10-Q 1 xq202mod.txt COMBINED 10-Q 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 JUNE 30, 2002 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 1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790 0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600 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) 0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790 1 Riverside Plaza, Columbus, Ohio 43215-2373 Telephone (614) 223-1000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company, Public Service Company of Oklahoma and West Texas Utilities Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q. Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No ------ ------ The number of shares outstanding of American Electric Power Company, Inc. Common Stock, par value $6.50, at July 31, 2002 was 338,835,220. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES FORM 10-Q For The Quarter Ended June 30, 2002 CONTENTS
Page Glossary of Terms i - ii Forward-Looking Information iii 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-5 Consolidated Financial Statements A-6 - A-10 AEP Generating Company: Management's Narrative Analysis of Results of Operations B-1 Financial Statements B-2 - B-5 Appalachian Power Company, Inc. and Subsidiaries: Management's Discussion and Analysis of Results of Operations C-1 - C-4 Consolidated Financial Statements C-5 - C-9 Central Power and Light Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations D-1 - D-4 Consolidated Financial Statements D-5 - D-8 Columbus Southern Power Company and Subsidiaries: Management's Narrative Analysis of Results of Operations E-1 - E-5 Consolidated Financial Statements E-6 - E-9 Indiana Michigan Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations F-1 - F-5 Consolidated Financial Statements F-6 - F-10 Kentucky Power Company Management's Narrative Analysis of Results of Operations G-1 - G-4 Financial Statements G-5 - G-9 Ohio Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations H-1 - H-4 Consolidated Financial Statements H-5 - H-9 Public Service Company of Oklahoma and Subsidiaries: Management's Narrative Analysis of Results of Operations I-1 - I-4 Consolidated Financial Statements I-5 - I-8 Southwestern Electric Power Company and Subsidiaries: Management's Discussion and Analysis of Results of Operations J-1 - J-4 Consolidated Financial Statements J-5 - J-8 West Texas Utilities Company: Management's Narrative Analysis of Results of Operations K-1 - K-4 Financial Statements K-5 - K-8 Footnotes to Financial Statements L-1 - L-16
Item 2. Registrants' Combined Management Discussion and Analysis of Financial Condition, Contingencies and Other Matters M-1 - M-11 Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1 - N-9 Part II. OTHER INFORMATION Item 4. Submission of Matters to a Vote of Security Holders O-1 Item 5. Other Information O-3 Item 6. Exhibits and Reports on Form 8-K O-4 (a) Exhibits Exhibit 3 (d) Exhibit 3 (e) Exhibit 12 Exhibit 99.1 Exhibit 99.2 (b) Reports on Form 8-K SIGNATURE P-1
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. GLOSSARY OF TERMS When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Term Meaning 2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs. AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP. aEP................................ American Electric Power Company, Inc. aEP Consolidated................... AEP and its majority owned subsidiaries consolidated. aEP Credit, Inc.................... AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and unaffiliated domestic electric utility companies. AEP East electric operating companies.......................... APCo, CSPCo, I&M, KPCo and OPCo. AEPR............................... AEP Resources, Inc. aEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries. AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. aEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies. AEP West electric operating companies.......................... CPL, PSO, SWEPCo and WTU. Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities. Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo. APCo............................... Appalachian Power Company, an AEP electric utility subsidiary. 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. CPL................................ Central Power and Light Company, an AEP electric utility subsidiary. CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary. CSW............................... Central and South West Corporation, a subsidiary of AEP. CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants. CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States. D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit. DOE................................ United States Department of Energy. EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force. 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. 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. MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members. Money Pool......................... AEP System's Money Pool. MPSC............................... Michigan Public Service Commission. MTN................................ Medium Term Notes. MW................................. Megawatt. MWH................................ Megawatthour. NEIL............................... Nuclear Electric Insurance Limited. NOx................................ Nitrogen oxide. NOx Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operates. NRC................................ Nuclear Regulatory Commission. Ohio Act........................... The Ohio Electric Restructuring Act of 1999. Ohio EPA........................... Ohio Environmental Protection Agency. OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary. 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, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU. Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M. RTO................................ Regional Transmission Organization. SEC................................ Securities and Exchange Commission. SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board. SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain ------------------------------------- Types of Regulation. ------------------- SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of ------------------------------------ Application of Statement 71. --------------------------- SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of -------------------------------- Long-Lived Assets and for Long-Lived Assets to be Disposed of. -------------------------------------------------------------- SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments ------------------------------------- and Hedging Activities. ---------------------- SFAS 142........................... Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. ------------------------------------- SFAS 144........................... Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or -------------------------------- Disposal of Long-lived Assets. ----------------------------- SNF................................ Spent Nuclear Fuel. SPP................................ Southwest Power Pool. STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light Company, an AEP electric utility subsidiary . SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary. Texas Restructuring Legislation.... Legislation enacted in 1999 to restructure the electric utility industry in Texas. 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. WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary. WTU................................ West Texas Utilities Company, an AEP electric utility 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.
FORWARD-LOOKING INFORMATION This report made by AEP and certain of its subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are: o Electric load and customer growth. o Abnormal weather conditions. o Available sources and costs of fuels. o Availability of generating capacity. o The speed and degree to which competition is introduced to our power generation business. o The structure and timing of a competitive market and its impact on energy prices or fixed rates. o The ability to recover stranded costs in connection with possible/proposed deregulation of generation. o New legislation and government regulations. o The ability of AEP to successfully control its costs. o The success of new business ventures. o International developments affecting AEP's foreign investments. o The economic climate and growth in AEP's service territory. o Inflationary trends. o Electricity and gas market prices. o Interest rates o Liquidity in the wholesale markets o Other risks and unforeseen events. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 American Electric Power Company, Inc.'s (AEP) principal operating business segments and their major activities are: o Wholesale o Generation of electricity for sale to retail and wholesale customers o Gas pipeline and storage services o Marketing and trading of electricity, gas and coal o Coal mining, bulk commodity barging operations and other energy supply related business. o Energy Delivery o Domestic electricity transmission, o Domestic electricity distribution o Other Investments o Foreign electric distribution and supply investments, o Telecommunication services. Net Income Net income for the second quarter was $62 million or $0.19 per share, a decrease of $170 million or $0.53 per share. AEP had a loss of $107 million ($0.33 per share) year-to-date compared with net income of $498 million ($1.54 per share) in 2001. A decline in system sales and margins, natural gas trading losses and charges associated with the impairment and divesture of foreign retail electricity and gas supply and distribution operations account for the decrease. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Domestic Gas Pipeline and Storage Activities - We recognize revenues from domestic gas pipeline and storage services 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. Energy Marketing and Trading Activities - We engage in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase. Therefore, over the term of a trading contract an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading and derivative contract assets or liabilities. The majority of our trading activities represent physical forward electricity and gas contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity or gas in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and the realized cost is included in purchased energy expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. A recently issued accounting pronouncement will require us to report our trading transactions on a net basis beginning in the third quarter of 2002. Our adoption of this new standard will lead to a material decrease in both revenues and purchased energy expense. See "New Accounting Standard" section in Registrants' Combined Management Discussion and Analysis of Financial Condition, Contingencies and Other Matters. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity or gas in July. If we do nothing else with these contracts until settlement in July and if the commodity type, volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. Of course we could have also done a similar transaction but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to commodity type, volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. Trading of electricity and gas options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle. When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on Company-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. 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 trading contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the Company-developed price models. This is particularly true for long-term contracts. We also mark-to-market derivatives that are not trading contracts in accordance with generally accepted accounting principles. Derivatives are contracts whose value is derived from the market value of an underlying commodity. We defer as regulatory assets or liabilities the effect on net income of marking to market open forward electricity trading contracts in our regulated jurisdictions since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Changes in mark-to-market valuations impact net income in our non-regulated gas and electricity business. Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk and causing our results of operations to be subject to volatility. See "Quantitative and Qualitative Disclosures About Market Risks" section of this report for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities. RESULTS OF OPERATIONS Net income for the second quarter of 2002 decreased by $170 million and by $605 million year-to-date. Reduced margins resulting from lower wholesale energy prices, losses from gas trading and marketing and losses associated with the impairment and divesture of SEEBOARD in the UK and CitiPower in Australia, two foreign retail electricity and gas supply and distribution investments, account for the decreases. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Also contributing to the year-to-date decrease was a transitional goodwill impairment loss related to SEEBOARD and CitiPower from the adoption of SFAS 142 (see Note 2) that has been reported as a cumulative effect of an accounting change retroactive to January 1, 2002. The rise in revenues from gas marketing and trading can be attributed to an increase in gas marketing and trading volume, up 123% year-to-date, as we expanded our gas trading operations around Houston Pipe Line (HPL) that we acquired in June 2001. Gas marketing and trading volume also rose in the second quarter as the Company continued unwinding positions that led to a first-quarter gas trading loss. The decrease in electric marketing and trading revenues was largely driven by the decline in system sales due to lower wholesale energy prices that decreased margins.
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing And Trading* $ (558) (6) $(1,306) (7) Gas Marketing and Trading 1,289 36 1,274 18 Energy Delivery* 13 1 22 1 Other Investments 20 18 8 3 ------ ------- Total $ 764 5 $ (2) - ====== =======
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery.
The changes in the total expenses were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel and Purchased Energy: Electricity Marketing And Trading $ (967) (11) $(1,899) (11) Gas Marketing and Trading 1,528 45 1,663 24 Other Investments 24 46 61 59 Maintenance and Other Operation 423 47 519 29 Depreciation and Amortization 38 12 68 11 Taxes other Than Income Taxes 9 5 27 8 ------ ------ $1,055 8 $ 439 2 ====== ======
The decrease in fuel and purchased energy expense was primarily attributable to a reduction in power generation and purchases and lower fuel costs reflecting lower market prices than in the second quarter of 2001. Net generation decreased 1.2% from last year due to the reduced demand for electricity and planned maintenance outages for various plants. The cost of purchased power for resale was also lower due to reduced demand and a continuation of the market conditions that developed in the fourth quarter of 2001. The increase in gas marketing and trading purchased energy expense was primarily due to an expansion of gas trading activity around our HPL pipeline assets. Maintenance and other operation expense increased largely as a result of material and labor costs incurred in connection with the construction of gas-fired plants for third parties; the expenses of recently acquired businesses MEMCO, a barging line; Quaker Coal; and two power plants in the UK; and a charge associated with the impairment and divestiture of CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia. These cost increases were partially offset by a reduction in trading incentive compensation. Project fees for the construction of gas-fired plants for third parties are recognized in revenues on a percentage of completion method, consequently, the charges to expense for material and labor costs do not adversely affect net income. On July 19, 2002, AEP, through a wholly owned subsidiary entered into an agreement to sell CitiPower, and recorded a net impairment charge totaling $125 million. $163 million (excluding tax of $65 million) was recorded in operating expenses in the second quarter of 2002 (see Note 3). $27 million of net impairment loss has been classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 2) and has been recorded as a cumulative effect of an accounting change retroactive to January 1, 2002. Other income decreased due to the gain from the sale of Frontera in 2001. The decrease in income taxes is predominately due to a decrease in pre-tax income. The decrease in interest was primarily due to the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (in millions, except per-share amounts) (UNAUDITED) Three Months Ended Six Months Ended June 30, June 30, 2002 2001 2002 2001 ---- ---- ---- ---- REVENUES: Electricity Marketing and Trading $9,001 $9,559 $17,525 $18,831 Gas Marketing and Trading 4,886 3,597 8,477 7,203 Domestic Electric Delivery 896 883 1,694 1,672 Other Investments 129 109 246 238 ------- ------- ------- ------- TOTAL REVENUES 14,912 14,148 27,942 27,944 ------- ------- ------- ------- EXPENSES: Fuel and Purchased Energy: Electricity Marketing and Trading 7,757 8,724 15,046 16,945 Gas Marketing and Trading 4,929 3,401 8,602 6,939 Other Investments 76 52 165 104 ------- ------- ------- ------- TOTAL FUEL AND PURCHASED ENERGY 12,762 12,177 23,813 23,988 ------- ------- ------- ------- Maintenance and Other Operation 1,332 909 2,325 1,806 Depreciation and Amortization 367 329 710 642 Taxes Other Than Income Taxes 178 169 364 337 ------- ------- ------- ------- TOTAL EXPENSES 14,639 13,584 27,212 26,773 ------- ------- ------- ------- OPERATING INCOME 273 564 730 1,171 OTHER INCOME 46 101 63 154 OTHER EXPENSE 7 28 29 47 LESS: INTEREST 204 217 414 464 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 3 2 5 5 MINORITY INTEREST IN FINANCE SUBSIDIARY 9 - 18 . - ------- ------- ------- ------- INCOME BEFORE INCOME TAXES 96 418 327 809 INCOME TAXES 38 163 120 321 ------- ------- ------- ------- INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 58 255 207 488 Discontinued Operations (net of tax) 4 25 36 58 Extraordinary Loss - (net of tax) - (48) - (48) Cumulative Effect of Goodwill Transition Impairment - - (350) - ------- ------- ------- ------- NET INCOME (LOSS) $ 62 $ 232 $ (107) $ 498 ======= ======= ======== ======= AVERAGE NUMBER OF SHARES OUTSTANDING 326 322 324 322 === === === === EARNINGS (LOSS) PER SHARE (BASIC AND DULUTIVE): Income Before Discontinued Operations, Extraordinary Item and Cumulative Effect of a Change in Accounting Principle $ 0.18 $ 0.79 $ 0.64 $1.51 Discontinued Operations 0.01 0.08 0.11 0.18 Extraordinary Loss - (0.15) - (0.15) Cumulative Effect of a Change in Accounting Principle - - (1.08) - ------ ------ ------ ----- EARNINGS (LOSS) PER SHARE (BASIC AND DILUTIVE) $ 0.19 $ 0.72 $(0.33) $1.54 ====== ====== ====== ===== CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.20 $1.20 ===== ===== ===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 (in millions) ASSETS ------ CURRENT ASSETS: Cash and Cash Equivalents $ 585 $ 244 Accounts Receivable (net) 2,638 1,687 Fuel, Materials and Supplies 1,146 1,048 Energy Trading and Derivative Contracts 9,466 8,572 Other 1,276 688 ------- ------- TOTAL CURRENT ASSETS 15,111 12,239 ------- ------- PROPERTY, PLANT AND EQUIPMENT: Electric: Production 18,090 17,477 Transmission 5,971 5,879 Distribution 9,827 9,661 Other (including gas, coal mining and nuclear fuel) 4,086 4,597 Construction Work in Progress 1,274 1,102 ------- ------- Total Property, Plant and Equipment 39,248 38,716 Accumulated Depreciation and Amortization 15,807 15,456 ------- ------- NET PROPERTY, PLANT AND EQUIPMENT 23,441 23,260 ------- ------- REGULATORY ASSETS 2,314 3,162 ------- ------- SECURITIZED TRANSITION ASSET 751 - ------- ------- INVESTMENTS IN POWER, DISTRIBUTION AND COMMUNICATIONS PROJECTS 540 633 ------- ------- ASSETS HELD FOR SALE 2,750 2,832 ------- ------- GOODWILL 482 417 ------- ------- INTANGIBLE ASSETS 366 474 ------- ------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,672 2,370 ------- ------- OTHER ASSETS 1,731 1,894 ------- ------- TOTAL $51,158 $47,281 ======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in millions) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts Payable $ 2,641 $ 1,985 Short-term Debt 3,041 4,011 Long-term Debt Due Within One Year 1,506 1,114 Energy Trading And Derivative Contracts 9,538 8,311 Other 1,789 1,926 ------- ------- TOTAL CURRENT LIABILITIES 18,515 17,347 -------- ------- LONG-TERM DEBT 10,094 9,052 ------- ------- EQUITY UNIT SENIOR NOTES 376 - ------- ------- LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 3,444 2,183 ------- ------- DEFERRED INCOME TAXES 4,326 4,555 ------- ------- DEFERRED INVESTMENT TAX CREDITS 474 491 ------- ------- DEFERRED CREDITS AND REGULATORY LIABILITIES 863 871 ------- ------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 190 194 ------- ------- OTHER NONCURRENT LIABILITIES 1,321 1,334 ------- ------- LIABILITIES HELD FOR SALE 1,955 1,798 ------- ------- COMMITMENTS AND CONTINGENCIES (Note 8) 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 750 750 ------- ------- CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 145 156 ------- ------- COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50: 2002 2001 ---- ---- Shares Authorized. . .600,000,000 600,000,000 Shares Issued. . . . .347,833,712 331,234,997 (8,999,992 shares were held in treasury at June 30, 2002 and December 31, 2001) 2,261 2,153 Paid-in Capital 3,413 2,906 Accumulated Other Comprehensive Income (Loss) (92) (126) Retained Earnings 2,802 3,296 ------- ------- TOTAL COMMON SHAREHOLDERS' EQUITY 8,384 8,229 ------- ------- TOTAL $51,158 $47,281 ======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in millions) OPERATING ACTIVITIES: Net Income (Loss) $ (107) $ 498 Adjustments for Noncash Items: Depreciation and Amortization 710 664 Deferred Federal Income Taxes (111) 11 Deferred Investment Tax Credits (10) (17) Amortization of Deferred Property Taxes 35 82 Amortization of Cook Plant Restart Costs 20 20 Deferred Costs Under Fuel Clause Mechanisms (35) 50 Transitional Impairment of Goodwill 350 - Provision for Loss on CitiPower 98 - Discontinued Operations (36) (58) Extraordinary Loss - Effects of Deregulation - 48 Mark to Market on Open Energy Trading Contracts (87) (260) Realized Mark to Market on Settled Energy Trading Contracts 294 (5) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (941) (1,205) Fuel, Materials and Supplies 250 (108) Accrued Utility Revenues (182) (84) Prepayments and Other (73) 1 Accounts Payable 354 (1,643) Taxes Accrued (15) 53 Interest Accrued 57 48 Option Premiums 49 (161) Change in Other Assets (841) 2,694 Change in Other Liabilities 317 (63) ------- ------- Net Cash Flows From Operating Activities 96 565 ------- ------- INVESTING ACTIVITIES: Construction Expenditures (783) (812) Purchase of Houston Pipe Line - (727) Sale of Yorkshire - 383 Sale of Frontera - 265 Other (21) (97) ------- ------- Net Cash Flows Used For Investing Activities (804) (988) ------- ------- FINANCING ACTIVITIES: Issuance of Common Stock 656 9 Issuance of Long-term Debt 1,786 1,388 Issuance of Equity Unit Senior Notes 334 - Change in Short-term Debt (net) (970) (275) Retirement of Long-term Debt (357) (463) Dividends Paid on Common Stock (387) (387) ------- ------- Net Cash Flows From Financing Activities 1,062 272 ------- ------- Effect of Exchange Rate Change on Cash (13) - ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents 341 (151) Cash and Cash Equivalents at Beginning of Period 244 363 ------- ------- Cash and Cash Equivalents at End of Period $ 585 $ 212 ======= =======
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $335 million and $342 million and for income taxes was $307 million and $107 million in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $2 million in 2002 and $21 million in 2001, respectively. See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (UNAUDITED) Accumulated Other Common Paid-in Retained Comprehensive Stock Capital Earnings Income (Loss) Total ----- ------- -------- ------------- ----- (in millions) JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054 Issuance of Common Stock 1 8 9 Common Stock Dividends (387) (387) Other (7) 9 2 ------ 7,678 Comprehensive Income: Other Comprehensive Income, Net of Taxes Currency Translation Adjustment (53) (53) Unrealized Gain on Hedged Derivative 31 31 Minimum Pension Liability (6) (6) Net Income 498 498 ------ Total Comprehensive Income 470 ------ ------ ------ ----- ------ JUNE 30, 2001 $2,153 $2,916 $3,210 $(131) $8,148 ====== ====== ====== ===== ====== JANUARY 1, 2002 $2,153 $2,906 $3,296 $(126) $8,229 Issuance of Common Stock 108 568 676 Common Stock Dividends (387) (387) Other (61) (61) ------ 8,457 Comprehensive Income: Other Comprehensive Income, Net of Taxes Currency Translation Adjustment 73 73 Unrealized Loss on Cash Flow Hedges (39) (39) Net Income (Loss) (107) (107) ------- Total Comprehensive Income (73) ------ ------ ------ ---- ------ JUNE 30, 2002 $2,261 $3,413 $2,802 $(92) $8,384 ====== ====== ====== ==== ======
See Notes to Financial Statements beginning on page L-1. AEP GENERATING COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 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. Net income declined $345,000 or 17% for the second quarter and $432,000 or 11% for the year-to-date period due to limits on recovery of return on capital related to operating and in-service ratios of the Rockport Plant. Increased recoverable operating expenses resulted in a $1,139,000 increase in operation revenues for the second quarter. A decrease in operating revenues of $9,493,000 for the year-to-date period resulted from a decrease in recoverable expenses, primarily fuel, as generation declined due to a decrease in the Rockport Plant's availability. Outages for planned maintenance at both units in the first quarter of 2002 decreased Rockport Plant's generation. Operating expenses increased 3% in the second quarter and declined 8% for the year-to-date period as follows:
Increase (Decrease) ------------------- Second Quarter Year-to-Date -------------- ------------ (in thousands) % (in thousands) % -------------- - -------------- - Fuel $1,274 6 $(8,871) (19) Rent - Rockport Plant Unit 2 - - - - Other Operation 1,646 70 1,910 36 Maintenance (1,593) (40) (543) (9) Depreciation 40 1 87 1 Taxes Other Than Income Taxes (118) (12) (108) (5) Income Taxes 268 N.M. (1,550) (62) ------ ------- Total $1,517 3 $(9,075) (8) ====== =======
N.M. = Not Meaningful Fuel expense increased in the second quarter due to an increase in generation and decreased due to the decline in generation for the year-to-date period. The increases in other operation expense are primarily due to higher costs for employee benefits and property insurance. Maintenance expense decreased significantly in the second quarter due to scheduled boiler inspection and repair being in the first quarter 2002 verses second quarter 2001. Maintenance costs declines in both periods reflect cost control efforts. The decrease in income taxes attributable to operations for the year-to-date period is primarily due to an over-accrual of state income taxes during first quarter of 2001 based on an estimate of higher taxable income for the year 2001 than actually occurred. The over-accrual was adjusted beginning in the second quarter of 2001 resulting in higher comparable income taxes for the second quarter of 2002. Interest charges declined 23% in the second quarter and 11% for the year-to-date period due to lower interest rates on short-term borrowing through AEP's money pool reflecting market conditions and lower outstanding balances.
