in millions) AAA/Exchanges $ 12 $33 $ 45 AA 302 19 321 A 338 17 355 BBB 515 161 676 Below Investment Grade 77 11 88 Total $ 1,244 $241 $1,485 The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. Merchant Plant Owned Assets Production and Hedging Information Table 5 provides information on the proportion of output of AEP's generation facilities (based on economic availability projections) economically hedged. This information is forward-looking and provided on a prospective basis through December 31, 2005. Please note that this table is point-in time estimates, subject to changes in market conditions and AEP decisions on how to manage operations and risk. TABLE 5 Merchant Plant-Owned Assets Hedging Information Estimated Next Three Years As of March 31, 2003 2003 2004 2005 Estimated Plant Output Hedged (a) 93% 88% 83% (a) Estimated Plant Output Hedged - Represents the portion of megawatt-hours of future generation production for which AEP has sales commitments to customers. VaR Associated with Energy Trading Contracts AEP uses a risk measurement model which calculates Value at Risk (VaR) to measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assumes 95% confidence level, a one-day holding period and a one-tailed distribution. Based on this VaR analysis, at March 31, 2003 a near term typical change in commodity prices is not expected to have a material effect on AEP's results of operations, cash flows or financial condition. The following table shows the end, high, average, and low market risk as measured by VaR for quarter ended and year-to-date: AEP VaR Model March 31, December 31, 2003 2002 End High Average Low End High Average Low (in millions) AEP $7 $19 $ 7 $5 $5 $24 $12 $4 APCo 1 3 2 1 1 4 1 - CSPCo 1 2 1 1 1 3 1 - I&M 1 2 1 1 1 3 1 - KPCo - 1 - - - 1 - - OPCo 1 2 1 1 1 4 1 - PSO - - - - - - - - SWEPCo - - - - - - - - TCC - - - - - - - - TNC - - - - - - - - The High VaR for the first quarter 2003 occurred in late February 2003 during a period when natural gas and power prices experienced high levels and extreme volatility. Within a few days the VaR returned to levels more representative of the average VaR for the quarter. The AEP VaR model results are adjusted using standard statistical treatments to calculate the Committee of Chief Risk Officers (CCRO) VaR reporting metrics listed below. The adjustments are made to take the AEP model results from a one-day holding period to the ten-day holding period, from a one-tailed result to a two-tailed result and from the 95% confidence level to the 99% confidence level. The AEP VaR model's performance has not been evaluated for its accuracy at calculating VaR using the CCRO VaR Metrics assumptions.
Committee of Chief Risk Officers (CCRO) VaR Metrics Average End of Q1 2003 for Q1 2003 High for Q1 2003 Low for Q1 2003 (in millions) 95% Confidence Level, Ten-Day Holding Period, Two-Tailed $26 $28 $71 $17 99% Confidence Level, One-Day Holding Period, Two-Tailed $11 $12 $30 $ 7
AEP utilizes a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level, a one year holding period and a one-tailed distribution. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $1,047 million at March 31, 2003 and $527 million at December 31, 2002. AEP would not expect to liquidate its entire debt portfolio in a one year holding period, therefore a near term change in interest rates should not materially affect results of operations or consolidated financial position. AEGCo is not exposed to risk from changes in interest rates on short-term and long-term borrowings used to finance operations since financing costs are recovered through the unit power agreements. AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for TCC and TNC) or frozen by settlement agreements in Michigan and West Virginia or capped in Indiana. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas. AEP employs physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps, and other derivative contracts to offset price risk where appropriate. AEP engages in risk management of electricity, gas and to a lesser degree other commodities and as a result AEP is subject to price risk. The amount of risk taken by the staff is controlled by risk management operations and AEP's Chief Risk Officer and his staff. When the risk from energy trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee. CONTROLS AND PROCEDURES (a) Evaluation of disclosure controls and procedures. Our chief executive officer and our chief financial officer, after evaluating the effectiveness of "disclosure controls and procedures" (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c)) as of a date (the "Evaluation Date") within 90 days before the filing date of this quarterly report, have concluded that as of the Evaluation Date, our disclosure controls and procedures were adequate and designed to ensure that material information relating to us and our consolidated subsidiaries would be made known to them by others within those entities. (b) Changes in internal controls. There were no significant changes in our internal controls or to our knowledge, in other factors that could significantly affect our disclosure controls and procedures subsequent to the Evaluation Date. PART II. OTHER INFORMATION Item 5. Other Information. NONE Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC Exhibit 99.1 - Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. Exhibit 99.2 - Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code. (b) Reports on Form 8-K: AEGCo, APCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC The following reports on Form 8-K were filed during the quarter ended March 31, 2003. Company Reporting Date of Report Item Reported AEP February 25, 2003 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits AEP February 26, 2003 Item 7. Financial Statements And Exhibits Item 9. Regulation FD Disclosure AEP February 27, 2003 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements And Exhibits AEP March 14, 2003 Item 5. Other Events and Regulation FD Disclosures Item 7. Financial Statements And Exhibits CSPCo and OPCo February 4, 2003 Item 5. Other Events and Regulation FD Disclosure Signatures 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/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto Geoffrey S. Chatas Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY AEP TEXAS CENTRAL COMPANY AEP TEXAS NORTH COMPANY APPALACHIAN POWER COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY By: /s/Geoffrey S. Chatas By: /s/Joseph M. Buonaiuto Geoffrey S. Chatas Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer Date: May 14, 2003 CERTIFICATIONS I, E. Linn Draper, Jr., certify that: 1. I have reviewed this quarterly report on Form 10-Q of: American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: May 14, 2003 By: /s/ E. Linn Draper, Jr. E. Linn Draper, Jr. Chief Executive Officer I, Susan Tomasky, certify that: 1. I have reviewed this quarterly report on Form 10-Q of: American Electric Power Company, Inc. AEP Generating Company AEP Texas Central Company AEP Texas North Company Appalachian Power Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Dated: May 14, 2003 By: /s/ Susan Tomasky Susan Tomasky Chief Financial Officer