AEP GENERATING COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES - Sales to AEP Affiliates $53,356 $52,217 $103,231 $112,724 ------- ------- -------- -------- OPERATING EXPENSES: Fuel 21,535 20,261 39,035 47,906 Rent - Rockport Plant Unit 2 17,070 17,070 34,141 34,141 Other Operation 4,014 2,368 7,236 5,326 Maintenance 2,378 3,971 5,354 5,897 Depreciation 5,642 5,602 11,275 11,188 Taxes Other Than Income Taxes 907 1,025 1,960 2,068 Income Taxes 306 38 959 2,509 ------- ------- -------- -------- TOTAL OPERATING EXPENSES 51,852 50,335 99,960 109,035 ------- ------- -------- -------- OPERATING INCOME 1,504 1,882 3,271 3,689 NONOPERATING INCOME 32 - 34 - NONOPERATING EXPENSES 94 1 106 10 NONOPERATING INCOME TAX CREDITS 823 888 1,655 1,759 INTEREST CHARGES 547 706 1,243 1,395 ------- ------- -------- ------- NET INCOME $ 1,718 $ 2,063 $ 3,611 $ 4,043 ======= ======= ======== =======
STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $14,604 $10,743 $13,761 $ 9,722 NET INCOME 1,718 2,063 3,611 4,043 CASH DIVIDENDS DECLARED 1,050 959 2,100 1,918 ------- ------- ------- ------- BALANCE AT END OF PERIOD $15,272 $11,847 $15,272 $11,847 ======= ======= ======= =======
The common stock of AEGCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $641,903 $638,297 General 2,883 3,012 Construction Work in Progress 10,993 6,945 -------- -------- Total Electric Utility Plant 655,779 648,254 Accumulated Depreciation 349,825 337,151 -------- -------- NET ELECTRIC UTILITY PLANT 305,954 311,103 -------- -------- OTHER PROPERTY AND INVESTMENTS 119 119 -------- -------- CURRENT ASSETS: Cash and Cash Equivalents - 983 Accounts Receivable: Affiliated Companies 28,800 22,344 Miscellaneous 147 147 Fuel - at average cost 19,157 15,243 Materials and Supplies - at average cost 4,437 4,480 Prepayments 86 244 -------- -------- TOTAL CURRENT ASSETS 52,627 43,441 -------- -------- REGULATORY ASSETS 5,089 5,207 -------- -------- DEFERRED CHARGES 2,973 1,471 -------- -------- TOTAL ASSETS $366,762 $361,341 ======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (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 15,272 13,761 -------- -------- Total Common Shareholder's Equity 39,706 38,195 Long-term Debt 44,798 44,793 -------- -------- TOTAL CAPITALIZATION 84,504 82,988 -------- -------- OTHER NONCURRENT LIABILITIES 421 76 -------- -------- CURRENT LIABILITIES: Advances from Affiliates 9,775 32,049 Accounts Payable: General 8,770 7,582 Affiliated Companies 29,867 1,654 Taxes Accrued 8,592 4,777 Rent Accrued - Rockport Plant Unit 2 4,963 4,963 Other 3,641 3,481 -------- -------- TOTAL CURRENT LIABILITIES 65,608 54,506 -------- -------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 113,832 116,617 -------- -------- REGULATORY LIABILITIES: Deferred Investment Tax Credit 54,635 56,304 Amounts Due to Customers for Income Taxes 21,393 22,725 -------- -------- TOTAL REGULATORY LIABILITIES 76,028 79,029 -------- -------- DEFERRED INCOME TAXES 26,369 27,975 -------- -------- DEFERRED CREDITS - 150 -------- -------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $366,762 $361,341 ======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 (in thousands) OPERATING ACTIVITIES: Net Income $ 3,611 $ 4,043 Adjustment for Noncash Items: Depreciation 11,275 11,188 Deferred Income Taxes (2,938) (2,935) Deferred Investment Tax Credits (1,669) (1,673) Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (2,785) (2,785) Deferred Property Taxes (1,786) (1,829) Changes in Certain Current Assets and Liabilities: Accounts Receivable (6,456) 5,713 Fuel, Materials and Supplies (3,871) (7,644) Accounts Payable 29,401 6,852 Taxes Accrued 3,815 5,833 Change in Other Assets 43 (5) Change in Other Liabilities 355 (2,366) -------- -------- Net Cash Flow From Operating Activities 28,995 14,392 -------- -------- INVESTING ACTIVITIES - Construction Expenditures (5,604) (1,537) -------- -------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) (22,274) (12,903) Dividends Paid (2,100) (1,918) -------- -------- Net Cash Flows Used For Financing Activities (24,374) (14,821) -------- -------- Net Increase in Cash and Cash Equivalents (983) (1,966) Cash and Cash Equivalents at Beginning of Period 983 2,757 -------- -------- Cash and Cash Equivalents at End of Period $ - $ 791 ======== ========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $1,132,000 and $1,143,000 and for income taxes was $1,217,000 and $1,350,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. APPALACHIAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 APCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 917,000 retail customers in southwestern Virginia and southern West Virginia. APCo 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 marketers including power trading transactions. APCo also sells wholesale power to municipalities. The cost of the AEP System'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. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to APCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on APCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Results of Operations Net income increased $10.2 million or 28% for the quarter due to decreased interest charges and lower general operating expenses. Net income increased $3.7 million or 4% for the year-to-date period due to decreases in interest charges offset in part by lower wholesale energy prices that reduced margins. The following analyzes the changes in operating revenues:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading Purchases $(543) (33) $(1,059) (31) Energy Delivery* (8) (6) (6) (2) Sales to AEP Affiliates 5 12 - - ----- ------- Total $(546) (30) $(1,065) (28) ===== =======
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in revenues was due primarily to reduced sales by the AEP Power Pool due to lower wholesale energy prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. APCo, as a member of the AEP Power Pool, shares in the revenues and costs of wholesale marketing and trading activities conducted on its behalf by the AEP Power Pool. Energy delivery revenues decreased due to the continuing economic recession in 2002. The changes in the components of operating expenses were:
Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $ 22 26 $ 34 19 Electricity Marketing and Trading Purchases (543) (38) (1,016) (35) Purchases from AEP Affiliates (27) (32) (72) (38) Other Operation (4) (6) (2) (2) Maintenance (6) (18) (13) (20) Depreciation and Amortization 3 6 6 7 Taxes Other Than Income Taxes - - (1) (1) Income Taxes 3 15 - - ----- -------- Total $(552) (31) $(1,064) (29) ===== =======
Fuel expense increased due to an increase in electric generation as certain plants that had undergone boiler plant maintenance in 2001 were available for service in 2002. The decline in electricity marketing and trading purchases was mainly due to reduced prices caused by market conditions affecting the electricity trading industry. Purchases from AEP affiliates decreased due to the increase in internal generation as a result of certain plants being available for service in 2002 that had undergone boiler plant maintenance in 2001. The decrease in other operations expense in the quarter is mainly due to a decrease in transmission equalization charges caused by a reduction in APCo's MLR. The decrease in maintenance expense is primarily due to the effect of boiler plant maintenance performed on certain plants in 2001. Depreciation and amortization expense increased predominantly due to the additional accelerated amortization beginning in July 2001 of transition regulatory assets in connection with the discontinuance of SFAS 71 in the Company's West Virginia jurisdiction whereby net generation-related regulatory assets were transferred to the distribution portion of the business commensurate with their recovery through regulated rates (see Note 4 for further discussion of the effects of restructuring). Additional investments in distribution and production plant also contributed to the increase in depreciation and amortization expense. The increase in income taxes from operations for the quarter was due to an increase in pre-tax operating income. Nonoperating income and expense decreased largely due to reduced margins on electricity trading outside of AEP's traditional marketing area caused by market conditions affecting the electricity trading industry in the second quarter and by decreased electricity demand in the first quarter resulting from mild weather and the slow economic recovery. The decrease in interest charges for the quarter was due to increased allowances for borrowed funds as a result of increased construction expenditures and lower AEP money pool interest rates and balances. Interest charges decreased for the year-to-date period primarily due to increased allowances for borrowed funds as a result of increased construction expenditures, the retirement of first mortgage bonds on March 1, 2001 and lower AEP money pool interest rates.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $1,113,871 $1,656,905 $2,371,226 $3,430,799 Energy Delivery 139,475 147,924 294,470 300,021 Sales to AEP Affiliates 49,934 44,475 92,740 92,611 ---------- ---------- ---------- ---------- TOTAL OPERATING REVENUES 1,303,280 1,849,304 2,758,436 3,823,431 ---------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 107,160 85,049 214,650 180,525 Purchased Power: Electricity Marketing and Trading 885,469 1,427,844 1,891,068 2,907,372 AEP Affiliates 58,717 85,987 119,497 191,661 Other Operation 64,158 67,948 131,585 133,837 Maintenance 27,638 33,842 53,489 66,851 Depreciation and Amortization 46,909 44,056 93,681 87,773 Taxes Other Than Income Taxes 25,050 25,257 50,045 50,685 Income Taxes 22,955 19,959 57,643 57,213 ---------- ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,238,056 1,789,942 2,611,658 3,675,917 ---------- ---------- ---------- ---------- OPERATING INCOME 65,224 59,362 146,778 147,514 NONOPERATING INCOME 422,518 649,030 822,690 1,114,435 NONOPERATING EXPENSES 408,245 637,831 806,978 1,096,036 NONOPERATING INCOME TAX EXPENSE 4,820 3,427 5,084 5,576 INTEREST CHARGES 28,069 30,715 55,457 62,131 ---------- ---------- ---------- ---------- NET INCOME 46,608 36,419 101,949 98,206 PREFERRED STOCK DIVIDEND REQUIREMENTS 503 503 1,006 1,006 ---------- ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 46,105 $ 35,916 $ 100,943 $ 97,200 ========== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $46,608 $36,419 $101,949 $98,206 OTHER COMPREHENSIVE INCOME (LOSS): Cashflow Power Hedges 2,217 - 2,217 - Cashflow Interest Rate Hedge (2,128) - (2,128) - Foreign Currency Exchange Rate Hedge - (212) 143 (629) ------- ------- -------- ------- COMPREHENSIVE INCOME $46,697 $36,207 $102,181 $97,577 ======= ======= ======== =======
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $174,651 $149,469 $150,797 $120,584 NET INCOME 46,608 36,419 101,949 98,206 -------- -------- -------- -------- DEDUCTIONS: Cash Dividends Declared: Common Stock 30,984 32,398 61,968 64,797 Preferred Stock 360 360 721 721 Capital Stock Expense 142 143 284 285 -------- -------- -------- -------- BALANCE AT END OF PERIOD $189,773 $152,987 $189,773 $152,987 ======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,107,053 $2,093,532 Transmission 1,215,707 1,222,226 Distribution 1,910,496 1,887,020 General 258,731 257,957 Construction Work in Progress 288,146 203,922 ---------- ---------- Total Electric Utility Plant 5,780,133 5,664,657 Accumulated Depreciation and Amortization 2,370,959 2,296,481 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,409,174 3,368,176 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 51,886 53,736 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 490,983 316,249 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 1,304 13,663 Advances to Affiliates 95,498 - Accounts Receivable: Customers 130,219 113,371 Affiliated Companies 204,490 63,368 Miscellaneous 22,598 11,847 Allowance for Uncollectible Accounts (2,096) (1,877) Fuel - at average cost 38,902 56,699 Materials and Supplies - at average cost 57,262 59,849 Accrued Utility Revenues 22,919 30,907 Energy Trading Contracts 794,212 566,284 Prepayments and Other 29,359 16,018 ---------- ---------- TOTAL CURRENT ASSETS 1,394,667 930,129 ---------- ---------- REGULATORY ASSETS 387,785 397,383 ---------- ---------- DEFERRED CHARGES 42,867 42,265 ---------- ---------- TOTAL ASSETS $5,777,362 $5,107,938 ========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (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 716,071 715,786 Accumulated Other Comprehensive Income (Loss) (108) (340) Retained Earnings 189,773 150,797 ---------- ---------- Total Common Shareowner's Equity 1,166,194 1,126,701 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 17,790 17,790 Subject to Mandatory Redemption 10,860 10,860 Long-term Debt 1,690,024 1,476,552 ---------- ---------- TOTAL CAPITALIZATION 2,884,868 2,631,903 ---------- ---------- OTHER NONCURRENT LIABILITIES 86,148 84,104 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 315,007 80,007 Advances from Affiliates - 291,817 Accounts Payable - General 126,032 131,387 Accounts Payable - Affiliated Companies 142,918 84,518 Taxes Accrued 90,827 55,583 Customer Deposits 20,113 13,177 Interest Accrued 28,180 21,770 Energy Trading Contracts 760,856 549,703 Other 65,784 75,299 ---------- ---------- TOTAL CURRENT LIABILITIES 1,549,717 1,303,261 ---------- ---------- DEFERRED INCOME TAXES 696,835 703,575 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 36,132 38,328 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 432,097 257,129 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 91,565 89,638 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,777,362 $5,107,938 ========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 (in thousands) OPERATING ACTIVITIES: Net Income $ 101,949 $ 98,206 Adjustments for Noncash Items: Depreciation and Amortization 93,737 87,829 Deferred Income Taxes (7,055) 31,726 Deferred Investment Tax Credits (2,196) (2,212) Mark-to-Market Energy Trading Contracts (12,797) (97,010) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (168,502) 69,776 Fuel, Materials and Supplies 20,384 (4,859) Accrued Utility Revenues 7,988 48,007 Accounts Payable 53,045 (3,747) Taxes Accrued 35,244 10,438 Interest Accrued 6,410 5,924 Change in Other Assets (13,851) 22,683 Change in Other Liabilities 7,449 (39,002) --------- --------- Net Cash Flows From Operating Activities 121,805 227,759 --------- --------- INVESTING ACTIVITIES: Construction Expenditures (128,853) (107,876) Proceeds from Sale of Property 583 1,182 --------- --------- Net Cash Flows Used For Investing Activities (128,270) (106,694) --------- --------- FINANCING ACTIVITIES: Change in Short-term Debt (net) - (191,495) Change in Advances to Affiliates (net) (387,315) 310,277 Issuance of Long-term Debt 444,110 - Retirement of Long-term Debt - (175,000) Dividends Paid on Common Stock (61,968) (64,797) Dividends Paid on Cumulative Preferred Stock (721) (721) --------- --------- Net Cash Flows Used For Financing Activities (5,894) (121,736) --------- --------- Net Decrease in Cash and Cash Equivalents (12,359) (671) Cash and Cash Equivalents at Beginning of Period 13,663 5,847 -------- --------- Cash and Cash Equivalents at End of Period $ 1,304 $ 5,176 ======== =========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $47,676,000 and $54,957,000 and for income taxes was $36,585,000 and $17,064,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1,684,000 in 2001, respectively. See Notes to Financial Statements beginning on page L-1. CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 CPL is a public utility engaged in the generation, sale, transmission and distribution of electric power in southern Texas. CPL also sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to retail electric providers (REPs) in Texas, (see "Introduction of Customer Choice" section below). Wholesale power marketing and trading activities are conducted on CPL's behalf by AEPSC. CPL, along with the other AEP electric operating subsidiaries, shares in AEP's forward trades with other utility systems and power marketers. Introduction of Customer Choice On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. CPL currently operates in the ERCOT region of Texas. Under the Texas Restructuring Legislation, each electric utility was required to submit a plan to structurally unbundle its business into a retail electric provider, a power generator, and a transmission and distribution utility. During the year 2000, CPL submitted a plan for separation that was subsequently approved by the PUCT. As a result of this legislation, CPL has functionally separated its generation from its transmission and distribution operations and formed a separate REP. Pending regulatory approval, CPL will corporately separate its generation from its transmission and distribution operations. The REP is a separate legal entity that is a subsidiary of AEP and is not owned by or consolidated with CPL. Since the REP is the electricity supplier to retail customers in the ERCOT area, CPL sells its generation to the REP and provides transmission and distribution services to retail customers in its ERCOT service territory. As a result of the formation of the REP, CPL no longer supplies electricity to retail customers in the ERCOT area. Instead CPL sells its generation to the REP. The implementation of REPs as suppliers to retail customers has caused a significant shift in CPL's sales as described below under "Results of Operations." Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CPL. Trading activities allocated to CPL involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the balance sheet as energy trading contract assets or liabilities. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and the realized cost is included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. 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 determine the fair value of open long-term trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CPL to market risk. See the "Quantitative and Qualitative Disclosure About Market Risk" section of Part I, Item 2 for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Second quarter net income decreased $19 million or 36%, while the year-to-date net income decreased $30 million or 34% primarily due to a slow economic recovery, a significant decline in wholesale prices and the replacement of sales to ultimate retail customers with sales to the REP's in the ERCOT area beginning on January 1, 2002. Operating revenues decreased $171 million for the quarter and $371 million year-to-date as shown below:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(390) (83) $(751) (80) Energy Delivery* 8 5 10 4 Sales to AEP Affiliates 211 N.M. 370 N.M. ----- ----- Total $(171) (26) $(371) (30) ===== =====
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful Electricity marketing and trading revenues decreased as a result of the elimination of retail sales in the ERCOT area as of January 1, 2002 and a decrease in energy trading. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Revenues from sales to AEP affiliates rose substantially due to the supplying of electricity to the newly formed affiliated REP's.Although CPL sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT area, total revenues received were lower because of the lower wholesale prices. Operating expenses declined 27% for the quarter and 31% year-to-date. The changes in the components of operating expenses were:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $ (57) (39) $(155) (52) Electricity Marketing and Trading Purchases (84) (40) (157) (38) Purchases from AEP Affiliates (1) (11) (6) (24) Other Operation (4) (6) (13) (9) Maintenance (3) (18) (10) (27) Depreciation and Amortization 7 14 7 7 Taxes Other Than Income Taxes 6 35 15 40 Income Taxes (17) (50) (25) (48) ----- ----- Total $(153) (27) $(344) (31) ===== =====
Fuel expense decreased due to a decrease in the average unit cost of fuel resulting from lower spot market natural gas prices. Electricity marketing and trading purchases decreased due to a decline in demand for electricity and lower wholesale prices due to the slow economic recovery. The decrease in maintenance and other operation expenses resulted from the effects of a STP nuclear plant refueling outage in 2001. Taxes other than income taxes increased due to the effect of a favorable accrual adjustment in 2001 for ad valorem taxes. The decrease in income tax expense attributable to operations in 2002 was primarily due to a decrease in pre-tax operating income.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $ 77,617 $ 468,428 $ 189,052 $ 940,722 Energy Delivery 176,828 168,433 288,955 278,763 Sales to AEP Affiliates 223,092 11,638 402,753 32,426 -------- ---------- --------- ---------- TOTAL OPERATING REVENUES 477,537 648,499 880,760 1,251,911 -------- ---------- --------- ---------- OPERATING EXPENSES: Fuel 89,956 147,179 144,284 299,032 Purchased Power: Electricity Marketing and Trading 123,118 206,733 251,443 408,529 Affiliates 12,564 14,039 20,491 26,809 Other Operation 71,975 76,189 137,961 151,260 Maintenance 14,782 17,995 25,741 35,282 Depreciation and Amortization 60,923 53,587 102,770 95,978 Taxes Other Than Income Taxes 23,474 17,330 51,396 36,818 Income Taxes 16,426 33,096 26,910 51,700 -------- ---------- --------- ---------- TOTAL OPERATING EXPENSES 413,218 566,148 760,996 1,105,408 -------- ---------- --------- ---------- OPERATING INCOME 64,319 82,351 119,764 146,503 NONOPERATING INCOME (LOSS) 4,472 (697) 14,003 2,502 NONOPERATING EXPENSES 3,478 810 12,865 1,647 NONOPERATING INCOME TAX EXPENSE (CREDIT) (648) 34 (515) 757 INTEREST CHARGES 32,426 28,292 63,437 59,052 -------- ---------- --------- ---------- NET INCOME 33,535 52,518 57,980 87,549 PREFERRED STOCK DIVIDEND REQUIREMENTS 61 61 121 121 -------- ---------- --------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 33,474 $ 52.457 $ 57,859 $ 87,428 ======== ========== ========= ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $33,535 $52,518 $57,980 $87,549 OTHER COMPREHENSIVE INCOME Cash Flow Power Hedge 263 - 263 - ------- ------- ------- ------- COMPREHENSIVE INCOME $33,798 $52,518 $58,243 $87,549 ======= ======= ======= =======
The common stock of CP&L is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $812,080 $790,176 $826,197 $792,219 NET INCOME 33,535 52,518 57,980 87,549 DEDUCTIONS: Cash Dividends Declared: Common Stock 38,502 37,014 77,004 74,028 Preferred Stock 61 61 121 121 -------- -------- -------- -------- BALANCE AT END OF PERIOD $807,052 $805,619 $807,052 $805,619 ======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $3,175,010 $3,169,421 Transmission 698,909 663,655 Distribution 1,301,563 1,279,037 General 243,438 241,137 Construction Work in Progress 158,562 169,075 Nuclear Fuel 251,157 247,382 ---------- ---------- Total Electric Utility Plant 5,828,639 5,769,707 Accumulated Depreciation and Amortization 2,518,016 2,446,027 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,310,623 3,323,680 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 50,005 47,950 ---------- ---------- SECURITIZED TRANSITION ASSET 750,939 - ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 31,136 72,502 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 28,385 10,909 Accounts Receivable: General 87,683 38,459 Affiliated Companies 228,135 6,249 Allowance for Uncollectible Accounts (505) (186) Fuel Inventory - at LIFO cost 42,997 38,690 Materials and Supplies - at average cost 52,239 55,475 Energy Trading Contracts 64,633 212,979 Prepayments and Other Current Assets 5,432 2,742 ---------- ---------- TOTAL CURRENT ASSETS 508,999 365,317 ---------- ---------- REGULATORY ASSETS 227,100 226,806 ---------- ---------- REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 171,066 959,294 ---------- ---------- NUCLEAR DECOMMISSIONING TRUST FUND 97,429 98,600 ---------- ---------- DEFERRED CHARGES 89,202 21,837 ---------- ---------- TOTAL ASSETS $5,236,499 $5,115,986 ========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 12,000,000 Shares Outstanding - 2,211,678 Shares at June 30, 2002 6,755,535 Shares at December 31, 2001 $ 55,292 $ 168,888 Paid-in Capital 132,592 405,000 Accumulated Other Comprehensive Income 263 - Retained Earnings 807,052 826,197 ---------- ---------- Total Common Shareowner's Equity 995,199 1,400,085 Preferred Stock 5,967 5,967 CPL - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of CPL 136,250 136,250 Long-term Debt 1,704,374 988,768 ---------- ---------- TOTAL CAPITALIZATION 2,841,790 2,531,070 ---------- ---------- CURRENT LIABILITIES: Short-term Debt Affiliate 200,000 - Long-term Debt Due Within One Year 196,017 265,000 Advances from Affiliates 102,285 354,277 Accounts Payable - General 66,204 65,307 Accounts Payable - Affiliated Companies 155,097 49,301 Customer Deposits 555 26,744 Over Recovered Fuel 61,867 57,762 Taxes Accrued 109,163 83,512 Interest Accrued 25,606 18,524 Energy Trading Contracts 67,321 219,486 Other 23,009 22,768 ---------- ---------- TOTAL CURRENT LIABILITIES 1,007,124 1,162,681 ---------- ---------- DEFERRED INCOME TAXES 1,147,562 1,163,795 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 120,289 122,892 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 28,118 62,138 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 91,616 73,410 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,236,499 $5,115,986 ========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 57,980 $ 87,549 Adjustments for Noncash Items: Depreciation and Amortization 102,770 95,978 Deferred Income Taxes (18,103) (17,699) Deferred Investment Tax Credits (2,603) (2,604) Deferred Property Taxes (19,120) (21,563) Mark-to-Market Energy Trading Contracts 3,932 (8,338) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (270,791) 47,588 Fuel, Materials and Supplies (1,071) (17,688) Fuel Recovery 4,105 33,954 Accounts Payable 106,693 (27,530) Taxes Accrued 25,651 73,457 Change in Other Assets (38,746) (13,442) Change in Other Liabilities (566) 4,152 --------- --------- Net Cash Flows From (Used For) Operating Activities (49,869) 233,814 --------- --------- INVESTING ACTIVITIES: Construction Expenditures (64,147) (109,638) Other - (354) --------- --------- Net Cash Flows Used For Investing Activities (64,147) (109,992) --------- ---------- FINANCING ACTIVITIES: Issuance of Long-term Debt 796,613 - Retirement of Long-term Debt (150,000) (11,971) Change in Short-term Debt Affiliated (net) 200,000 - Retirement of Common Stock (386,004) - Change in Advances from Affiliates (net) (251,992) (46,200) Dividends Paid on Common Stock (77,004) (74,028) Dividends Paid on Cumulative Preferred Stock (121) (121) --------- --------- Net Cash Flows From (Used For) Financing Activities 131,492 (132,320) --------- --------- Net Decrease in Cash and Cash Equivalents 17,476 (8,498) Cash and Cash Equivalents at Beginning of Period 10,909 14,253 --------- --------- Cash and Cash Equivalents at End of Period $ 28,385 $ 5,755 ========= =========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $40,588,000 and $46,083,000 and for income taxes was $44,322,000 and $11,307,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 Columbus Southern Power Company is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 678,000 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 utility systems and power marketers including power trading 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 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 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. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to CSPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse the previously recorded cumulative unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on CSPCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing CSPCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased $30.7 million or 146% in the second quarter of 2002 and $26.9 million or 46% in the year-to-date period due to an extraordinary loss recorded in the prior period second quarter to recognize a stranded asset resulting from deregulation. A decline in revenues is mainly due to a decrease in wholesale sales revenues due to lower wholesale energy prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. The following analyzes the changes in operating revenues:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing And Trading* $(197.1) (20) $(365.8) (18) Energy Delivery* 2.8 2 6.3 3 Sales to AEP Affiliates (1.7) (9) (12.7) (34) ------- ------- Total $(196.0) (18) $(372.2) (17) ======= =======
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in electric marketing and trading revenues was largely driven by the decline in sales by the AEP Power Pool due to lower wholesale energy prices that decreased margins. Operating expenses declined 18% in the second quarter of 2002 and 17% in the year-to-date period of 2002. The changes in the components of operating expenses were:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $ 0.7 2 $ (0.7) (1) Electricity Marketing and Trading Purchases (204.7) (26) (366.4) (23) Purchases from AEP Affiliates 10.1 15 9.4 7 Other Operation 7.8 14 7.4 7 Maintenance (4.7) (24) (9.3) (24) Depreciation and Amortization 1.0 3 2.3 4 Taxes other Than Income Taxes (2.7) (9) (3.2) (5) Income Taxes 1.4 7 (0.5) (1) ------- ------- Total $(191.1) (18) $(361.0) (17) ======= =======
Electricity marketing and trading purchases also declined due to lower wholesale energy costs driven by market conditions. Other operation expense increased in both periods primarily due to post retirement benefits expense and property insurance. Maintenance expenses decreased in the second quarter and year-to-date of 2002 due to boiler overhaul work that was performed during 2001. Expenses for maintaining distribution overhead lines and underground lines were also lower in both periods of 2002. The increase in income taxes for the second quarter is predominately due to an increase in pre-tax income. The decrease in income taxes for the year-to-date period is predominately due to a decrease in pre-tax income and changes in certain book/tax timing differences accounted for on a flow-through basis offset in part by a decrease in deferred state taxes. The decrease in nonoperating income which was offset by a larger decrease in non-operating expenses was due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income and expense. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand. The decrease in interest was primarily due to a decrease in the outstanding balance of long-term debt since the first quarter of 2001, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $772,779 $ 969,836 $1,611,868 $1,977,667 Energy Delivery 123,062 120,314 225,610 219,310 Sales to AEP Affiliates 17,275 18,945 24,953 37,691 -------- ---------- ---------- ---------- TOTAL OPERATING REVENUES 913,116 1,109,095 1,862,431 2,234,668 -------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 43,064 42,368 88,714 89,398 Purchased Power: Electricity Marketing and Trading 572,644 777,356 1,210,565 1,576,995 AEP Affiliates 78,622 68,504 150,204 140,776 Other Operation 62,273 54,510 116,431 109,058 Maintenance 15,050 19,729 29,190 38,509 Depreciation and Amortization 32,402 31,379 65,138 62,861 Taxes Other Than Income Taxes 29,330 32,079 59,606 62,766 Income Taxes 21,691 20,276 38,995 39,479 -------- ---------- ---------- ---------- TOTAL OPERATING EXPENSES 855,076 1,046,201 1,758,843 2,119,842 -------- ---------- ---------- ---------- OPERATING INCOME 58,040 62,894 103,588 114,826 NONOPERATING INCOME 275,637 352,505 533,215 605,351 NONOPERATING EXPENSES 265,114 348,255 519,242 596,047 NONOPERATING INCOME TAX EXPENSE 3,450 1,238 4,797 2,820 INTEREST CHARGES 13,392 18,488 27,185 36,221 -------- ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 51,721 47,418 85,579 85,089 EXTRAORDINARY LOSS - EFFECTS OF DEREGULATION (INCLUSIVE OF TAX BENEFIT OF $8,353,000) - (26,407) - (26,407) -------- ---------- ---------- ---------- NET INCOME 51,721 21,011 85,579 58,682 PREFERRED STOCK DIVIDEND REQUIREMENTS 203 301 384 603 -------- ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 51,518 $ 20,710 $ 85,195 $ 58,079 ======== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $51,721 $21,011 $85,579 $58,682 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Power Hedge 1,449 - 1,449 - ------- ------- ------- ------- COMPREHENSIVE INCOME $53,170 $21,011 $87,028 $58,682 ======= ======= ======= =======
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $187,766 $115,486 $176,103 $ 99,069 NET INCOME 51,721 21,011 85,579 58,682 DEDUCTIONS: Cash Dividends Declared: Common Stock 21,768 20,738 43,534 41,476 Preferred Stock 175 263 350 525 Capital Stock Expense 254 253 508 507 -------- -------- -------- -------- BALANCE AT END OF PERIOD $217,290 $115,243 $217,290 $115,243 ======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,579,404 $1,574,506 Transmission 409,373 401,405 Distribution 1,183,240 1,159,105 General 149,750 146,732 Construction Work in Progress 80,695 72,572 ---------- ---------- Total Electric Utility Plant 3,402,462 3,354,320 Accumulated Depreciation and Amortization 1,424,191 1,377,032 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,978,271 1,977,288 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 39,319 40,369 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 320,819 193,915 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 3,414 12,358 Advances to Affiliates 20,709 - Accounts Receivable: Customers 53,347 41,770 Affiliated Companies 154,468 63,470 Miscellaneous 17,006 16,968 Allowance for Uncollectible Accounts (751) (745) Fuel - at average cost 21,864 20,019 Materials and Supplies - at average cost 39,716 38,984 Accrued Utility Revenues 17,376 7,087 Energy Trading Contracts 518,838 347,198 Prepayments and Other Current Assets 37,919 28,733 ---------- ---------- TOTAL CURRENT ASSETS 883,906 575,842 ---------- ---------- REGULATORY ASSETS 257,378 262,267 ---------- ---------- DEFERRED CHARGES 34,658 56,187 ---------- ---------- TOTAL ASSETS $3,514,351 $3,105,868 ========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 24,000,000 Shares Outstanding - 16,410,426 Shares $ 41,026 $ 41,026 Paid-in Capital 574,877 574,369 Accumulated Other Comprehensive Income 1,449 - Retained Earnings 217,290 176,103 ---------- ---------- Total Common Shareowner's Equity 834,642 791,498 Cumulative Preferred Stock - Subject to Mandatory Redemption - 10,000 Long-term Debt 445,691 571,348 ---------- ---------- TOTAL CAPITALIZATION 1,280,333 1,372,846 ---------- ---------- OTHER NONCURRENT LIABILITIES 37,350 36,715 ---------- ---------- CURRENT LIABILITIES: Preferred Stock Due Within One Year 10,000 - Long-term Debt Due Within One Year 346,343 220,500 Short-term Debt Affiliated 250,000 - Advances from Affiliates - 181,384 Accounts Payable - General 64,131 62,393 Accounts Payable - Affiliated Companies 130,130 83,697 Taxes Accrued 83,181 116,364 Interest Accrued 10,996 10,907 Energy Trading Contracts 495,172 334,958 Other 32,889 34,600 ---------- ---------- TOTAL CURRENT LIABILITIES 1,422,842 1,044,803 ---------- ---------- DEFERRED INCOME TAXES 439,988 443,722 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 35,619 37,176 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 282,341 157,706 ---------- ---------- DEFERRED CREDITS 15,878 12,900 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $3,514,351 $3,105,868 ========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, (in thousands) 2002 2001 ---- ---- OPERATING ACTIVITIES: Net Income $ 85,579 $ 58,682 Adjustments for Noncash Items: Depreciation and Amortization 65,192 63,686 Deferred Federal Income Taxes (5,432) 18,384 Deferred Investment Tax Credits (1,557) (1,671) Deferred Property Tax 23,971 35,416 Mark-to-Market Energy Trading Contracts (11,260) (52,316) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (102,607) (37,869) Fuel, Materials and Supplies (2,577) (6,758) Accrued Utility Revenues (10,289) 9,638 Prepayments and Other Current Assets (9,186) 19,077 Accounts Payable 48,171 28,155 Taxes Accrued (33,183) (45,627) Other Assets (7,865) 10,516 Other Liabilities 3,529 (19,204) --------- -------- Net Cash Flows From Operating Activities 42,486 80,109 --------- -------- INVESTING ACTIVITIES: Construction Expenditures (55,842) (67,532) Proceeds from Sale of Property 389 1,284 --------- -------- Net Cash Flows Used For Investing Activities (55,453) (66,248) --------- -------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) (202,093) 26,570 Change in Short-term Debt Affiliated (net) 250,000 - Dividends Paid on Common Stock (43,534) (41,476) Dividends Paid on Cumulative Preferred Stock (350) (525) --------- -------- Net Cash Flows From (Used For) Financing Activities 4,023 (15,431) --------- -------- Net Increase (Decrease) in Cash and Cash Equivalents (8,944) (1,570) Cash and Cash Equivalents at Beginning of Period 12,358 11,600 --------- -------- Cash and Cash Equivalents at End of Period $ 3,414 $ 10,030 ========= ========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $26,262,000 and $32,812,000 and for income taxes was $32,254,000 and $17,579,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $734,000 in 2001. See Notes to Financial Statements beginning on page L-1. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 I&M is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to 567,000 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 including power trading transactions. I&M also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP System'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. I&M is committed under unit power agreements to purchase all of 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. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, I&M's consolidated financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to I&M as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contracts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since I&M is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). The deferral reflects the fact that power sales and purchases are included in regulated rates on a settlement basis. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities as appropriate. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. 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 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing I&M to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $19.9 million or 73% in the second quarter and $41.2 million or 69% in the year-to-date period due primarily to a reduction in generation as a result of a refueling outage at both units of I&M's Cook Plant, reduced generation at Rockport Plant due to maintenance outages and lower margins on electricity sales. Operating revenues decreased 22% in the second quarter and 21% for the year-to-date period due to decreased wholesale marketing and trading prices and the decline in generation due to power plant outages. The following analyzes the changes in operating revenues:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(255.5) (23) $(481.1) (21) Energy Delivery* (0.3) N.M. (3.7) (2) Sales to AEP Affiliates (19.0) (30) (42.8) (32) ------- ------- Total $(274.8) (22) $(527.6) (21) ======= =======
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful The decrease in electricity marketing and trading revenues was due to a decline in sales by the AEP Power Pool due to lower wholesale energy prices. Revenues from sales to AEP affiliates declined significantly reflecting less power being available for sale as one unit of the Cook Nuclear Plant was shutdown for refueling in each of the first two quarters of 2002 and both units of Rockport Plant underwent scheduled planned boiler maintenance in the first quarter of 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 declined resulting in less power being delivered to the AEP Power Pool. Operating expenses declined in 2002. The changes in the components of operating expenses were:
Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $ (7.3) (12) $ (17.1) (14) Electricity Marketing and Trading Purchases (260.1) (30) (476.3) (27) Purchases from AEP Affiliates 7.3 13 (2.7) (2) Other Operation 11.0 10 25.4 12 Maintenance 8.0 26 10.9 18 Depreciation and Amortization 1.0 3 2.2 3 Taxes other Than Income Taxes 0.5 3 0.5 1 Income Taxes (7.8) (50) (20.6) (60) ------- ------- Total $(247.4) (20) $(477.8) (19) ======= =======
Fuel expense decreased primarily due to the decline in generation reflecting the plant outages as both units of our nuclear plant were refueled in 2002. The decrease in electricity marketing and trading purchases resulted mainly from the decrease in energy prices. Purchases from AEP affiliates increased in the second quarter due to the timing of the Rockport Plant outages in first quarter of 2002 and in second quarter of 2001. I&M is required to purchase AEGCo's Rockport Plant generation under their unit power agreement. Other operation and maintenance expenses increased due to costs related to the nuclear plant refueling outages. The decrease in income tax expense attributable to operations is due primarily to a decline in pre-tax operating income. Nonoperating income and nonoperating expenses decreased due to lower prices for power sold and purchased outside of AEP's traditional marketing area reflecting reduced demand. The decrease in nonoperating income tax expense reflects a decline in pre-tax nonoperating income.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $860,979 $1,116,459 $1,777,992 $2,259,076 Energy Delivery 78,657 78,970 153,194 156,907 Sales to AEP Affiliates 45,401 64,445 92,610 135,429 -------- ---------- ---------- ---------- TOTAL OPERATING REVENUES 985,037 1,259,874 2,023,796 2,551,412 -------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 53,163 60,491 107,319 124,464 Purchased Power: Electricity Marketing and Trading 620,545 880,649 1,312,351 1,788,688 AEP Affiliates 63,110 55,805 116,617 119,353 Other Operation 121,180 110,197 232,946 207,560 Maintenance 39,580 31,506 70,623 59,681 Depreciation and Amortization 41,870 40,840 83,736 81,563 Taxes Other Than Income Taxes 17,855 17,336 36,096 35,574 Income Taxes 7,869 15,710 13,880 34,491 -------- ---------- ---------- ---------- TOTAL OPERATING EXPENSES 965,172 1,212,534 1,973,568 2,451,374 -------- ---------- ---------- ---------- OPERATING INCOME 19,865 47,340 50,228 100,038 NONOPERATING INCOME 315,454 415,752 610,639 718,026 NONOPERATING EXPENSES 303,005 409,323 594,496 705,037 NONOPERATING INCOME TAX EXPENSE 1,313 2,018 888 4,133 INTEREST CHARGES 23,507 24,377 46,931 49,157 -------- ---------- ---------- ---------- NET INCOME 7,494 27,374 18,552 59,737 PREFERRED STOCK DIVIDEND REQUIREMENTS 1,153 1,156 2,308 2,311 -------- ---------- ---------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 6,341 $ 26,218 $ 16,244 $ 57,426 ======== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $ 7,494 $27,374 $18,552 $59,737 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Interest Rate Hedge 1,228 (903) 2,487 (2,822) Power Trading Hedge 1,567 - 1,567 - ------- ------- ------- ------- COMPREHENSIVE INCOME $10,289 $26,471 $22,606 $56,915 ======= ======= ======= =======
The common stock of I&M is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $84,508 $34,651 $74,605 $ 3,443 NET INCOME 7,494 27,374 18,552 59,737 DEDUCTIONS: Cash Dividends Declared - Cumulative Preferred Stock 1,121 1,122 2,243 2,244 Capital Stock Expense 34 34 67 67 ------- ------- ------- ------- BALANCE AT END OF PERIOD $90,847 $60,869 $90,847 $60,869 ======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $2,765,097 $2,758,160 Transmission 958,863 957,336 Distribution 907,104 900,921 General (including nuclear fuel) 238,213 233,005 Construction Work in Progress 114,117 74,299 ---------- ---------- Total Electric Utility Plant 4,983,394 4,923,721 Accumulated Depreciation and Amortization 2,505,922 2,436,972 ---------- ---------- NET ELECTRIC UTILITY PLANT 2,477,472 2,486,749 ---------- ---------- NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 851,070 834,109 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 356,052 215,544 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 121,961 127,977 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 13,708 16,804 Advances to Affiliates - 46,309 Accounts Receivable: Customers 76,763 60,864 Affiliated Companies 189,093 31,908 Miscellaneous 41,366 25,398 Allowance for Uncollectible Accounts (715) (741) Fuel - at average cost 29,340 28,989 Materials and Supplies - at average cost 90,900 91,440 Energy Trading Contracts 587,571 399,195 Accrued Utility Revenues 2,920 2,072 Prepayments 11,027 6,497 ---------- ---------- TOTAL CURRENT ASSETS 1,041,973 708,735 ---------- ---------- REGULATORY ASSETS 412,308 408,927 ---------- ---------- DEFERRED CHARGES 36,183 34,967 ---------- ---------- TOTAL ASSETS $5,297,019 $4,817,008 ========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - No Par Value: Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares $ 56,584 $ 56,584 Paid-in Capital 733,491 733,216 Accumulated Other Comprehensive Income (Loss) 219 (3,835) Retained Earnings 90,847 74,605 ---------- ---------- Total Common Shareowner's Equity 881,141 860,570 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 8,103 8,736 Subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,364,500 1,312,082 ---------- ---------- TOTAL CAPITALIZATION 2,318,689 2,246,333 ---------- ---------- OTHER NONCURRENT LIABILITIES: Nuclear Decommissioning 610,986 600,244 Other 85,716 87,025 ---------- ---------- TOTAL OTHER NONCURRENT LIABILITIES 696,702 687,269 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 290,000 340,000 Advances from Affiliates 11,806 - Accounts Payable: General 118,187 90,817 Affiliated Companies 150,769 43,956 Taxes Accrued 68,048 69,761 Interest Accrued 23,398 20,691 Obligations Under Capital Leases 9,025 10,840 Energy Trading Contracts 564,572 383,714 Other 79,169 72,435 ---------- ---------- TOTAL CURRENT LIABILITIES 1,314,974 1,032,214 ---------- ---------- DEFERRED INCOME TAXES 384,370 400,531 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 101,760 105,449 ---------- ---------- DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 75,739 77,592 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 318,158 175,581 ---------- ---------- DEFERRED CREDITS 86,627 92,039 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,297,019 $4,817,008 ========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 18,552 $ 59,737 Adjustments for Noncash Items: Depreciation and Amortization 83,779 83,090 Deferral of Incremental Nuclear Refueling Outage Expenses (net) (45,701) (771) Unrecovered Fuel and Purchased Power Costs 18,751 18,751 Amortization of Nuclear Outage Costs 20,000 20,000 Deferred Federal Income Taxes (7,723) (4,256) Deferred Investment Tax Credits (3,689) (3,736) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (189,078) 10,372 Fuel, Materials and Supplies 189 (13,858) Accrued Utility Revenues (848) - Accounts Payable 134,183 (41,383) Taxes Accrued (1,713) 31,255 Mark-to-Market Energy Trading Contracts 2,377 (84,756) Regulatory Liability - Trading Gains 838 34,080 Regulatory Assets - Trading Losses (8,166) 4,079 Change in Other Assets (24,349) 18,409 Change in Other Liabilities 11,802 (1,448) --------- --------- Net Cash Flows From Operating Activities 9,204 129,565 --------- --------- INVESTING ACTIVITIES: Construction Expenditures (67,396) (41,321) Buyout of Nuclear Fuel Leases - (92,616) Other - 324 --------- --------- Net Cash Flows Used For Investing Activities (67,396) (133,613) --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 49,648 - Retirement of Cumulative Preferred Stock (424) - Retirement of Long-term Debt (50,000) (44,922) Change in Advances from Affiliates (net) 58,115 48,448 Dividends Paid on Cumulative Preferred Stock (2,243) (2,244) --------- --------- Net Cash Flows From Financing Activities 55,096 1,282 --------- --------- Net Decrease in Cash and Cash Equivalents (3,096) (2,766) Cash and Cash Equivalents at Beginning of Period 16,804 14,835 --------- --------- Cash and Cash Equivalents at End of Period $ 13,708 $ 12,069 ========= =========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $42,695,000 and $46,243,000 and for income taxes was $18,711,000 and $11,073,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $1,020,000 in 2001. See Notes to Financial Statements beginning on page L-1. KENTUCKY POWER COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 KPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power serving 172,000 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 marketers including power trading 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. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, KPCo's financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to KPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. The majority of trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting physical contracts. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contacts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since KPCo is a cost-based rate-regulated entity, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). AEP's traditional marketing area is up to two transmission systems from the AEP service territory. The change in the fair value of physical forward sale and purchase contracts outside AEP's traditional marketing area is included in nonoperating income on a net basis. Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred for contracts with delivery points in AEP's traditional marketing area and for contracts with delivery points outside of AEP's traditional marketing area the unrealized gain or loss is recognized as nonoperating income. When the contract settles the total gain or loss is realized in cash and the impact on the income statement depends on whether the contract's delivery points are within or outside of AEP's traditional marketing area. For contracts with delivery points in AEP's traditional marketing area, the total gain or loss realized in cash is recognized in the income statement. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contacts with delivery points outside of AEP's traditional marketing area only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized in the income statement. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the balance sheet as energy trading assets or liabilities. Trading of electricity options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the cumulative prior unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing KPCo to market risk. See the "Quantitative and Qualitative Disclosures About Market Risk" section of Part I, Item 2 for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Revenues decreased for both the quarter and year-to-date by 28% and 26%, respectively. These declines were offset by improvements in both operating and nonoperating margins resulting in increases in net income of 91% and 58% or $2.5 million for the quarter and $5.7 million year-to-date. The following analyzes the changes in operating revenues:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(120) (30) $(222) (27) Energy Delivery* 1 2 (1) (1) Sales to AEP Affiliates (3) (26) (7) (31) ----- ----- Total $(122) (28) $(230) (26) ===== =====
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. The decrease in revenues is due primarily to a decrease in electricity trading prices in both the first and second quarter. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions.
Significant changes in the components of operating expenses were: Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $ - - $ 4 11 Electricity Marketing and Trading Purchases (125) (36) (231) (33) Purchases from AEP Affiliates - - (7) (10) Other Operation (2) (11) (4) (13) Maintenance 3 56 2 19 Taxes Other Than Income Taxes 1 25 1 14 Income Taxes (1) (25) 1 12
Year-to-date fuel expense increased as a result of fewer credits from profits on trading power and increases in the cost of coal. Under the Kentucky commission's fuel clause mechanism, a portion of the profits on wholesale transactions are shared with the customers. This sharing is recognized through credits to fuel expense. As margins on wholesale electricity marketing and trading transactions declined, the amount of credits shared through the fuel clause adjustment mechanism decreased. The decreases in purchased power expense were attributable to lower prices resulting from general market trends and reduced volume of electricity traded stemming from continued soft demand in the wholesale power market. Other operation expense decreased due to reduced consumption of emission allowances, increased AEP transmission equalization credits and reduced accruals for trading incentive compensation. Under the AEP East Region Transmission Agreement, KPCo and certain affiliates share the costs associated with the ownership of their transmission system based upon each company' peak demand and investment. A decrease in KPCo's peak demand relative to its affiliates' peak demand was the main reason for the increase in transmission equalization credits. Maintenance expense increased as a result of planned power plant outages. Taxes other than income taxes increased with increases in payroll taxes and real and personal property taxes. Income taxes year-to-date have increased primarily as a result of increases in pre-tax income. Decreases in nonoperating income and expenses were due to decreases in power trading revenues and purchases from non-regulated AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. As with power trading activity within the traditional marketing areas, non-regulated trading transactions also experienced declining prices due to reduced demand.
KENTUCKY POWER COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $276,723 $396,250 $586,880 $809,383 Energy Delivery 31,385 30,837 66,514 67,164 Sales to AEP Affiliates 8,893 12,044 14,915 21,741 -------- -------- -------- -------- TOTAL OPERATING REVENUES 317,001 439,131 668,309 898,288 -------- -------- -------- -------- OPERATING EXPENSES: Fuel 17,570 17,418 39,337 35,374 Purchased Power: Electricity Marketing and Trading 224,647 349,388 476,652 707,618 AEP Affiliates 32,366 32,525 61,307 68,160 Other Operation 12,811 14,470 25,280 29,198 Maintenance 8,078 5,185 12,627 10,614 Depreciation and Amortization 8,269 8,080 16,526 16,107 Taxes Other Than Income Taxes 2,368 1,900 4,503 3,949 Income Taxes 1,342 1,801 7,043 6,300 -------- -------- -------- -------- TOTAL OPERATING EXPENSES 307,451 430,767 643,275 877,320 -------- -------- -------- -------- OPERATING INCOME 9,550 8,364 25,034 20,968 NONOPERATING INCOME 108,733 158,973 210,717 272,489 NONOPERATING EXPENSES 104,604 157,076 205,516 268,349 NONOPERATING INCOME TAX EXPENSE 1,920 654 1,730 1,422 INTEREST CHARGES 6,513 6,865 13,013 13,869 -------- -------- -------- -------- NET INCOME $ 5,246 $ 2,742 $ 15,492 $ 9,817 ======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $5,246 $2,742 $15,492 $ 9,817 OTHER COMPREHENSIVE INCOME (LOSS) Cash Flow Power Hedge 572 - 572 - Cash Flow Interest Rate Hedge 357 (68) 873 (1,422) ------ ------ ------- ------- COMPREHENSIVE INCOME $6,175 $2,674 $16,937 $ 8,395 ====== ====== ======= =======
The common stock of KPCo is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $52,035 $57,027 $48,833 $57,513 NET INCOME 5,246 2,742 15,492 9,817 DEDUCTIONS: Cash Dividends Declared 7,044 7,561 14,088 15,122 ------- ------- ------- ------- BALANCE AT END OF PERIOD $50,237 $52,208 $50,237 $52,208 ======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 273,037 $ 271,070 Transmission 373,339 374,116 Distribution 405,503 402,537 General 63,671 65,059 Construction Work in Progress 59,796 15,633 ---------- ---------- Total Electric Utility Plant 1,175,346 1,128,415 Accumulated Depreciation and Amortization 394,818 384,104 ---------- ---------- NET ELECTRIC UTILITY PLANT 780,528 744,311 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 6,354 6,492 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 126,702 77,972 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 918 1,947 Advances to Affiliates 2,165 - Accounts Receivable: Customers 23,516 20,036 Affiliated Companies 40,179 16,012 Miscellaneous 2,707 3,333 Allowance for Uncollectible Accounts (241) (264) Fuel - at average cost 17,479 12,060 Materials and Supplies - at average cost 16,828 15,766 Accrued Utility Revenues 7,813 5,395 Energy Trading Contracts 204,908 139,605 Prepayments 3,212 1,314 ---------- ---------- TOTAL CURRENT ASSETS 319,484 215,204 ---------- ---------- REGULATORY ASSETS 97,615 97,692 ---------- ---------- DEFERRED CHARGES 10,217 11,572 ---------- ---------- TOTAL ASSETS $1,340,900 $1,153,243 ========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $50 Par Value: Authorized - 2,000,000 Shares Outstanding - 1,009,000 Shares $ 50,450 $ 50,450 Paid-in Capital 158,750 158,750 Accumulated Other Comprehensive Income (Loss) (458) (1,903) Retained Earnings 50,237 48,833 ---------- ---------- Total Common Shareowner's Equity 258,979 256,130 Long-term Debt 300,796 251,093 ---------- ---------- TOTAL CAPITALIZATION 559,775 507,223 ---------- ---------- OTHER NONCURRENT LIABILITIES 12,348 11,929 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 155,000 95,000 Advances from Affiliates - 66,200 Accounts Payable: General 32,325 24,050 Affiliated Companies 38,892 22,557 Customer Deposits 6,877 4,461 Taxes Accrued 10,434 10,305 Interest Accrued 4,644 5,269 Energy Trading Contracts 203,518 144,364 Other 14,981 12,296 ---------- ---------- TOTAL CURRENT LIABILITIES 466,671 384,502 ---------- ---------- DEFERRED INCOME TAXES 169,770 168,304 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 9,814 10,405 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 111,507 63,412 ---------- ---------- DEFERRED CREDITS 11,015 7,468 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $1,340,900 $1,153,243 ========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 15,492 $ 9,817 Adjustments for Noncash Items: Depreciation and Amortization 16,526 16,107 Deferred Income Taxes 965 7,921 Deferred Investment Tax Credits (591) (593) Deferred Fuel Costs (net) 2,430 (1,241) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (27,044) 4,012 Fuel, Materials and Supplies (6,481) (672) Accrued Utility Revenues (2,418) 6,500 Accounts Payable 24,610 3,245 Taxes Accrued 129 (6,606) Mark-to-Market Energy Contracts (4,479) (21,923) Change in Other Assets (1,416) 2,336 Change in Other Liabilities 6,355 (4,841) -------- -------- Net Cash Flows From Operating Activities 24,078 14,062 -------- -------- INVESTING ACTIVITIES: Construction Expenditures (51,997) (14,912) Proceeds from Sales of Property - 216 -------- -------- Net Cash Flow Used For Investing Activities (51,997) (14,696) -------- -------- FINANCING ACTIVITIES: Issuance of Long-term Debt - Affiliated Company 123,843 75,000 Retirement of Long-term Debt (14,500) (60,000) Change in Advances from Affiliates (net) (68,365) (405) Dividends Paid (14,088) (15,122) -------- -------- Net Cash Flows From (Used For) Financing Activities 26,890 (527) -------- -------- Net Decrease in Cash and Cash Equivalents (1,029) (1,161) Cash and Cash Equivalents at Beginning of Period 1,947 2,270 -------- -------- Cash and Cash Equivalents at End of Period $ 918 $ 1,109 ======== ========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $13,485,000 and $13,692,000 and for income taxes was $7,024,000 and $6,010,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $22,021 and $760,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. OHIO POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 OPCo is a public utility engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 698,000 customers in the northwestern, east central, eastern and southern sections of Ohio. As a member of the AEP Power Pool, OPCo shares the revenues and the costs of the AEP Power Pool's wholesale sales to neighboring utilities and power marketers including power trading transactions. OPCo also sells wholesale power to municipalities and electric cooperatives. The cost of the AEP System'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. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to OPCo as a member of the AEP Power Pool. Trading activities involve the purchase and sale of energy under physical forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The majority of our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse the previously recorded cumulative unrealized gain or loss. Depending on whether the delivery point for the electricity is in AEP's traditional marketing area or not determines where the contract is reported on OPCo's income statement. AEP's traditional marketing area is up to two transmission systems from the AEP service territory. Physical forward trading sale contracts with delivery points in AEP's traditional marketing area are included in revenues when the contracts settle. Physical forward trading purchase contracts with delivery points in AEP's traditional marketing area are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in AEP's traditional marketing area are included in revenues on a net basis. Physical forward sales contracts for delivery outside of AEP's traditional marketing area are included in nonoperating income when the contract settles. Physical forward purchase contracts for delivery outside of AEP's traditional marketing area are included in nonoperating expenses when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of AEP's traditional marketing area are included in nonoperating income on a net basis. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on results of operations from recording additional changes in fair values using mark-to-market accounting. Trading of electricity options, futures and swaps represents financial transactions with unrealized gains and losses from changes in fair values reported net in nonoperating income until the contracts settle. When these financial contracts settle, we record our share of the net proceeds in nonoperating income and reverse to nonoperating income the prior cumulative unrealized net gain or loss. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing OPCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased $44.8 million in the second quarter of 2002 and $55.4 million in the year-to-date period due to the effect of an extraordinary loss recorded in the second quarter of 2001 to recognize a stranded asset resulting from deregulation. The decline in revenues is mainly due to a decrease in electric marketing and trading revenues due to lower wholesale energy prices. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. The following analyzes the changes in operating revenues:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(337) (25) $(632) (23) Energy Delivery* 10 7 20 8 Sales to AEP Affiliates (4) (3) (36) (13) ----- ----- Total $(331) (20) $(648) (19) ===== =====
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating expenses declined 22% in the second quarter of 2002 and 21% in the year-to-date period of 2002. The changes in the components of operating expenses were:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $(31) (17) $ (89) (23) Electricity Marketing and Trading Purchases (341) (30) (623) (27) Purchases from AEP Affiliates 4 22 1 4 Other Operation 10 10 12 7 Maintenance (7) (18) (13) (18) Depreciation and Amortization 3 6 6 5 Taxes Other Than Income Taxes (1) (3) 4 5 Income Taxes 17 94 21 42 ---- ----- Total $(346) (22) $(681) (21) ===== =====
The fuel expense decrease reflects a reduction of 17% in the average cost fuel for generation offset in part by a 10% increase in MWH generated. Electricity marketing and trading purchases declined due to lower wholesale energy costs driven by market conditions. Other operation expense increased in both periods primarily due to post retirement benefits expense. Maintenance expenses decreased in the second quarter and year-to-date of 2002 due to boiler overhaul work that was performed during 2001. Depreciation expense increased in both periods due to the placement of selective catalytic reduction (SCR) technology in service at the Gavin Plant in the second quarter of 2001. The increase in income taxes for both periods is predominately due to an increase in pre-tax income. The decrease in nonoperating income as well as a decrease in nonoperating expenses was due to a reduction in net gains from AEP Power Pool trading transactions outside of the AEP System's traditional marketing area. The AEP Power Pool enters into power trading transactions for the purchase and sale of electricity and for options, futures and swaps. The Company's share of the AEP Power Pool's gains and losses from forward electricity trading transactions outside of the AEP System traditional marketing area and for speculative financial transactions (options, futures, swaps) is included in nonoperating income and expense. The decrease reflects a reduction in electricity prices and margins due to a decrease in demand. The decrease in interest was primarily due to a slightly smaller decrease in the outstanding balances of long-term debt in both periods as compared to year end balances in both periods, the refinancing of debt at favorable interest rates and a reduction in short-term interest rates.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $1,027,105 $1,364,271 $2,159,297 $2,791,088 Energy Delivery 143,144 133,160 284,904 265,009 Sales to AEP Affiliates 125,393 129,746 235,027 270,745 ---------- ---------- ---------- ---------- TOTAL OPERATING REVENUES 1,295,642 1,627,177 2,679,228 3,326,842 ---------- ---------- ---------- ---------- OPERATING EXPENSES: Fuel 149,097 180,057 291,433 380,618 Purchased Power: Electricity Marketing and Trading 789,191 1,130,038 1,669,348 2,292,322 AEP Affiliates 20,265 16,617 34,492 33,239 Other Operation 106,633 96,623 197,153 185,029 Maintenance 29,957 36,448 58,945 71,848 Depreciation and Amortization 61,176 57,666 123,797 117,725 Taxes Other Than Income Taxes 43,292 44,662 89,131 84,898 Income Taxes 34,985 17,999 70,167 49,340 ---------- ---------- ---------- ---------- TOTAL OPERATING EXPENSES 1,234,596 1,580,110 2,534,466 3,215,019 ---------- ---------- ---------- ---------- OPERATING INCOME 61,046 47,067 144,762 111,823 NONOPERATING INCOME 381,184 538,032 737,525 908,506 NONOPERATING EXPENSES 366,062 528,734 716,885 885,592 NONOPERATING INCOME TAX EXPENSE 626 1,489 4,348 3,997 INTEREST CHARGES 20,194 22,782 41,655 45,249 ---------- ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM 55,348 32,094 119,399 85,491 EXTRAORDINARY LOSS - EFFECTS OF DEREGULATION (INCLUSIVE OF TAX BENEFIT OF $11,585,000) - (21,515) - (21,515) ---------- ---------- -------- ---------- NET INCOME 55,348 10,579 119,399 63,976 PREFERRED STOCK DIVIDEND REQUIREMENTS 315 316 629 630 ---------- ---------- -------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 55,033 $ 10.263 $118,770 $ 63,346 ========== ========== ======== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $55,348 $10,579 $119,399 $63,976 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Exchange Rate Hedge - - (201) - Cash Flow Power Hedges 1,970 (104) 1,970 (325) ------- ------- -------- ------- COMPREHENSIVE INCOME $57,318 $10,475 $121,168 $63,651 ======= ======= ======== =======
The common stock of Ohio Power is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $432,452 $415,425 $401,297 $398,086 NET INCOME 55,348 10,579 119,399 63,976 CASH DIVIDENDS DECLARED: Common Stock 32,582 35,744 65,164 71,488 Cumulative Preferred Stock 315 315 629 629 -------- -------- -------- -------- BALANCE AT END OF PERIOD $454,903 $389,945 $454,903 $389,945 ======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $3,032,034 $3,007,866 Transmission 891,591 891,283 Distribution 1,095,478 1,081,122 General 238,903 245,232 Construction Work in Progress 264,296 165,073 ---------- ---------- Total Electric Utility Plant 5,522,302 5,390,576 Accumulated Depreciation and Amortization 2,513,727 2,452,571 ---------- ---------- NET ELECTRIC UTILITY PLANT 3,008,575 2,938,005 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 59,958 62,303 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 438,789 263,734 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 6,872 8,848 Accounts Receivable: Customers 103,425 84,694 Affiliated Companies 193,372 148,563 Miscellaneous 22,937 20,409 Allowance for Uncollectible Accounts (678) (1,379) Fuel - at average cost 87,396 84,724 Materials and Supplies - at average cost 81,625 88,768 Accrued Utility Revenues 5,276 - Energy Trading Contracts 711,726 472,246 Prepayments and Other 36,624 20,865 ---------- ---------- TOTAL CURRENT ASSETS 1,248,575 927,738 ---------- ---------- REGULATORY ASSETS 611,696 644,625 ---------- ---------- DEFERRED CHARGES 42,290 79,662 ---------- ---------- TOTAL ASSETS $5,409,883 $4,916,067 ========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (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) 1,573 (196) Retained Earnings 454,903 401,297 ---------- ---------- Total Common Shareholder's Equity 1,240,160 1,184,785 Cumulative Preferred Stock: Not Subject to Mandatory Redemption 16,648 16,648 Subject to Mandatory Redemption 8,850 8,850 Long-term Debt 974,350 1,203,841 ---------- ---------- TOTAL CAPITALIZATION 2,240,008 2,414,124 ---------- ---------- OTHER NONCURRENT LIABILITIES 130,298 130,386 ---------- ---------- CURRENT LIABILITIES: Short-term Debt From Affiliated Companies 150,000 - Long-term Debt Due Within One Year 224,850 - Advances from Affiliates 137,069 300,213 Accounts Payable - General 131,398 134,418 Accounts Payable - Affiliated Companies 274,557 176,520 Customer Deposits 9,037 5,452 Taxes Accrued 141,044 126,770 Interest Accrued 21,965 17,679 Obligations Under Capital Leases 14,346 16,405 Energy Trading Contracts 673,621 456,047 Other 56,250 87,070 ---------- ---------- TOTAL CURRENT LIABILITIES 1,834,137 1,320,574 ---------- ---------- DEFERRED INCOME TAXES 781,270 797,889 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 20,395 21,925 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 382,253 214,487 ---------- ---------- DEFERRED CREDITS 21,522 16,682 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $5,409,883 $4,916,067 ========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 119,399 $ 63,976 Adjustments for Noncash Items: Depreciation 86,605 93,161 Amortization of Transition Assets 37,192 36,705 Deferred Federal Income Taxes (18,653) 116 Mark-to-Market Energy Trading Contracts (24,493) (69,557) Deferred Property Taxes 30,046 40,596 Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (66,769) (37,904) Fuel, Materials and Supplies 4,471 2,252 Accrued Utility Revenues (5,276) 264 Prepayments and Other Current Assets (15,759) 15,116 Accounts Payable 95,017 (62,996) Customer Deposits 3,585 (32,368) Taxes Accrued 14,274 (39,022) Interest Accrued 4,286 3,841 Other Operating Assets 6,667 15,877 Other Operating Liabilities (30,834) (44,004) --------- --------- Net Cash Flows From (Used For) Operating Activities 239,758 (13,947) --------- --------- INVESTING ACTIVITIES: Construction Expenditures (158,080) (151,314) Proceeds from Sale of Property and Other 283 7,626 --------- --------- Net Cash Flows Used For Investing Activities (157,797) (143,688) --------- --------- FINANCING ACTIVITIES: Change in Advances to Affiliates (net) (163,144) 344,809 Retirement of Long-term Debt (5,000) (117,506) Change in Short-term Debt Affiliated (net) 150,000 - Dividends Paid on Common Stock (65,164) (71,488) Dividends Paid on Cumulative Preferred Stock (629) (630) --------- --------- Net Cash Flows From (Used For) Financing Activities (83,937) 155,185 --------- --------- Net Decrease in Cash and Cash Equivalents (1,976) (2,450) Cash and Cash Equivalents at Beginning of Period 8,848 31,393 --------- --------- Cash and Cash Equivalents at End of Period $ 6,872 $ 28,943 ========= =========
Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $36,585,000 and $40,580,000 and for income taxes was $29,187,000 and $54,694,000 in 2002 and 2001, respectively. Noncash acquisitions under capital leases were $98,000 and $522,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 PSO is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power to approximately 503,000 retail customers in eastern and southwestern Oklahoma. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on PSO's behalf by AEPSC. PSO, along with the other AEP electric operating subsidiaries, shares in AEP's forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a cost-based rate-regulated electric public utility company, PSO's consolidated financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to PSO. Trading activities allocated to PSO involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. Accounting standards applicable to trading activities require that changes in the fair value of trading contracts be recognized in revenues prior to settlement and is commonly referred to as mark-to-market (MTM) accounting. Since PSO is a cost-based rate-regulated entity, whose revenues are based on settled transactions, unrealized changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Mark-to-market accounting represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed and the actual realized cash gain or loss is recognized in the income statement. Therefore, as the contract's market value changes over the contract's term an unrealized gain or loss is deferred as a regulatory liability or a regulatory asset. When the contract settles the total gain or loss is realized in cash and recognized in the income statement. Physical forward trading sale contracts are included in revenues when the contracts settle. Physical forward trading purchase contracts are included in purchased power expense when they settle. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts are deferred as regulatory liabilities (gains) or regulatory assets (losses). Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing PSO to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income declined by 2.5% for the quarter and 4% for the year-to-date period as substantial decreases in revenues were nearly offset by comparable decreases in operating expenses. The following analyzes the changes in operating revenues:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(153) (47) $(256) (41) Energy Delivery* 10 16 13 12 Sales to AEP Affiliates (2) (19) (11) (56) ----- ----- Total $(145) (36) $(254) (34) ===== =====
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. Operating revenues decreased as a result of a decline in fuel recovery revenue and a decline in AEP marketing and trading revenues shared with PSO. Revenues from AEP's power marketing and trading operations declined as a result of lower prices for wholesale power transactions. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Significant change in operating expenses are as follows:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $(112) (77) $(166) (64) Electricity Marketing and Trading Purchases (44) (35) (77) (30) Purchases from AEP Affiliates 12 53 (8) (14) Other Operation - - (7) (11) Maintenance (1) (8) 3 15 Depreciation and Amortization 1 7 3 7
The decrease in fuel expense was primarily due to amortization of previously overrecovered fuel costs through the fuel clause recovery mechanism and a reduction in the cost of fuel reflecting lower market prices for natural gas and fuel oil. The decrease in electric marketing and trading purchases resulted mainly from the decrease in energy prices. The increase in the quarter and the decrease year-to-date in purchases from AEP affiliates results mainly from the availability of internal generation. Other operation expense decreased in the year-to-date period primarily due to lower transmission, administrative, and customer service expenses. Maintenance expense decreased in the second quarter due primarily to lower production power plant costs and distribution costs for overhead and underground facilities. Year-to-date maintenance expense increased largely as a result of increased expenses to repair damage to overhead lines caused by a winter storm in 2002. Depreciation expense increased for both the quarter and year-to-date due to the cost of repowering Northeast Station Units 1 & 2.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $175,999 $ 329,316 $370,023 $ 625,915 Energy Delivery 70,815 61,294 122,547 109,711 Sales to AEP Affiliates 6,162 7,584 8,256 18,707 -------- ---------- -------- ---------- TOTAL OPERATING REVENUES 252,976 398,194 500,826 754,333 -------- ---------- -------- ---------- OPERATING EXPENSES: Fuel 33,772 145,927 91,869 257,728 Purchased Power: Electricity Marketing and Trading 81,803 126,602 178,323 255,781 AEP Affiliates 34,703 22,659 51,548 60,026 Other Operation 34,826 34,332 61,465 68,889 Maintenance 11,886 12,859 26,055 22,689 Depreciation and Amortization 21,061 19,673 41,977 39,144 Taxes Other Than Income Taxes 8,083 7,533 15,931 15,326 Income Taxes 6,641 6,667 5,047 4,468 -------- ---------- -------- ---------- TOTAL OPERATING EXPENSES 232,775 376,252 472,215 724,051 -------- ---------- -------- ---------- OPERATING INCOME 20,201 21,942 28,611 30,282 NONOPERATING INCOME 1,223 409 1,329 1,233 NONOPERATING EXPENSES 69 336 664 672 NONOPERATING INCOME TAX CREDIT (100) (19) (241) (134) INTEREST CHARGES 9,835 10,113 19,545 20,616 -------- ---------- -------- ---------- NET INCOME 11,620 11,921 9,972 10,361 PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 106 106 -------- ---------- -------- ---------- EARNINGS APPLICABLE TO COMMON STOCK $ 11,567 $ 11.868 $ 9,866 $ 10,255 ======== ========== ======== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $11,620 $11,921 $ 9,972 $10,361 OTHER COMPREHENSIVE INCOME Cash Flow Power Hedge 200 - 200 - ------- ------- ------- ------- COMPREHENSIVE INCOME $11,820 $11,921 $10,172 $10,361 ======= ======= ======= =======
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $118,838 $123,015 $142,994 $137,688 NET INCOME 11,620 11,921 9,972 10,361 DEDUCTIONS: Cash Dividends Declared: Common Stock 22,456 13,060 44,911 26,120 Preferred Stock 53 53 106 106 -------- -------- -------- -------- BALANCE AT END OF PERIOD $107,949 $121,823 $107,949 $121,823 ======== ======== ======== ========
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,040,461 $1,034,711 Transmission 432,990 427,110 Distribution 990,374 972,806 General 203,088 203,572 Construction Work in Progress 58,004 56,900 ---------- ---------- Total Electric Utility Plant 2,724,917 2,695,099 Accumulated Depreciation and Amortization 1,219,697 1,184,443 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,505,220 1,510,656 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 42,383 41,020 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 22,015 55,215 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 6,953 5,795 Accounts Receivable: Customers 35,896 31,100 Affiliated Companies 30,061 10,905 Fuel - at LIFO costs 24,939 21,559 Materials and Supplies - at average costs 36,631 36,785 Under-Recovered Fuel Costs 44,436 - Energy Trading Contracts 41,417 162,200 Prepayments and Other 2,343 2,368 ---------- ---------- TOTAL CURRENT ASSETS 222,676 270,712 ---------- ---------- REGULATORY ASSETS 26,428 35,004 ---------- ---------- DEFERRED CHARGES 26,152 5,290 ---------- ---------- TOTAL ASSETS $1,844,874 $1,917,897 ========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $15 Par Value: Authorized Shares: 11,000,000 Shares Issued Shares: 10,482,000 shares and Outstanding Shares: 9,013,000 Shares $ 157,230 $ 157,230 Paid-in Capital 180,000 180,000 Accumulated Other Comprehensive Income 200 - Retained Earnings 107,949 142,994 ---------- ---------- Total Common Shareholder's Equity 445,379 480,224 Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,283 5,283 PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000 Long-term Debt 310,283 345,129 ---------- ---------- TOTAL CAPITALIZATION 835,945 905,636 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 141,000 106,000 Advances from Affiliates 212,950 123,087 Accounts Payable - General 62,987 72,759 Accounts Payable - Affiliated Companies 76,447 40,857 Customers Deposits 21,869 21,041 Taxes Accrued 15,962 18,150 Over-Recovered Fuel Costs - 8,720 Interest Accrued 3,331 7,298 Energy Trading Contracts 47,305 167,658 Other 17,262 12,296 ---------- ---------- TOTAL CURRENT LIABILITIES 599,113 577,866 ---------- ---------- DEFERRED INCOME TAXES 319,339 296,877 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 33,097 33,992 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 37,170 56,203 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 20,210 47,323 ---------- ---------- TOTAL CAPITALIZATION AND LIABILITIES $1,844,874 $1,917,897 ========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 9,972 $ 10,361 Adjustments for Noncash Items: Depreciation and Amortization 41,977 39,144 Deferred Income Taxes 21,559 (10,754) Deferred Investment Tax Credits (895) (895) Deferred Property Taxes (16,184) (14,951) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (23,952) 17,488 Fuel, Materials and Supplies (3,226) 6,094 Accounts Payable 25,818 (52,882) Taxes Accrued (2,188) 28,006 Fuel Recovery (53,156) 31,748 Changes in Other Assets (2,968) (8,234) Changes in Other Liabilities (4,387) 1,780 --------- -------- Net Cash Flows From (Used For) Operating Activities (7,630) 46,905 --------- -------- INVESTING ACTIVITIES: Construction Expenditures (35,095) (67,042) Other (963) (359) --------- -------- Net Cash Flows Used For Investing Activities (36,058) (67,401) --------- -------- FINANCING ACTIVITIES: Retirement of Long-term Debt - (20,000) Change in Advances From Affiliates (net) 89,863 66,327 Dividends Paid on Common Stock (44,911) (26,120) Dividends Paid on Cumulative Preferred Stock (106) (106) --------- -------- Net Cash Flows From Financing Activities 44,846 20,101 --------- -------- Net Increase in Cash and Cash Equivalents 1,158 (395) Cash and Cash Equivalents at Beginning of Period 5,795 11,301 --------- -------- Cash and Cash Equivalents at End of Period $ 6,953 $ 10,906 ========= ========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $17,870,000 and $19,011,000 and for income taxes was $2,575,000 and $1,978,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 SWEPCo is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in northeastern Texas, northwestern Louisiana, and western Arkansas. SWEPCo also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives. Wholesale power marketing and trading activities are conducted on SWEPCo's behalf by AEPSC. SWEPCo, along with the other AEP electric operating subsidiaries, shares in AEP's forward trades with other utility systems and power marketers. Critical Accounting Policies - Revenue Recognition Regulatory Accounting - Our financial statements reflect the actions of regulators since our electricity supply sales in the Louisiana jurisdiction and our transmission and distribution operations are cost-based rate-regulated. As a result of the regulators' actions, our financial statements can recognize revenues and expenses in different time periods than enterprises that are not rate regulated. In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory liabilities (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. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general expenses are recorded when incurred. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to SWEPCo. Trading activities allocated to SWEPCo involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We generally recognize revenues from open trading activities based on changes in the fair value of energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading contract assets or liabilities. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized cost is included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing SWEPCo to market risk. See "Quantitative and Qualitative Disclosures about Market Risk" section for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income increased slightly in the second quarter and decreased $11 million or 30%, for the first half of 2002. The decrease for the first half of 2002 resulted from reduced wholesale prices and margins due to a decline in demand for electricity which resulted from mild weather and a slow economic recovery. Operating revenues decreased 19% in the second quarter and 20% for the year-to-date period due to decreased wholesale marketing and trading prices. The changes in the components of revenues were as follows:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(74.7) (23) $(153.3) (24) Energy Delivery* (2.0) (2) (11.1) (7) Sales to AEP Affiliates (4.5) (24) (10.2) (22) ------ ------- Total $(81.2) (19) $(174.6) (20) ====== =======
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. All of the components of revenues decreased in 2002 as a result of reduced wholesale prices due to reduced energy demand as a result of a decrease in marketing and trading activity, and the slow economic recovery. Operating expenses decreased 20% in the second quarter and the year-to-date period due to a significant decrease in electricity marketing and trading purchases and fuel expense.
Increase (Decrease) ------------------- Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $(28.9) (23) $ (58.3) (24) Electricity Marketing and Trading Purchases (60.3) (38) (104.0) (33) Purchases from AEP Affiliates - - (5.6) (21) Other Operation 10.7 31 13.5 18 Maintenance 0.5 3 (2.9) (8) Depreciation and Amortization (2.8) (8) (0.7) (1) Taxes Other Than Income Taxes (0.6) (4) 0.8 3 Income Taxes 1.3 16 (4.8) (29) ------ ------- Total $(80.1) (20) $(162.0) (20) ====== =======
Fuel expense decreased due to lower natural gas prices as a result of a mild winter and the slow economic recovery. Decreasing purchased power prices resulted in decreases to both electricity marketing and trading purchases and electricity purchases from AEP affiliates for the second quarter and first half of 2002. The first half of 2002 was also affected by milder than normal winter. The acquisition of Dolet Hills mining operation in June 2001 caused other operation expense to increase in 2002. Maintenance expense decreased for the first half of 2002 as a result of costs incurred last year to restore service and make repairs following a severe ice storm. The decrease in depreciation and amortization expense was due primarily to a decrease in excess earnings accruals under the Texas restructuring legislation offset by new expenses from the acquisition of the Dolet Hills mining operation. The increase in income taxes for the second quarter of 2002 is predominately due to the reversal of deferred taxes in excess of the statutory tax rate, and an increase in pre-tax income. Income taxes attributable to operations decreased for the first half of 2002 due to a significant decrease in pre-tax income. Nonoperating income decreased for the first half of 2002 due primarily to a reduction in interest income earned on under-recovered fuel which resulted from significant natural gas price increases in the second half of 2000 and 2001. During 2001 gas price declines and a PUCT approved fuel rate and fuel surcharge increases lowered the unrecovered fuel balance thus lowering interest income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $255,385 $330,094 $495,730 $649,080 Energy Delivery 84,008 85,970 152,943 164,027 Sales to AEP Affiliates 14,224 18,731 37,184 47,377 -------- -------- -------- -------- TOTAL OPERATING REVENUES 353,617 434,795 685,857 860,484 -------- -------- -------- -------- OPERATING EXPENSES: Fuel 95,207 124,151 184,090 242,397 Purchased Power: Electricity Marketing and Trading 96,349 156,608 207,444 311,403 AEP Affiliates 12,075 12,063 20,516 26,125 Other Operation 44,725 34,071 86,876 73,339 Maintenance 20,942 20,431 32,780 35,667 Depreciation and Amortization 30,533 33,328 60,673 61,458 Taxes Other Than Income Taxes 12,889 13,485 27,355 26,513 Income Taxes 9,317 8,009 12,074 16,947 -------- -------- -------- -------- TOTAL OPERATING EXPENSES 322,037 402,146 631,808 793,849 -------- -------- -------- -------- OPERATING INCOME 31,580 32,649 54,049 66,635 NONOPERATING INCOME 313 850 415 1,683 NONOPERATING EXPENSES (CREDITS) (20) 681 546 1,320 NONOPERATING INCOME TAX EXPENSE (CREDIT) (137) 139 (109) 86 INTEREST CHARGES 13,895 14,895 27,713 29,259 -------- -------- -------- -------- NET INCOME 18,155 17,784 26,314 37,653 -------- -------- -------- -------- PREFERRED STOCK DIVIDEND REQUIREMENTS 58 58 115 115 -------- -------- -------- -------- EARNINGS APPLICABLE TO COMMON STOCK $ 18,097 $ 17,726 $ 26,199 $ 37,538 ======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $18,155 $17,784 $26,314 $37,653 OTHER COMPREHENSIVE INCOME Cash Flow Power Hedge 230 - 230 - ------- ------- ------- ------- COMPREHENSIVE INCOME $18,385 $17,784 $26,544 $37,653 ======= ======= ======= =======
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 RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $298,053 $295,248 $308,915 $293,989 NET INCOME 18,155 17,784 26,314 37,653 DEDUCTIONS: Cash Dividends Declared: Common Stock 18,963 18,552 37,927 37,105 Preferred Stock 58 58 115 115 -------- -------- -------- -------- BALANCE AT END OF PERIOD $297,187 $294,422 $297,187 $294,422 ======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $1,443,282 $1,429,356 Transmission 565,230 538,749 Distribution 1,036,036 1,042,523 General 394,628 376,016 Construction Work in Progress 51,488 74,120 ---------- ---------- Total Electric Utility Plant 3,490,664 3,460,764 Accumulated Depreciation and Amortization 1,606,606 1,550,618 ---------- ---------- NET ELECTRIC UTILITY PLANT 1,884,058 1,910,146 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 44,127 43,000 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 25,267 63,372 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 15,860 5,415 Accounts Receivable: Customers 51,533 44,588 Affiliated Companies 60,171 12,069 Allowance for Uncollectible Accounts (111) (89) Fuel Inventory - at average cost 78,335 52,212 Under-recovered Fuel - 2,501 Materials and Supplies - at average cost 36,932 32,527 Energy Trading Contracts 47,535 186,159 Prepayments 18,993 18,716 ---------- ---------- TOTAL CURRENT ASSETS 309,248 354,098 ---------- ---------- REGULATORY ASSETS 48,165 51,989 ---------- ---------- DEFERRED CHARGES 79,693 67,753 ---------- ---------- TOTAL ASSETS $2,390,558 $2,490,358 ========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $18 Par Value: Authorized - 7,600,000 Shares Outstanding - 7,536,640 Shares $ 135,660 $ 135,660 Paid-in Capital 245,000 245,000 Accumulated Other Comprehensive Income 230 - Retained Earnings 297,187 308,915 ---------- ---------- Total Common Shareowner's Equity 678,077 689,575 Preferred Stock 4,704 4,704 SWEPCO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Junior Subordinated Debentures of SWEPCO 110,000 110,000 Long-term Debt 637,810 494,688 ---------- ---------- TOTAL CAPITALIZATION 1,430,591 1,298,967 ---------- ---------- OTHER NONCURRENT LIABILITIES 14,617 34,997 ---------- ---------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 55,595 150,595 Advances from Affiliates 65,073 117,367 Accounts Payable - General 89,147 71,810 Accounts Payable - Affiliated Companies 94,789 37,469 Customer Deposits 19,446 19,880 Taxes Accrued 61,162 36,522 Interest Accrued 11,473 13,631 Energy Trading Contracts 54,187 192,318 Over-recovered Fuel 9,146 - Other 16,275 26,166 ---------- ---------- TOTAL CURRENT LIABILITIES 476,293 665,758 ---------- ---------- DEFERRED INCOME TAXES 361,712 369,781 ---------- ---------- DEFERRED INVESTMENT TAX CREDITS 46,452 48,714 ---------- ---------- REGULATORY LIABILITIES AND DEFERRED CREDITS 37,754 17,828 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 23,139 54,313 ---------- ---------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $2,390,558 $2,490,358 ========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 ---- ---- (in thousands) OPERATING ACTIVITIES: Net Income $ 26,314 $ 37,653 Adjustments for Noncash Items: Depreciation and Amortization 60,673 61,458 Deferred Income Taxes (9,004) (4,546) Deferred Investment Tax Credits (2,262) (2,212) Mark-to-Market Energy Trading Contracts 7,834 (7,942) Deferred Property Taxes (17,545) (17,703) Changes in Certain Current Assets and Liabilities: Accounts Receivable (net) (55,025) 2,286 Fuel, Materials and Supplies (30,528) (4,266) Accounts Payable 74,657 (45,226) Taxes Accrued 24,640 41,158 Fuel Recovery 11,647 (9,447) Change in Other Assets 10,995 (47,147) Change in Other Liabilities (13,802) 49,536 --------- --------- Net Cash Flows From Operating Activities 88,594 53,602 --------- --------- INVESTING ACTIVITIES: Construction Expenditures (35,695) (49,418) Purchase of Dolet Hills - (85,716) Other (284) (411) --------- --------- Net Cash Flows Used For Investing Activities (35,979) (135,545) --------- --------- FINANCING ACTIVITIES: Issuance of Long-term Debt 198,616 - Retirement of Long-term Debt (150,450) (450) Change in Advances from Affiliates (net) (52,294) 119,660 Dividends Paid on Common Stock (37,927) (37,105) Dividends Paid on Cumulative Preferred Stock (115) (115) --------- --------- Net Cash Flows From (Used For) Financing Activities (42,170) 81,990 --------- --------- Net Increase in Cash and Cash Equivalents 10,445 47 Cash and Cash Equivalents at Beginning of Period 5,415 1,907 --------- --------- Cash and Cash Equivalents at End of Period $ 15,860 $ 1,954 ========= =========
Supplemental Disclosure: Cash paid for interest net of capitalized amounts was $21,331,000 and $25,743,000 and for income taxes was $24,479,000 and $4,144,000 in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1. WEST TEXAS UTILITIES COMPANY MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS SECOND QUARTER 2002 vs. SECOND QUARTER 2001 AND YEAR-TO-DATE 2002 vs. YEAR-TO-DATE 2001 WTU is a public utility engaged in the generation, purchase, sale, transmission and distribution of electric power in west and central Texas. WTU sells electric power at wholesale to other utilities, municipalities, rural electric cooperatives and beginning in 2002 to retail electric providers (REPs) in Texas (see "Introduction of Customer Choice" section below). Wholesale power marketing and trading activities are conducted on WTU's behalf by AEPSC. WTU, along with the other AEP electric operating subsidiaries, shares in AEP's forward trades with other utility systems and power marketers. Introduction of Customer Choice On January 1, 2002, customer choice of electricity supplier began in the Electric Reliability Council of Texas (ERCOT) area of Texas. WTU currently 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 has been required to submit a plan to structurally unbundle its business into a retail electric provider, a power generator, and a transmission and distribution utility. During the year 2000, WTU submitted a plan for separation that was subsequently approved by the PUCT. As a result of this legislation, WTU has functionally separated its generation from its transmission and distribution operations and formed a separate REP. Pending regulatory approval, WTU will corporately separate its generation from its transmission and distribution operations. The REP is a separate legal entity that is a subsidiary of AEP and is not owned by or consolidated with WTU. Since the REP is the electricity supplier to retail customers in the ERCOT area, WTU sells its generation to the REP and provides transmission and distribution services to retail customers in its ERCOT service territory. As a result of the formation of the REP, WTU no longer supplies electricity to retail customers in the ERCOT area. Instead WTU sells its generation to the REP that was unbundled from WTU and also sells its generation to other REPs in the area. The implementation of REPs as suppliers to retail customers has caused a significant shift in WTU's sales as described below under "Results of Operations." Critical Accounting Policies - Revenue Recognition Regulatory Accounting - As a result of our cost-based rate-regulated transmission and distribution operations, our financial statements 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) and regulatory liabilities (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. 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 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 net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates. Traditional Electricity Supply and Delivery Activities - We recognize revenues on an accrual basis for electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when incurred. Energy Marketing and Trading Activities - AEP engages in wholesale electricity marketing and trading transactions (trading activities). A portion of the revenues and costs of AEP's trading activities are allocated to WTU. Trading activities allocated to WTU involve the purchase and sale of energy under physical forward contracts at fixed and variable prices. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of open energy trading contracts. Recording the net change in the fair value of open trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. Under MTM accounting the change in the unrealized gain or loss throughout a contract's term is recognized in each accounting period. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt of electricity and net settle in cash, the unrealized cumulative gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased power expense for a purchase. Therefore, over the trading contract's term an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the balance sheet as energy trading contract assets or liabilities. Our trading activities represent physical forward electricity contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity in July. At the end of each month until the contract settles in July, we would record our share of any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize our share of a gain or loss in cash and reverse to revenues the previously recorded cumulative unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and the realized cost is included in purchased power expense for a purchase contract with the prior change in unrealized fair value reversed in revenues. Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity in July. If we do nothing else with these contracts until settlement in July and if the volumes, delivery point, schedule and other key terms match, then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts from this point forward will have no further impact on results of operations but will have an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on AEP-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. 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 trading contracts. AEP has independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices at settlement do not correlate with the AEP-developed price models. Volatility in commodities markets affects the fair values of all of our open trading contracts exposing WTU to market risk. See the "Quantitative and Qualitative Disclosures about Market Risk" section of Part I, Item 2 for a discussion of the policies and procedures used to manage exposure to risk from trading activities. Results of Operations Net income decreased $5.5 million or 89% for the quarter and $2.4 million or 34% for the year-to-date period. The decreases are primarily due to a downturn in the overall economy, a significant decline in wholesale prices, and the diversion of retail sales from the ultimate retail customer to the REPs in the ERCOT region as of January 1, 2002. Overall operating revenues decreased $50.8 million for the quarter and $104.6 million year-to-date as shown below:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Electricity Marketing and Trading* $(92) (63) $(192) (65) Energy Delivery* (4) (10) (2) (3) Sales to AEP Affiliates 45 N.M. 89 N.M. ---- ----- Total $(51) (26) $(105) (27) ==== =====
*Reflects the allocation of certain transmission and distribution revenues included in bundled retail rates to energy delivery. N.M. = Not Meaningful Electricity marketing and trading revenues decreased primarily as a result of the elimination of retail electricity sales in the ERCOT region as of January 1, 2002. Also contributing to the decrease was a decline in prices for power trading transactions. In 2002 the wholesale energy sector has been under pressure from lower commodity prices in contrast to last year when we had strong performance from the wholesale business due to favorable market conditions. Sales to AEP affiliates increased primarily due to increased revenues to the newly-created affiliated REP. Although WTU sold electricity to the affiliated REP instead of directly to retail customers in the ERCOT region, total revenues received were lower because of the lower wholesale prices. Operating expenses declined $43.7 million for the quarter and $103.3 million year-to-date, primarily due to decreases in fuel expense and purchased power. Changes in the components of operating expenses are shown below:
Increase (Decrease) Second Quarter Year-to-Date (in millions) % (in millions) % - - Fuel $(14) (30) $ (49) (46) Electricity Marketing and Trading Purchases (19) (29) (36) (29) Purchases from AEP Affiliates (6) (37) (15) (40) Other Operation - - (2) (4) Maintenance - - - - Depreciation and Amortization (1) (4) (1) (3) Taxes Other Than Income Taxes (1) (9) - - Income Taxes (3) (116) - - ---- ----- Total $(44) (24) $(103) (28) ==== =====
Fuel expense decreased significantly primarily due to a decrease in the average unit cost of fuel as a result of lower spot market natural gas prices. The decline in electricity marketing and trading purchases was mainly due to reduced prices caused by decreased electricity demand driven largely by the downturn in the economy. The quarter-to-date decrease in income taxes is predominately due to a decrease in pre-tax income. Nonoperating income and expense increased significantly during the quarter and year-to-date as a result of increased non-utility revenue and expenses associated with energy related construction projects for third parties.
WEST TEXAS UTILITIES COMPANY STATEMENTS OF INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) OPERATING REVENUES: Electricity Marketing and Trading $ 53,681 $145,720 $104,046 $296,061 Energy Delivery 38,550 42,688 79,179 81,330 Sales to AEP Affiliates 49,798 4,431 100,040 10,454 -------- -------- -------- -------- Total Operating Revenues 142,029 192,839 283,265 387,845 OPERATING EXPENSES: Fuel 32,842 46,848 57,822 106,753 Purchased Power: Electricity Marketing and Trading 44,989 63,650 89,112 124,950 AEP Affiliates 10,559 16,835 22,209 37,227 Other Operation 24,910 25,355 49,080 51,111 Maintenance 7,050 7,046 11,406 11,608 Depreciation and Amortization 11,072 11,529 22,641 23,300 Taxes Other Than Income Taxes 5,726 6,260 12,026 12,298 Income Taxes (Credit) (468) 2,888 2,475 2,778 -------- -------- -------- -------- Total Operating Expenses 136,680 180,411 266,771 370,025 OPERATING INCOME 5,349 12,428 16,494 17,820 NONOPERATING INCOME 6,980 253 5,492 2,298 NONOPERATING EXPENSES 5,688 188 7,060 520 NONOPERATING INCOME TAX EXPENSE (CREDIT) 358 618 (631) 900 INTEREST CHARGES 5,608 5,742 10,890 11,674 -------- -------- -------- -------- NET INCOME 675 6,133 4,667 7,024 PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 52 52 -------- -------- -------- -------- EARNINGS APPLICABLE TO COMMON STOCK $ 649 $ 6,107 $ 4,615 $ 6,972 ======== ======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) NET INCOME $675 $6,133 $4,667 $7,024 OTHER COMPREHENSIVE INCOME Cash Flow Power Hedge 78 - 78 - ---- ------ ------ ------ COMPREHENSIVE INCOME $753 $6,133 $4,745 $7,024 ==== ====== ====== ======
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY STATEMENTS OF RETAINED EARNINGS (UNAUDITED) Three Months Ended June 30, Six Months Ended June 30, 2002 2001 2002 2001 ---- ---- ---- ---- (in thousands) BALANCE AT BEGINNING OF PERIOD $103,187 $116,247 $105,970 $122,588 NET INCOME 675 6,133 4,667 7,024 DEDUCTIONS: Cash Dividends Declared: Common Stock 6,749 7,206 13,498 14,412 Preferred Stock 26 26 52 52 -------- -------- -------- -------- BALANCE AT END OF PERIOD $ 97,087 $115,148 $ 97,087 $115,148 ======== ======== ======== ========
The common stock of the Company is wholly owned by AEP. See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) ASSETS ------ ELECTRIC UTILITY PLANT: Production $ 442,670 $ 443,508 Transmission 254,463 250,023 Distribution 440,271 431,969 General 108,642 112,797 Construction Work in Progress 32,115 22,575 ---------- ---------- Total Electric Utility Plant 1,278,161 1,260,872 Accumulated Depreciation and Amortization 557,728 546,162 ---------- ---------- NET ELECTRIC UTILITY PLANT 720,433 714,710 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 25,329 24,933 ---------- ---------- LONG-TERM ENERGY TRADING CONTRACTS 12,985 21,532 ---------- ---------- CURRENT ASSETS: Cash and Cash Equivalents 1,908 2,454 Accounts Receivable: Customers 29,200 18,720 Affiliated Companies 72,975 8,656 Allowance for Uncollectible Accounts (219) (196) Fuel - at average cost 10,038 8,307 Materials and Supplies - at average cost 4,464 11,190 Under-recovered Fuel Costs 34,842 32,791 Energy Trading Contracts 25,156 63,252 Prepayments and Other Current Assets 1,655 966 ---------- ---------- TOTAL CURRENT ASSETS 180,019 146,140 ---------- ---------- REGULATORY ASSETS 10,392 13,659 ---------- ---------- DEFERRED CHARGES 25,717 2,446 ---------- ---------- TOTAL ASSETS $ 974,875 $ 923,420 ========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY BALANCE SHEETS (UNAUDITED) June 30, 2002 December 31, 2001 ------------- ----------------- (in thousands) CAPITALIZATION AND LIABILITIES CAPITALIZATION: Common Stock - $25 Par Value: Authorized - 7,800,000 Shares Outstanding - 5,488,560 Shares $137,214 $137,214 Paid-in Capital 2,236 2,236 Accumulated Other Comprehensive Income 78 - Retained Earnings 97,087 105,970 -------- -------- Total Common Shareowner's Equity 236,615 245,420 Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482 2,482 Long-term Debt 221,028 220,967 -------- -------- TOTAL CAPITZALIZATION 460,125 468,869 -------- -------- CURRENT LIABILITIES: Long-term Debt Due Within One Year 35,000 35,000 Advances from Affiliates 120,439 50,448 Accounts Payable - General 19,129 33,782 Accounts Payable - Affiliated Companies 64,024 11,388 Customer Deposits - 4,191 Taxes Accrued 18,503 17,358 Interest Accrued - 1,244 Energy Trading Contracts 24,759 65,414 Other 15,890 12,001 -------- -------- TOTAL CURRENT LIABILITIES 297,744 230,826 -------- -------- DEFERRED INCOME TAXES 147,088 145,049 -------- -------- DEFERRED INVESTMENT TAX CREDITS 22,145 22,781 -------- -------- LONG-TERM ENERGY TRADING CONTRACTS 11,212 18,455 -------- -------- REGULATORY LIABILITIES AND DEFERRED CREDITS 36,561 37,440 -------- -------- CONTINGENCIES (Note 8) TOTAL CAPITALIZATION AND LIABILITIES $974,875 $923,420 ======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY STATEMENTS OF CASH FLOWS (UNAUDITED) Six Months Ended June 30, 2002 2001 (in thousands) OPERATING ACTIVITIES: Net Income $ 4,667 $ 7,024 Adjustments for Noncash Items: Depreciation and Amortization 22,641 23,300 Deferred Income Taxes 1,470 (4,738) Deferred Investment Tax Credits (636) (636) Mark-to-Market Energy Trading Contracts (1,134) (2,639) Deferred Property Taxes (7,175) (6,200) Changes in Certain Assets and Liabilities: Accounts Receivable (net) (74,776) 24,941 Fuel, Materials and Supplies 4,995 (3,276) Accounts Payable 37,983 (42,805) Taxes Accrued 1,145 13,305 Fuel Recovery (2,051) 8,978 Change in Other Assets (16,944) 730 Change in Other Liabilities (2,018) 585 --------- --------- Net Cash Flows From (Used For) Operating Activities (31,833) 18,569 --------- --------- INVESTING ACTIVITIES: Construction Expenditures (25,154) (20,312) Other - (127) --------- --------- Net Cash Flows Used For Investing Activities (25,154) (20,439) --------- --------- FINANCING ACTIVITIES: Change in Advances from Affiliates (net) 69,991 13,375 Dividends Paid on Common Stock (13,498) (14,412) Dividends Paid on Cumulative Preferred Stock (52) (52) --------- --------- Net Cash Flows From (Used For) Financing Activities 56,441 (1,089) --------- --------- Net Decrease in Cash and Cash Equivalents (546) (2,959) Cash and Cash Equivalents at Beginning of Period 2,454 6,941 --------- --------- Cash and Cash Equivalents at End of Period $ 1,908 $ 3,982 ========= =========
Supplemental Disclosure: Cash paid (received) for interest net of capitalized amounts was $9,841,000 and $10,139,000 and for income taxes was $2,408,000 and ($2,957,000) in 2002 and 2001, respectively. See Notes to Financial Statements beginning on page L-1.
NOTES TO FINANCIAL STATEMENTS JUNE 30, 2002 (UNAUDITED) The notes to financial statements are a combined presentation for AEP and its subsidiary registrants as follows: Note Registrant that Note applies to ---- ------------------------------- 1. General AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 2. Goodwill and Other Intangible Assets AEP 3. Acquisitions and Dispositions AEP 4. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo, WTU 5. Rate Matters AEP, APCo, CPL, PSO, SWEPCo, WTU 6. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU 7. Financing and Related Activities AEP, APCo, CPL, I&M, KPCo, OPCo, SWEPCo 8. Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
1. GENERAL The accompanying unaudited financial statements should be read in conjunction with the 2001 Annual Report as incorporated in and filed with the Form 10-K. Certain prior period financial statement items were reclassified to conform to current period presentation. Reclassifications had no effect on previously reported net income. In the opinion of management, the unaudited financial statements reflect all normal recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods. 2. GOODWILL AND OTHER INTANGIBLE ASSETS SFAS 142, "Goodwill and Other Intangible Assets" was effective for AEP on January 1, 2002. The adoption of SFAS 142 requires the transition testing for impairment of all indefinite lived intangibles by the end of the first quarter and initial testing of goodwill by the end of the second quarter of 2002. In the first quarter of 2002, AEP completed testing the goodwill of its domestic operations and its indefinite lived intangible assets and there was no impairment. In the second quarter of 2002 we completed initial testing for goodwill impairment of our UK and Australian retail electricity and supply operations. As a result of that testing, we determined that we had a net transitional impairment loss of $350 million, which is reported as a cumulative effect of an accounting principle change. SFAS 142 also changed the accounting and reporting for goodwill and other intangible assets. Effective with the adoption of SFAS 142 on January 1, 2002 the amortization of goodwill ceased. SFAS 142 requires that other intangible assets be separately identified and if they have finite lives, they must be amortized over that life. New reporting requirements imposed by SFAS 142 include the disclosures shown below. Goodwill The changes in the carrying amount of goodwill for the six months ended June 30, 2002 by operating segment are:
Energy Wholesale Delivery Other AEP Consolidated (in millions) Balance January 1, 2002 $340 $37 $ 40 $417 Goodwill acquired 2 - - 2 Goodwill assigned from purchase price allocation for recent prior period acquisitions 94 - - 94 Transitional impairment loss - - (27) (27) Non-transitional impairment loss - - (12) (12) Foreign currency exchange rate changes 6 - 2 8 ---- --- ---- ---- Balance June 30, 2002 $442 $37 $ 3 $482 ==== === ==== ====
In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12 million ($8 million net of tax) as a result of management's decision to exit its Gas Power Systems business that was developing customized generators powered by surplus helicopter engines. Management elected to exit this business due to technical problems with the underlying technology and recognized an impairment loss for all goodwill related to the acquisition of Gas Power Systems. The transitional impairment loss related to SEEBOARD goodwill, which is reported as a cumulative effect of an accounting change, is excluded from the above schedule. Under SFAS 144, SEEBOARD's assets, including goodwill, are reported as available for sale on one line in the balance sheet. See Note 3 related to the sale of SEEBOARD and CitiPower. As required by SFAS 142 the following tables show the transitional disclosures to adjust reported net income and earnings per share to exclude amortization expense recognized in prior periods related to goodwill and intangible assets that are no longer being amortized and adjustments for changes in amortization periods for intangible assets that continue to be amortized. Net Income Six Months Ended June 30, 2002 2001 ---- ---- (in millions) Reported Net Income (Loss) $(107) $498 Add back: Goodwill amortization - 19 Add back amortization for intangibles with indefinite lives under SFAS 142 - 4 ----- ---- Adjusted Net Income (Loss) $(107) $521 ===== ==== Earnings Per Share (Basic and Dilutive) Six Months Ended June 30, 2002 2001 ---- ---- Reported Earnings (Loss) per Share $(0.33) $1.54 Add back: Goodwill amortization - 0.06 Add back amortization for intangibles with indefinite lives under SFAS 142 - - ------ ----- Adjusted Earnings (Loss) per Share $(0.33) $1.60 ====== ===== Acquired Intangible Assets Acquired intangible assets subject to amortization are $42 million at June 30, 2002 and $53 million at December 31, 2001 net of accumulated amortization. The gross carrying amount and accumulated amortization by major asset class are:
June 30, 2002 December 31, 2001 Gross Carrying Accumulated Gross Carrying Accumulated Amount Amortization Amount Amortization (in millions) (in millions) CitiPower retail supply licenses $ - $- $24 $4 Dolet Hills advanced Royalties 35 3 35 2 Unpatented Technology 10 - - - --- -- --- -- Totals $45 $3 $59 $6 === == === ==
Amortization of intangible assets was $2 million for the six months ended June 30, 2002. Estimated aggregate amortization expense is $4.5 million for each year 2003 through 2008. Acquired intangible assets no longer subject to amortization are comprised of distribution licenses for CitiPower operating franchises with a carrying amount of $324 million and $421 million at June 30, 2002 and December 31, 2001. The reduction in the carrying values of the CitiPower retail supply and distribution licenses since December 31, 2001 results from impairment charges recorded in the second quarter of 2002 and changes in the foreign currency exchange rate. See Note 3 related to the pending sale of CitiPower. 3. ACQUISITIONS AND DISPOSITIONS Disposition of SEEBOARD On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an agreement, subject to European Union ("EU") approval, to sell its consolidated subsidiary SEEBOARD, a UK electricity supply and distribution company. EU approval was received July 25, 2002 and the sale was completed on July 29, 2002. AEP received approximately $1.04 billion in cash from the sale, subject to a working capital true up, and the buyer assumed SEEBOARD debt of approximately $1.12 billion, resulting in a net impairment loss of $345 million using June 30, 2002 exchange rates. In accordance with SFAS 144 the results of operations of SEEBOARD have been classified as discontinued operations in the accompanying financial statements. $22 million of the net impairment loss was recorded in the second quarter and is classified as discontinued operations. The remaining $323 million of the net loss has been classified as a transitional impairment loss from the adoption of SFAS 142 (see Note 2) and has been reported as a cumulative effect of an accounting change retroactive to January 1, 2002. Proceeds from the sale of SEEBOARD were used to pay down bank facilities and short-term debt. The assets and liabilities of SEEBOARD have been aggregated on the balance sheet as assets held for sale and liabilities held for sale. The major classes of SEEBOARD's assets and liabilities held for sale are: June 30, 2002 December 31, 2001 (in millions) Assets Current Assets $ 324 $ 324 Plant, Property and Equipment, Net 1,457 1,283 Goodwill 867 1,129 Other Assets 102 96 ------ ------ Total Assets Held For Sale $2,750 $2,832 ====== ====== Liabilities Current Liabilities $ 881 $ 752 Long-term Debt 739 701 Deferred Income Taxes 327 268 Other Liabilities 8 77 ------ ------ Total Liabilities Held For Sale $1,955 $1,798 ====== ====== Disposition of CitiPower On July 19, 2002, AEP, through a wholly owned subsidiary entered into an agreement to sell Citipower, a retail electricity and gas supply and distribution subsidiary in Australia. AEP will receive net cash of approximately $181 million and the buyer will assume CitiPower debt of approximately $774 million. The transaction is subject to a net asset true up and is anticipated to close in the third quarter of 2002. AEP recorded a net impairment charge totaling $125 million. $98 million was recorded in the second quarter of 2002 and relates to an impairment loss on the distribution license intangible asset. The remaining $27 million of net impairment loss has been classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see Note 2) and has been recorded as a cumulative effect of an accounting change retroactive to January 1, 2002. Since the transaction occurred after the balance sheet date of June 30, 2002, but before the issuance of the financial statements, CitiPower's results of operation were not classified as discontinued operation in accordance with SFAS 144. CitiPower's results of operation will be reclassified as discontinued operations in the third quarter. Also, CitiPower's assets and liabilities have not been aggregated on the balance sheet as assets held for sale and liabilities held for sale. This too will occur in the third quarter in accordance with SFAS 144. Acquisition of European Trading In January 2002 AEP acquired for $2 million the existing trading operations, including 34 key staff, of Enron's Norway and Sweden-based energy trading businesses. Results of operations are included in AEP's consolidated income statements from the acquisition date. Based on a preliminary purchase price allocation the excess of cost over fair value of the net assets acquired is approximately $2 million which is recorded as goodwill. The allocation of the purchase price is subject to revision after completion of a final appraisal of the fair values of the assets acquired and liabilities assumed. REPs Transfer In April 2002 AEP reached a definitive agreement to transfer two of its Texas retail electric providers (REPs) to Centrica, a provider of retail energy and other consumer services. An independent appraiser will establish a fair market value for the transaction after mid-June 2002. If the appraised value is outside the range of $133 million to $153 million, the transaction need not be completed. AEP will provide Centrica with a power supply contract for the two REPs and all back-office services related to these customers for a two-year period following closing. In addition, AEP retains the right to share in earnings from the two REPs above a threshold amount through 2006 in the event the Texas retail market develops increased earnings opportunities. AEP will also receive an up-front payment of approximately $39 million from Centrica associated with the back-office service agreement. Completion of the transaction is contingent upon the fair market value appraisal meeting the required contractual guidelines, regulatory approval from the PUCT and federal anti-trust clearance. AEP and Centrica expect to complete the regulatory approval process and conclude the transaction by the end of 2002. 4. INDUSTRY RESTRUCTURING As discussed in the 2001 Annual Report, customer choice began in four of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events occurring in 2002 related to customer choice and industry restructuring. Ohio Restructuring - Affecting AEP, CSPCo and OPCo As discussed in Note 7 of the Notes to Financial Statements in the 2001 Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme Court related to a tax expense issue which would result in duplicate expense of $40 million and $50 million, respectively, for a twelve month period beginning on May 1, 2001. On April 3, 2002, the Ohio Supreme Court rejected the companies' arguments related to a duplicate tax period and affirmed the PUCO's order which established the effective date of tax credit riders in rates. This ruling had no impact on results of operations as the companies had recorded an extraordinary loss when the prepaid asset was stranded by a PUCO order in 2001. 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 complainants seek, among other relief, an order from the PUCO suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred and 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 FERC delays in the approval of our RTO filings, CSPCo and OPCo have been unable to implement their RTO participation plan. Management is unable to predict the timing of FERC's final approval of RTOs and the timing of an RTO being operational or the outcome of this proceeding before the PUCO. Virginia Restructuring - Affecting AEP and APCo On January 1, 2002, choice of electricity supplier for retail customers began in Virginia. Presently, APCo continues to service virtually all its previous customers. Pursuant to settlement agreements and terms of the restructuring law, APCo's capped rates are the rates which were in effect on July 1, 1999 and no wires charge will be collected during 2002. However, the Virginia restructuring law allows rates to be adjusted in certain circumstances including changes in fuel prices (see Note 5). See the 2001 Annual Report for further discussion of Virginia restructuring. Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU As discussed in the 2001 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. All of SWEPCo's Texas service territory and a small portion of WTU's service territory are located in the SPP area. CPL operates entirely in the ERCOT area of Texas. Under the Texas Legislation, the PUCT approved business separation plans for the utility companies. The business separation plans provided for CPL and WTU to establish separate companies and divide their integrated utility operations and assets into a power generation company, a transmission and distribution utility and a retail electric provider. Due to the delay in the start of competition in the SPP area and lack of regulatory approval for our corporate separation plan, only CPL's and WTU's retail electric providers commenced operations on January 1, 2002. Operations for CPL, SWEPCo and WTU have been functionally separated. The companies anticipate completing legal separation following receipt of the appropriate regulatory approvals. In February 2002, CPL through a subsidiary, issued $797 million of transition notes approved under the securization provisions in the Texas Restructuring Legislation. The transition notes provide more economical financing for certain transition generation-related regulatory assets during their recovery period. A 2004 true-up proceeding will determine the amount of total stranded costs, if any, including the final fuel recovery, net regulatory asset recovery, certain environmental costs, accumulated excess earnings offsets and other 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 of and/or exchange of generation assets, the issuance of power generation company stock to the public or the use of an ECOM model. To the extent that the final 2004 true-up proceeding determines that CPL should recover additional stranded costs, the additional amount recoverable can also be securitized. Two unaffiliated Texas utilities reached settlement agreements approved by the PUCT regarding recovery of stranded generation costs. CPL is not presently engaged in any settlement discussions with the PUCT. CPL's generation-related regulatory assets subject to recovery as stranded costs are approximately $1.1 billion of which $949 million has been securitized pending the 2004 true-up proceeding's determination of stranded costs recovery including the recovery of stranded generation-related regulatory assets. WTU and SWEPCo do not have any recoverable Texas generation-related regulatory assets. The PUCT ordered CPL to reduce distribution rates by $54.8 million over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings would be used to reduce stranded cost. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL will have no stranded cost and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. Since CPL expensed excess earnings amounts in 1999, 2000, and 2001, the order has no additional effect on reported net income but will reduce cash flows for the five year refund period. Beginning January 1, 2002, fuel costs for CPL and WTU in ERCOT are no longer subject to PUCT fuel reconciliation proceedings. Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT which reconciles their fuel costs through the period ending December 31, 2001. As discussed in Note 5 "Rate Matters", WTU filed its final fuel reconciliation for its ERCOT service territory with the PUCT in June 2002. These final fuel balances will be included in each company's 2004 true-up proceeding. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL and WTU to the risk of fuel market price increases and could adversely affect results of operations. In the event CPL, SWEPCo, and WTU 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. Michigan Restructuring - Affecting AEP and I&M Customer choice commenced for I&M's Michigan customers on January 1, 2002. Effective with that date the rates on I&M's Michigan customers' bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M's total rates in Michigan remain unchanged and reflect cost of service. At this time, none of I&M's customers have elected to change suppliers and no competing suppliers are active in I&M's Michigan service territory. Management has concluded that as of June 30, 2002 the requirements to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan continue to be cost-based regulated. As a result I&M has not yet discontinued regulatory accounting under SFAS 71. West Virginia Restructuring - Affecting AEP and APCo As discussed in Note 7 of the 2001 Annual Report, the West Virginia Legislature in 2000 approved an electricity restructuring plan. Before implementation of the plan, the West Virginia Legislature needed to enact legislation to preserve the revenues of state and local government. In the past two legislative sessions, which usually end in March each year, the West Virginia Legislature has not enacted the required legislation. Due to the lack of activity, the Public Service Commission of West Virginia closed two proceedings related to electricity restructuring in the summer of 2002. The two West Virginia Commission orders related to the dismissal of the respective dockets intended originally to determine whether West Virginia should deregulate the generation business, and to develop the Commission's Deregulation Plan and related Commission rules to implement the Plan. Management is currently reviewing the impact of these two orders to determine if the West Virginia Jurisdiction meets the conditions to apply SFAS 71. 5. RATE MATTERS Fuel Reconciliation - Affecting AEP and WTU In June 2002 WTU 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 WTU's ERCOT service territory. Texas restructuring legislation eliminated fuel clause recovery mechanisms beginning in 2002 for the ERCOT area and provides for a 2004 true-up proceeding to determine recovery of final fuel balances. At December 31, 2001, the under-recovery balance associated with WTU's ERCOT service area was $26.4 million including interest. WTU also requested authority to surcharge its SPP customers. WTU's SPP customers will continue to be subject to fuel reconciliations until competition begins. The under-recovery balance at December 31, 2001 for WTU's service within SPP was $0.7 million including interest. During the reconciliation period, WTU incurred $292.7 million of eligible fuel and fuel related expenses serving both ERCOT and SPP retail customers. The PUCT is not expected to act on this issue prior to the end of 2002. FERC Wholesale Fuel Complaint - Affecting AEP and WTU As discussed in Note 5 of the 2001 Annual Report, certain WTU wholesale customers filed a complaint with FERC alleging that WTU had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997. The customers allege WTU had billed them for not only the cost of a 1999 Oklaunion plant outage, but also certain additional costs that are not permissible under the fuel adjustment clause. Negotiations to settle the complaint and update the contracts are continuing. In March 2002 WTU 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. Texas Retail Price-to-Beat Rates - Affecting AEP AEP subsidiaries which are the Texas retail electric providers (REP) for the ERCOT area, CPL REP and WTU REP, filed with the PUCT in May 2002 to increase the fuel portion of their "price-to-beat" rate in compliance with the Texas Restructuring Legislation and rules issued by the PUCT. The Texas legislation provides for the adjustment of the fuel portion of the rate up to twice annually based on changes in the market price of fuel using a natural gas price index. On July 15, 2002, the PUCT required further hearings to reconsider the validity of their existing rules for fuel factor adjustments. On July 24, 2002, CPL REP and WTU REP filed a petition with the District Court seeking an injunction commanding the PUCT to proceed to a final order based on the existing rules and prohibiting the PUCT from conducting a remand proceeding. The District Court issued an order on August 9, 2002 requiring the PUCT to comply with the existing rules. CPL REP and WTU REP are unable to predict the response of the PUCT to the Court's order and when or if they will be able to adjust the fuel portion of their "price-to-beat" rates. A delay or denial of CPL REP's or WTU REP's request to increase the fuel portion of their "price-to-beat" rates could reduce AEP's future results of operations and cash flows. FERC Transmission Rates - Affecting AEP, CPL, PSO, SWEPCo and WTU In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and calculate and issue refunds for overcharges from January 1, 1997. The order resulted from a remand by an appeals court of a tariff compliance filing order issued in November 1998 that had been appealed by certain customers. CPL and WTU recorded refund provisions of $1.7 million and $0.7 million, respectively, including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each in 2001 for this order making the AEP total $2.6 million. On July 26, 2002, FERC approved a revised open access transmission tariff. Refunds are to be completed within 30 days. The amount of the refunds are being calculated. Management does not expect the refunds to be materially different from the amounts provided in 2001. Texas Transmission Cost Recovery - Affecting AEP, CPL and WTU On July 15, 2002, CPL and WTU filed a petition to update their Transmission Cost Recovery Factor (TCRF) as of September 1, 2002. The TCRF allows for the pass through of changes in wholesale transmission costs billed to the distribution service providers by transmission service providers. CPL and WTU are seeking TCRF increases of $0.8 million and $0.2 million, respectively. The requested increases include amounts for an interim increase granted by the PUCT for one unaffiliated transmission service provider. The PUCT has not ruled on whether interim amounts qualify for a TCRF. If the interim amount is disallowed, CPL's and WTU's increase would be reduced to $0.4 million and $0.1 million, respectively. Virginia Fuel Rate Filing - Affecting AEP and APCo In July 2002 APCo filed with the Virginia SCC requesting an increase in fuel rates effective January 1, 2003. The request would increase annual revenues by approximately $28 million. A public hearing is scheduled for September 23, 2002 related to this filing. 6. BUSINESS SEGMENTS AEP has three business segments: Wholesale, Energy Delivery and Other. The business activities of each of these segments are as follows: Wholesale o Generation of electricity for sale to retail and wholesale customers, o Marketing and trading of electricity, gas and coal. o Gas pipeline and storage services and other energy supply related business o Coal mining, bulk commodity barging operations and other energy supply related businesses Energy Delivery o Domestic electricity transmission o Domestic electricity distribution Other o Foreign electricity distribution and supply investments o Telecommunication services Segment results of operations for the six months ended June 30, 2002 and 2001 are shown below. These amounts include certain estimates and allocations where necessary. We have used Earnings before Interest and Income Taxes (EBIT) as a measure of segment operating performance. The EBIT measure is total operating revenues net of total operating expenses and other income and deductions from income. It differs from net income in that it does not take into account interest expense or income taxes. EBIT is believed to be a reasonable gauge of results of operations. By excluding interest and income taxes, EBIT does not give guidance regarding the demand of debt service or other interest requirements, or tax liabilities or taxation rates. The effects of interest expense and taxes on overall corporate performance can be seen in the consolidated statements of income. The amounts shown for the three business segments reported by AEP include certain estimates and allocations where necessary.
Energy Other Reconciling Wholesale Delivery Investments Adjustments Consolidated June 30, 2002 (in millions) Revenues from: External customers $26,002 $1,694 $ 246 $ - $27,942 Transactions with other operating segments (1,151) (5) (486) (1,642) Segment EBIT 477 461 (174) 764 Total assets 35,544 13,190 2,424 51,158 June 30, 2001 Revenues from: External customers 26,034 1,672 238 27,944 Transaction with other operating segments 1,067 10 30 (1,107) - Segment EBIT 845 483 142 (71) 1,399 Total assets 29,566 14,379 7,539 (1,257) (a) 50,227 (a) Reconciling adjustment for Total Assets: Eliminate intercompany balances (1,448) Corporate assets 37 Other 154 ------- $(1,257) =======
All of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.
Six Months Ended Six Months Ended June 30, 2002 June 30, 2001 Segment Segment Revenues EBIT Total Assets Revenues EBIT Total Assets Wholesale Segment (in thousands) (in thousands) APCo $2,463,966 $111,292 $3,229,545 $3,523,410 $107,415 $3,666,392 CPL 591,805 67,406 3,047,642 973,148 133,446 2,935,249 CSPCo 1,636,821 116,606 2,249,185 2,015,358 119,544 2,499,506 I&M 1,870,602 7,886 3,649,646 2,394,505 86,108 3,994,291 KPCo 601,795 8,225 681,177 831,124 4,162 772,669 OPCo 2,394,324 192,718 3,473,145 3,061,833 125,565 3,927,606 PSO 378,279 5,684 872,625 644,622 12,124 859,240 SWEPCo 532,914 26,357 1,171,373 696,457 32,036 1,184,118 WTU 204,086 5,088 418,221 306,515 1,335 400,251
Segment Segment Revenues EBIT Total Assets Revenues EBIT Total Assets Energy Delivery Segment (in thousands) (in thousands) APCo $294,470 $108,841 $2,547,817 $300,021 $115,711 $2,892,449 CPL 288,955 80,406 2,188,857 278,763 65,612 2,108,135 CSPCo 225,610 39,950 1,265,166 219,310 44,065 1,405,972 I&M 153,194 72,365 1,647,373 156,907 61,410 1,802,938 KPCo 66,514 29,053 659,723 67,164 27,246 748,333 OPCo 284,904 42,851 1,936,738 265,009 58,512 2,190,161 PSO 122,547 28,639 972,249 109,711 23,187 957,334 SWEPCo 152,943 39,635 1,219,185 164,027 51,909 1,232,449 WTU 79,179 12,313 556,654 81,330 21,041 532,734
Registrant Subsidiaries Company Total Revenues EBIT Total Assets Revenues EBIT Total Assets (in thousands) (in thousands) APCo $2,758,436 $220,133 $5,777,362 $3,823,431 $223,126 $6,558,841 CPL 880,760 147,812 5,236,499 1,251,911 199,058 5,043,384 CSPCo 1,862,431 156,556 3,514,351 2,234,668 163,609 3,905,478 I&M 2,023,796 80,251 5,297,019 2,551,412 147,518 5,797,229 KPCo 668,309 37,278 1,340,900 898,288 31,408 1,521,002 OPCo 2,679,228 235,569 5,409,883 3,326,842 184,077 6,117,767 PSO 500,826 34,323 1,844,874 754,333 35,311 1,816,574 SWEPCo 685,857 65,992 2,390,558 860,484 83,945 2,416,567 WTU 283,265 17,401 974,875 387,845 22,376 932,985
7. FINANCING AND RELATED ACTIVITIES Equity Units In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345 million). Each equity-linked security consists of a forward purchase contract and a senior note issued by AEP. The forward purchase contracts obligate the holders to purchase from AEP shares of AEP common stock on the stock purchase date of August 16, 2005. The purchase price per equity unit is $50. The number of shares to be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are pledged as collateral to secure the purchase of common stock under the forward purchase contracts. Holders may satisfy their obligation under the forward purchase contracts by allowing the senior notes to be remarketed. The proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that holders pledge to AEP to secure their obligations under the forward purchase contracts. Alternatively, holders may choose to continue holding the senior notes and use other resources as consideration for the purchase of stock under the forward purchase contracts. AEP will make quarterly interest payments on the senior notes at the initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP will pay the purchaser contract adjustment payments at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments has been recorded as a liability in equity unit senior notes offset by a charge to paid-in capital. Interest payments on the senior notes are reported as interest expense and contract adjustment payments are charged against the liability. Accretion of the contract adjustment payment liability is reported as interest expense. We apply the treasury stock method to the equity units to calculate diluted earnings per share. Common Stock In June 2002, AEP issued 16 million shares of common stock at $40.90 per share through an equity offering and received net proceeds of $634 million. Proceeds from the sale of equity units and common stock were used to pay down short-term debt and establish a cash liquidity reserve fund. Issuances and Retirements of Long-term Debt In the first quarter of 2002, CPL Transition Funding LLC, a subsidiary of CPL, issued $797 million of transition notes under the provisions of the Texas Restructuring Legislation (See Note 4). The proceeds were used to reduce CPL's debt and retire 4.5 million shares of CPL's common stock. The notes were issued under the following classes: Principal Interest Scheduled Final Final Class Amount Rate Payment Date Maturity Date ----- --------- -------- --------------- ------------- (in millions) (%) A-1 129 3.54 2005 2007 A-2 154 5.01 2008 2010 A-3 107 5.56 2010 2012 A-4 215 5.96 2013 2015 A-5 192 6.25 2016 2017 Other issuances and retirements of long-term debt and other securities during the first six months of 2002 were: Type of Principal Interest Company Debt Amount Rate Due Date ------- ------- --------- -------- -------- Issuances (in millions) (%) --------- APCo Senior Unsecured Notes $ 450 4.80 2005 I&M Installment Purchase Contracts 50 4.90 2025 KPCo Senior Unsecured Notes 125 5.50 2007 SWEPCo Senior Unsecured Notes 200 4.50 2005 Non-Registrant AEP Subs. Revolving Credit Agreement 143 Variable 2003 Retirements CPL Senior Unsecured Notes $150 Variable 2002 I&M Installment Purchase Contract 50 Variable 2014 KPCo First Mortgage Bonds 15 7.90 2023 OPCo First Mortgage Bonds 5 8.80 2022 SWEPCo Senior Unsecured Notes 150 Variable 2002 Non-Registrant AEP Subs. Notes Payable 12 Variable 2002-2007 Related Activities AEP Credit renewed its sale of receivables agreement during the second quarter of 2002. At June 30, 2002, the sale of receivables agreement provided commitments of $600 million to purchase receivables from AEP Credit, of which $455 million was outstanding. All of the receivables sold, represented affiliate receivables. The commitment's new term under the sale of receivables agreement will remain at $600 million until May 28, 2003. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of the receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts. In April 2002, AEP closed on a bridge loan facility consisting of a $1,125 million 364-day revolving credit facility and a $600 million 364-day term loan facility to prepare for corporate separation. We borrowed $600 million under the term loan facility and loaned the amounts borrowed to CPL ($200 million), CSPCo ($250 million) and OPCo ($150 million). Pricing on the facilities and intercompany loans is based on a spread over LIBOR. AEP has available $3.5 billion in bank facilities consisting of a $2.5 billion 364-day facility and a $1.0 billion five-year facility maturing on May 31, 2005. On May 22, 2002, AEP renewed the $2.5 billion facility for another year extending the maturity date to May 21, 2003. Upon the issuance of the $450 million 4.80% unsecured notes due in 2005, APCo announced the following debt would be redeemed in July; $75 million of 8.25% junior subordinated debentures due 2026, $90 million of 8% junior subordinated debentures due 2027, $40 million of 6.65% first mortgage bonds due 2003 and $30 million of 6.85% first mortgage bonds due 2003. Upon issuance of the $125 million 5.50% unsecured notes due 2007, KPCo announced the redemption of $45 million of first mortgage bonds on August 1. In preparation for corporate restructuring, management announced the following bonds would be redeemed in July, CSPCo's $72.8 million remaining outstanding principal amount of the 8-3/8% junior subordinated debentures due 2025 and $40 million of the 7.92% junior subordinated debentures due 2027 and OPCo's $85 million remaining outstanding principal of the 8.16% junior subordinated debentures due 2025 and $50 million of the 7.92% junior subordinated debentures due 2027. 8. CONTINGENCIES Litigation Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in Note 8 of the Notes to Financial Statements in the 2001 Annual Report, AEP, 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. 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 Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. The Circuit Court dismissed the motion as pre-mature. 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, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo 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. The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans which could have resulted in the imposition of stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA assumption of state air quality management programs. Most of those states have submitted conforming compliance plans and the appeal filed by AEP subsidiaries and other utilities in the D.C. Circuit Court to review this ruling has been dismissed. 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 imposed 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 August 2001 the D.C. Circuit Court issued an order tolling the compliance schedule until Federal EPA responded 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 in May 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 action in the D.C. Circuit Court. In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. AEP is installing selective catalytic reduction (SCR) technology to reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced operations. 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 with completion scheduled in May 2003 through 2006. Our estimates indicate that AEP's compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion, including amounts spent through June 30, 2002. Estimated compliance costs by registrant subsidiaries are as follows: Estimated Compliance Costs ---------------- (in millions) AEGCo $125 APCo 365 CPL 57 CSPCo 106 I&M 202 KPCo 160 OPCo 606 SWEPCo 28 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 At the date of Enron's bankruptcy 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. In connection with the acquisition of HPL, we acquired from BAM Lease Company, a now-bankrupt subsidiary of Enron, the right to use under a 30-year lease, with a renewal right for another 20 years, the Bammel gas storage facility. The lease includes the use of the Bammel storage reservoir and the related above ground compression, treating and delivery systems. We also entered into a "right to use" agreement with BAM Lease Company which allows us to use approximately 55 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the facility. The Bammel Trust which purportedly owned the cushion gas had entered into a financing arrangement with a group of banks. These banks purported to have certain rights to the cushion gas in certain events of default. We have been informed by the banks of Bammel Trust's default under the terms of their financing agreement. 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. Management is unable to predict the outcome of this lawsuit or its impact on results of operation and cash flows. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax (in millions) APCo $5.2 $3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceeding or in the lawsuit related to the cushion gas financing agreement, our future results of operations, cash flows and possibly financial condition could be adversely impacted. Energy Market Investigations - Affecting AEP In February 2002 the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron Corp. and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange. The May 8, 2002 FERC data request required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices. On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquires, we provided the pertinent information. The PUCT also issued similar data requests to AEP and other power marketers. AEP responded to such data request by the July 2, 2002 response date. The US Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17, 2002 requesting information with respect to "wash sale" trading practices. We responded to CFTC. In addition, the US Department of Justice made a civil investigation demand to us and other electric generating companies concerning their investigation of the Intercontinental Exchange. We have recently completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. We believe that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales". FERC Proposed Security Standards In July 2002 the FERC published for comment its proposed security standards as part of the Standards for Market Design (SMD). These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities and require compliance by January 1, 2004. The impact of these proposed standards is far-reaching and has significant penalties for non-compliance. These standards apply to marketers, transmission owners, and power producers. For the AEP System this includes: regulated and non-regulated power generation plants, transmission systems, distribution systems, regulated and non-regulated energy trading, and related areas of business. These standards represent a significant effort that will impact the entire AEP System. Unless the cost can be recovered from customers, results of operations and cash flows would be adversely affected. FERC Market Power Mitigation A FERC order on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power systems status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows. Minority Interest in Finance Subsidiary - Affecting AEP In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling preferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agreements, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate. The $750 million received replaced interim funding used to acquire Houston Pipe Line Company in June 2001. The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such 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 the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time. The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements. Steelhead has the right to terminate the transaction and liquidate 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 $321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could negatively impact AEP's liquidity. Caddis and the AEP subsidiary which acts as its managing member 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 such managing member are consolidated with AEP for financial reporting purposes. The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary. Foreign Distribution Projects - Affecting AEP We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and our investment has been affected by the devaluation of the Brazilian Real. The cumulative equity share of operating and foreign currency translation losses through June 30, 2002 is approximately $47 million and $58 million, respectively, net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively, net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price. As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option. In January 2002, management evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and concluded that our partners should be able to fulfill their responsibilities. Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered. In addition, our partners have a principal payment due in November 2002 in the amount of $55 million. Our partners plan to refinance the debt before the payment comes due. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations. Management will continue to monitor both the status of the losses and its partners ability to fulfill their obligations under the put option. Investments in Telecommunications Companies - Affecting AEP AEP provides telecommunications services to business and telecommunication companies through a broadband fiber optic network. AEP conducts its operations through an ownership interest in a joint venture, AFN Networks, LLC (AFN), and through its AEP Communications and C3 subsidiaries. Management is currently reassessing its telecommunications business strategy and considering certain changes that could include additional investment in AFN, possible financial control of the joint venture's operations, and a reorganization of its other telecommunications operations in order to optimize the value of such assets. The review of the telecommunications business strategy is expected to be completed in the third quarter of 2002. In connection with the completion of this assessment and reorganization activities, management will review its investment in telecommunication companies for any impairment of value. Management is unable to determine whether there is any impairment until such evaluation is complete. At June 30, 2002 AEP's investment in telecommunications companies was approximately $252 million. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2001 Annual Report. REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS This is our combined presentation of management's discussion and analysis of financial condition, contingencies and other matters 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 and year-to-date period ended June 30, 2002 is presented with their financial statements earlier in this document. FINANCIAL CONDITION The rating agencies have been conducting credit reviews of AEP and its registrant subsidiaries as we prepare for corporate separation. In April 2002 Moody's Investors Service placed AEP and five of its registrant subsidiaries (CPL, CSPCo, OPCo, SWEPCo and WTU) on credit rating watch for possible downgrade. The review of SWEPCo could conclude with more than a one notch downgrade. Moody's confirmed the credit ratings of four of AEP registrant subsidiaries (APCo, I&M, KPCo, and PSO). In May 2002, Standard & Poors confirmed AEP and its registrant subsidiaries senior unsecured debt rating. First Mortgage Bond ratings of all the registrant subsidiaries were lowered to "BBB+" from "A". AEP's commercial paper programs short-term ratings of A2 and P2 were confirmed by Moody's and Standard and Poor's, respectively. The review of the companies' debt position and credit rating is being completed in anticipation of corporate separation. We are working with the rating agencies and providing information to support AEP's current credit rating. If our credit ratings are lowered, the interest rates we pay on borrowings will potentially rise thereby increasing our interest expense unless we can reduce our borrowings. At June 30, 2002, the ratings of AEP's subsidiaries' first mortgage bonds are listed in the following table: Company Moody's S&P Fitch APCo A3 BBB+ A- CPL A3 BBB+ A CSPCo A3 BBB+ A I&M Baa1 BBB+ BBB+ KPCo Baa1 BBB+ BBB+ OPCo A3 BBB+ A- PSO A1 BBB+ A+ SWEPCo A1 BBB+ A WTU A2 BBB+ A The ratings at June 30, 2002 for senior unsecured debt are listed in the following table: Company Moody's S&P Fitch aEP Baa1 BBB+ BBB+ AEP Resources* Baa1 BBB+ BBB+ APCo Baa1 BBB+ BBB+ CPL Baa1 BBB+ BBB+ CSPCo A3 BBB+ A- I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB OPCo A3 BBB+ BBB+ PSO A2 BBB+ A SWEPCo A2 BBB+ A- WTU - BBB+ - *The rating is for a series of senior notes issued with a Support Agreement from AEP. 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, convertible securities, 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 come from the parent company's commercial paper program and are loaned to subsidiaries through inter-company notes. The commercial paper program is backed by $3.5 billion in bank facilities of which $1 billion matures in May 2005 and $2.5 billion matures in May 2003. At June 30, 2002, approximately $1.4 billion was outstanding in commercial paper. In addition, AEP has a $1.725 billion bank facility maturing in April 2003 that is available for debt refinancing in anticipation of corporate separation. At June 30, 2002, $600 million was outstanding under that facility. We anticipate repayment of the facility through the issuance of bonds by certain subsidiaries. The pricing on the facility is based on a spread over LIBOR. During the first half of 2002 cash flow from operations was $96 million, including $107 million from a net loss and $912 million from depreciation, amortization and deferred taxes. Capital expenditures including acquisitions were $785 million and dividends on common stock were $387 million. Cash from operations and the issuance of common stock, common equity units and transition funding bonds provided funds to reduce debt, fund construction and pay dividends. Major construction expenditures included amounts for emission control technology on several coal-fired generating units (see discussion in Note 8). During the fourth quarter of 2001, Quaker Coal Co., MEMCO Barge Line, Inc. and two coal-fired generating plants in the UK were acquired using short-term borrowings and available cash. Long-term financing arrangements are being negotiated for the UK generating plants and will be announced as completed. Completion of this financing is anticipated in the third quarter of 2002. Long-term funding arrangements are often complex and take time to complete. In anticipation of corporate separation, CPL and WTU both initiated tenders for their first mortgage bonds in July. The cumulative amounts tendered for CPL and WTU was $401 million and $89 million, respectively. In order to pay for a portion of these retired bonds, as well as previously retired bonds, AEP borrowed $600 million under the term loan facility. In turn, AEP loaned the amounts it borrowed to CPL ($200 million), CSPCo ($250 million) and OPCo ($150 million). In June 2002 we issued 16 million shares of AEP common stock and 6.9 million equity units. We used the proceeds from the issuances of $968 million to establish a $300 million cash liquidity reserve and to reduce debt. The cash reserve enhances our liquidity and is included in cash and cash equivalents on AEP's consolidated balance sheet. Total consolidated plant and property additions including capital leases for the six months ended June 30, 2002 were $865 million. The following table shows the plant and property additions by certain registrant subsidiaries: Company Amount ------- ------ (in millions) APCo $129 CPL 65 I&M 69 OPCo 158 SWEPCo 36 Pending and 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 meaningful financial returns and to dispose of investments that do not meet these principles. In July 2002 we completed the sale of SEEBOARD, an energy delivery and power supply business in the UK, receiving cash of approximately $1.04 billion which will be used to reduce debt. The sale resulted in a loss of $345 million (See Note 3). We have entered into a definitive agreement to dispose of two of our Texas retail electric providers which serve retail residential and small commercial customers in Texas. The disposal price will not be determined until a date closer to the consummation of the transaction, which is expected to be during the fourth quarter of 2002. In July 2002 we reached an agreement to sell CitiPower, our energy delivery and retail supply businesses in Australia. It is anticipated that AEP will receive approximately $180 million in cash and the sale will result in a $125 million loss (See Note 3). AEP provides telecommunications services to business and telecommunication companies through a broadband fiber optic network. AEP conducts its operations through an ownership interest in a joint venture, AFN Networks, LLC (AFN), and through its AEP Communications and C3 subsidiaries. Management is currently reassessing its telecommunications business strategy and considering certain changes that could include additional investment in AFN, possible financial control of the joint venture's operations, and a reorganization of its other telecommunications operations in order to optimize the value of such assets. The review of the telecommunications business strategy is expected to be completed in the third quarter of 2002. In connection with the completion of this assessment and reorganization activities, management will review its investment in telecommunication companies for any impairment of value. Management is unable to determine whether there is any impairment until such evaluation is complete. At June 30, 2002 AEP's investment in telecommunications companies was approximately $252 million. Corporate Separation As discussed in the 2001 Annual Report, we have filed with the FERC and SEC seeking approval to separate our regulated and unregulated operations. Our plan for corporate separation allows us to meet the requirements of Texas and Ohio restructuring legislation. We intend to transfer the generation assets from the integrated electric operating companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU) to unregulated generation companies. We proposed amendments to the power pooling agreements for all operating companies. Only those operating companies that continue to exist as integrated utilities would be included in the amended power pooling agreements, which would govern energy exchanges among members and the allocation of their off system purchases and sales. Several state commissions, wholesale customer groups and other interested parties intervened in the FERC proceeding. We have negotiated settlement agreements with the six state regulatory commissions and other major intervenors. The settlement agreements have been filed at the FERC for review and approval. FERC and SEC approval of our corporate separation plan is required for its implementation. In order to execute this separation, we will be required to retire various debt securities and to transfer assets between legal entities. RTO Formation As discussed in the 2001 Annual Report, FERC Order No. 2000 and many of the settlement agreements with the state regulatory commissions to approve the AEP-CSW merger required the transfer of control of our transmission system to RTOs. Certain AEP subsidiaries participated in the formation of the Alliance RTO. Other subsidiaries are members of ERCOT or SPP. The FERC expressed its opinion that large RTOs will better support competitive, reliable electric service and rejected the Alliance RTO's filing. In May 2002 AEP announced an agreement with the PJM Interconnection to pursue terms for certain subsidiares to participate in its RTO. Final agreements are expected to be negotiated. In July 2002 the FERC tentatively approved certain AEP subsidiaries' decision to join PJM subject to certain conditions being met. The performance of these conditions are only partially under AEP's control. In other RTO developments FERC recently accepted conditionally, filings related to a proposed consolidation of the Midwest Independent System Operator (MISO) and the SPP. In that order the FERC required the AEP subsidiaries in SPP to file reasons why those subsidiaries should not be required to join MISO. AEP filed with the FERC a response that additional analysis was required prior to AEP making an RTO decision. The SPP companies are also regulated by state public utility commissions, and the Louisiana and Arkansas commissions also filed responses to the FERC's RTO order indicating that additional analysis was required. Management is unable to predict the final 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. OTHER MATTERS Industry Restructuring As discussed in Note 4 and the 2001 Annual Report, restructuring and customer choice began 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 regulation of bundled electric service to customer choice and market pricing for the supply of electricity. Customer choice of electricity supplier began on January 1, 2001 for Ohio customers and on January 1, 2002, for Michigan, Texas and Virginia customers. In the Texas jurisdiction competition began in the ERCOT area but was delayed in the SPP area. In Ohio, Michigan and Virginia virtually all customers continue to receive electric generation, transmission and distribution services from our electric operating companies. 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 complainants seek, among other relief, an order from the PUCO suspending collection of transition charges by CSPCo and OPCo until transfer of control of their transmission assets has occurred and 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 FERC delays in the approval of our RTO filings, CSPCo and OPCo have been unable to implement their RTO plan. Management is unable to predict the timing of FERC's final approval of RTOs and the timing of an RTO being operational or the outcome of this proceeding before the PUCO. In 2001 the PUCT issued an order requiring CPL to reduce future distribution rates by $54.8 million over a five-year period beginning January 1, 2002 in order to return estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring Legislation intended that excess earnings would be used to reduce stranded cost. Final stranded cost amounts and the treatment of excess earnings will be determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL will have no stranded cost and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently, the order has no effect on reported net income. Beginning January 1, 2002, fuel costs for CPL and WTU in ERCOT are no longer subject to PUCT fuel reconciliation proceedings under the Texas Restructuring Legislation. Consequently, CPL and WTU will file a final fuel reconciliation with the PUCT to reconcile their fuel costs through the period ending December 31, 2001. These final fuel balances will be included in each company's 2004 true-up proceeding. The elimination of the fuel clause recoveries in 2002 in Texas will subject AEP, CPL and WTU to the risk of fuel market price increases and could adversely affect future results of operations. Two unaffiliated Texas utilities reached settlement agreements approved by the PUCT regarding recovery of stranded generation costs. CPL is not presently engaged in any settlement discussions with the PUCT. Under the Texas Legislation, a 2004 true-up proceeding will determine recovery of stranded costs including final fuel recovery balances, net regulatory assets, certain environmental costs, accumulated excess earnings and other issues. CPL's generation-related regulatory assets subject to recovery as stranded costs are approximately $1.1 billion of which $949 million has been securitized pending the 2004 true-up proceeding's determination of stranded costs recovery including the recovery of stranded generation-related regulatory assets. WTU and SWEPCo do not have any recoverable Texas generation-related regulatory assets. In the event CPL, SWEPCo, and WTU 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. Litigation Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M, and OPCo As discussed in the 2001 Annual Report, AEP, 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. 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 Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief. In February 2001 the government filed a motion requesting a determination that four projects undertaken on units at Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance, repair and replacement" as used in the Clean Air Act. The Circuit Court dismissed the motion as premature. 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, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo 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. The NOx Rule required states to submit plans to comply with its provisions. In 2000 Federal EPA ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed to submit approvable compliance plans which could have resulted in the imposition of stringent sanctions including limits on construction of new sources of air emissions, loss of federal highway funding and possible Federal EPA assumption of state air quality management programs. Most of those states have submitted conforming compliance plans and the appeal filed by AEP subsidiaries and other utilities in the D.C. Circuit Court to review this ruling has been dismissed. 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 August 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 in May 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 action in the D.C. Circuit Court. In 2000 the Texas Natural Resource Conservation Commission adopted rules requiring significant reductions in NOx emissions from utility sources, including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo. AEP is installing selective catalytic reduction (SCR) technology to reduce NOx emission. During 2001 SCR on OPCo's Gavin Plant commenced operations. 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 with completion scheduled in May 2003 through 2006. Our estimates indicate that AEP's compliance with the NOx Rule, the Texas Natural Resource Conservation Commission rule and the Section 126 Rule could result in required capital expenditures of approximately $1.6 billion, including amounts spent through June 30, 2002. The following table shows the estimated compliance cost for certain of AEP's registrant subsidiaries. Company Amount ------- ------ (in millions) APCo $365 CPL 57 I&M 202 OPCo 606 SWEPCo 28 Since compliance costs cannot be estimated with certainty, the actual cost to comply could be significantly different than the 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. Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo At the date of Enron's bankruptcy 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. In connection with the acquisition of HPL, we acquired from BAM Lease Company, a now-bankrupt subsidiary of Enron, the right to use under a 30-year lease, with a renewal right for another 20 years, the Bammel gas storage facility. The lease includes the use of the Bammel storage reservoir and the related above ground compression, treating and delivery systems. We also entered into a "right to use" agreement with BAM Lease Company which allows us to use approximately 55 billion cubic feet of cushion gas (or pad gas) required for the normal operation of the facility. The Bammel Trust which purportedly owned the cushion gas had entered into a financing arrangement with a group of banks. The banks purported to have certain rights to the cushion gas in certain events of default. We have been informed by the banks of Bammel Trust's default under the terms of their financing agreement. 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. Management is unable to predict the outcome of this lawsuit or its impact on results of operation and cash flows. In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax) for our estimated loss from the Enron bankruptcy. The amounts for certain subsidiary registrants were: Amounts Amounts Net of Registrant Provided Tax (in millions) APCo $5.2 $3.4 CSPCo 3.2 2.1 I&M 3.4 2.2 KPCo 1.3 0.8 OPCo 4.3 2.8 The amounts provided were based on an analysis of contracts where AEP and Enron are counterparties, the offsetting of receivables and payables, the application of deposits from Enron and management's analysis of the HPL related purchase contingencies and indemnifications. If there are any adverse unforeseen developments in the bankruptcy proceeding or in the lawsuit related to the cushion gas financing agreement, our future results of operations, cash flows and possibly financial condition could be adversely impacted. Energy Market Investigations - Affecting AEP In February 2002 the FERC issued an order directing its Staff to conduct a fact-finding investigation into whether any entity, including Enron Corp., manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward. In April 2002 AEP furnished certain information to the FERC in response to their related data request. Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further data requests, including requests for admissions, with respect to certain trading strategies engaged in by Enron Corp. and, allegedly, traders of other companies active in the wholesale electricity and ancillary services markets in the West, particularly California, during the years 2000 and 2001. This data request was issued to AEP as part of a group of over 100 entities designated by the FERC as all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator and/or the California Power Exchange. The May 8, 2002 FERC data request required senior management to conduct an investigation into our trading activities during 2000 and 2001 and to provide an affidavit as to whether we engaged in certain trading practices that the FERC characterized in the data request as being potentially manipulative. Senior management complied with the order and denied our involvement with those trading practices. On May 21, 2002, the FERC issued a further data request with respect to this matter to us and over 100 other market participants requesting information for the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back" trading in the Western System Coordinating Council (WSCC), which involves the sale of an electricity product to another company together with a simultaneous purchase of the same product at the same price (collectively, "wash sales"). Similarly, on May 22, 2002, the FERC issued an additional data request with respect to this matter to us and other market participants requesting similar information for the same period with respect to the sale of natural gas products in the WSCC and Texas. After reviewing our records, we responded to the FERC that we did not participate in any "wash sale" transactions involving power or gas in the relevant market. We further informed the FERC that certain of our traders did engage in trades on the Intercontinental Exchange, an electronic electricity trading platform owned by a group of electricity trading companies, including us, on September 21, 2001, the day on which all brokerage commissions for trades on that exchange were donated to charities for the victims of the September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a "wash sale" but do have certain characteristics in common with such sales. In response to a request from the California attorney general for a copy of AEP's responses to the FERC inquires, we provided the pertinent information. The PUCT also issued similar data requests to AEP and other power marketers. AEP responded to such data request by the July 2, 2002 response date. The US Commodity Futures Trading Commission (CFTC) issued a subpoena on June 17, 2002 requesting information with respect to "wash sale" trading practices. We responded to CFTC. In addition, the US Department of Justice made a civil investigation demand to us and other electric generating companies concerning their investigation of the Intercontinental Exchange. We have recently completed a review of our trading activities in the United States for the last three years involving sequential trades with the same terms and counterparties. The revenue from such trading is not material to our financial statements. We believe that substantially all these transactions involve economic substance and risk transference and do not constitute "wash sales". Minority Interest in Finance Subsidiary - Affecting AEP In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, and sold a non-controlling preferred member interest in Caddis to an unconsolidated special purpose entity (Steelhead) for $750 million. Under the provisions of the Caddis formation agreements, the preferred member interest receives quarterly a preferred return equal to an adjusted floating reference rate. The $750 million received replaced interim funding used to acquire Houston Pipe Line Company in June 2001. The preferred interest is supported by natural gas pipeline assets and $321.4 million of preferred stock issued by an AEP subsidiary to the AEP affiliate which has the managing member interest in Caddis. Such 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 the preferred interest were reduced by $225 million. In addition, Caddis has the right to redeem the preferred member interest at any time. The initial period of the preferred interest is through August 2006. At the end of the initial period, Caddis will either reset the preferred rate, re-market the preferred member interests to new investors, redeem the preferred member interests, in whole or in part including accrued return, or liquidate in accordance with the provisions of applicable agreements. Steelhead has the right to terminate the transaction and liquidate 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 $321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest. Liquidation of the preferred interest or of Caddis could negatively impact AEP's liquidity. Foreign Distribution Projects - Affecting AEP We own a 44% equity interest in Vale, a Brazilian electric operating company which was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric operating company), a subsidiary of Vale. Vale and Caiua have experienced losses from operations and our investment has been affected by the devaluation of the Brazilian Real. The cumulative equity share of operating and foreign currency translation losses through June 30, 2002 is approximately $47 million and $58 million, respectively, net of tax. The cumulative equity share of operating and foreign currency translation losses through December 31, 2001 is approximately $46 million and $54 million, respectively, net of tax. Both investments are covered by a put option, which, if exercised, requires our partners in Vale to purchase our Vale and Caiua shares at a minimum price equal to the U.S. dollar equivalent of the original purchase price. As a result, management has concluded that the investment carrying amount should not be reduced below the put option value unless it is deemed to be an other than temporary impairment and our partners in Vale are deemed unable to fulfill their responsibilities under the put option. In January 2002, management evaluated through an independent third-party, the ability of its Vale partners to fulfill their responsibilities under the put option agreement and concluded that our partners should be able to fulfill their responsibilities. Management believes that the decline in the value of its investment in Vale in US dollars is not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investments. As a result we will not recognize any future earnings from Vale and Caiua until the operating losses are recovered. In addition, our partners have a principal payment due in November 2002 in the amount of $55 million. Our partners plan to refinance the debt before the payment comes due. Should the impairment of our investment become other than temporary due to our partners in Vale becoming unable to fulfill their responsibilities, it would have an adverse effect on future results of operations. Management will continue to monitor both the status of the losses and its partners ability to fulfill their obligations under the put option. FERC Proposed Security Standards In July 2002 the FERC published for comment its proposed security standards as part of the Standards for Market Design (SMD). These standards are intended to ensure all market participants have a basic security program that effectively protects the electric grid and related market activities and require compliance by January 1, 2004. The impact of these proposed standards is far-reaching and has significant penalties for non-compliance. These standards apply to marketers, transmission owners, and power producers. For the AEP System this includes: regulated and non-regulated power generation plants, transmission systems, distribution systems, regulated and non-regulated energy trading, and related areas of business. These standards represent a significant effort that will impact the entire AEP System. Unless the cost can be recovered from customers, results of operations and cash flows would be adversely affected. FERC Market Power Mitigation A FERC order on AEP's triennial market based wholesale power rate authorization update required certain mitigation actions that AEP would need to take for sales/purchases within its control area and required AEP to post information on its website regarding its power systems status. As a result of a request for rehearing filed by AEP and other market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. No such conference has been held and management is unable to predict the timing of any further action by the FERC or its affect on future results of operations and cash flows. Other AEP and its subsidiary registrants continue to be involved in certain other matters discussed in the 2001 Annual Report. New Accounting Standard In June 2002, the FASB's Emerging Issues Task Force (EITF) in Issue No. 02-3 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities", reached a consensus that energy trading contracts (whether realized or unrealized and whether financially or physically settled) should be shown net in the income statement and that expanded disclosures of energy trading activities are required. This consensus is effective for periods ending after July 15, 2002 and reclassification of prior period amounts is required. Our adoption of EITF Issue No. 02-3 in the third quarter 2002 financial statements will lead to a material decrease in both revenues and purchased energy expense. There will be no impact on results of operations. Previous guidance in EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities", permitted settled forward energy trading contract sales and purchases to be shown either gross or net in the income statement. AEP currently records, and reports upon settlement, sales under forward trading contracts as revenues and purchases under forward trading contracts as purchased energy expense. The table below shows the amounts of revenues and purchased energy expense that AEP would report if forward sales and purchase contracts that settle financially were accounted for on a net basis. The determination of net trading revenues under EITF Issue No. 02-3 may yield a different result than calculating net revenues on the basis of financially settled transactions only. We are currently assessing the application of EITF Issue No. 02-3 to report trading transactions on a net basis.
Six Months Ended June 30, 2002 2001 (in millions) Gross Net Gross Net ----- --- ----- --- Revenues: Electricity Marketing and Trading $ 17,525 $4,042 $18,831 $4,788 Gas Marketing and Trading 8,477 1,014 7,203 573 Domestic Electricity Delivery 1,694 1,694 1,672 1,672 Other Investments 246 246 238 238 ------- ------ ------- ------ Total $27,942 $6,996 $27,944 $7,271 ======= ====== ======= ====== Gross Net Gross Net ----- --- ----- --- Fuel and Purchased Energy Expense: Electricity Marketing and Trading $ 15,046 $1,563 $16,945 $2,902 Gas Marketing and Trading 8,602 1,139 6,939 309 Other Investments 165 165 104 104 ------- ------ ------- ------ Total $23,813 $2,867 $23,988 $3,315 ======= ====== ======= ======
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU As a major power producer and trader of wholesale electricity and natural gas, we have 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 us 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 our day to day operations. Our risk policies have been reviewed with the Board of Directors, approved by a Risk Management Committee and administered by a Chief Risk Officer. The Risk Management 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. We use a risk measurement model which calculates Value at Risk (VaR) to measure our commodity price risk. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Based on this VaR analysis, at June 30, 2002 a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition. The following table shows the high, average, and low market risk as measured by VaR for the: Six Months Ended Year Ended June 30, December 31, 2002 2001 ---- ---- High Average Low High Average Low (in millions) (in millions) AEP $22 $12 $6 $28 $14 $5 APCo 3 2 1 4 1 - CPL - - - 3 1 - CSPCo 2 1 - 2 1 - I&M 2 1 - 3 1 - KPCo 1 - - 1 - - OPCo 3 1 - 3 1 - PSO - - - 2 1 - SWEPCo - - - 3 1 - WTU - - - 1 1 - We also utilize 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 and a one year holding period. The volatilities and correlations were based on three years of weekly 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 $639 million at June 30, 2002 and $673 million at December 31, 2001. However, since we would not expect to liquidate our entire debt portfolio in a one year holding period, 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 CPL and WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia. 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. We employ 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. However, we engage in trading of electricity, gas and to a lesser degree coal, oil, natural gas liquids, and emission allowances and as a result the Company is subject to price risk. The amount of risk taken by the traders is controlled by the management of the trading operations and the Company's Chief Risk Officer and his staff. When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee. We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates or fair values on short and long-term debt when management deems it necessary. We do not hedge all interest rate risk. We employ cash flow forward hedge contracts to lock-in prices on certain power trading transactions and certain transactions denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in foreign currencies. We do not hedge all foreign currency exposure. AEP limits credit risk by extending unsecured credit to entities based on internal ratings. In addition, 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. This data, in conjunction with the ratings information, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below investment grade counterparties in our normal course of business. We trade electricity and gas contracts with numerous counterparties. Since our open energy trading contracts are valued based on changes in market prices of the related commodities, our exposures change daily. We believe that our credit and market exposures with any one counterparty is not material to financial condition at June 30, 2002. At June 30, 2002 approximately 8% of the counterparties were below investment grade as expressed in terms of Net Mark to Market Assets. Net Mark to Market Assets represents the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price. The following table approximates counterparty credit quality and exposure for AEP. Futures, Forwards and Counterparty Swap Contracts Options Total Credit Quality: June 30, 2002 (in millions) AAA/Exchanges $ - $51 $ 51 AA 115 - 115 A 327 - 327 BBB 784 7 791 Below Investment Grade 103 2 105 ------ --- ------ Total $1,329 $60 $1,389 ====== === ====== The counterparty credit quality and exposure for the registrant subsidiaries is generally consistent with that of AEP. We enter into transactions for electricity and natural gas as part of wholesale trading operations. Electric and gas transactions are executed over the counter with counterparties or through brokers. Gas transactions are also executed through brokerage accounts with brokers who are registered with the Commodity Futures Trading Commission. Brokers and counterparties require cash or cash related instruments to be deposited on these transactions as margin against open positions. The combined margin deposits at June 30, 2002 and December 31, 2001 were $241 million and $55 million. These margin accounts are restricted and therefore are not included in cash and cash equivalents on the Balance Sheet. We can be subject to further margin requirements should related commodity prices change. We recognize the net change in the fair value of all open trading contracts, a practice commonly called mark-to-market accounting, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. The marking to market of open trading contracts in the second quarter of 2002 resulted in an unrealized increase in revenues of $40 million and unrealized increase in revenues of $87 million year-to-date. The fair value of open short-term trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts are based mainly on Company developed valuation models. This fair value is present valued and reduced by appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Forward price curves are developed for inclusion in the model based on broker quotes and other available market data. The curves are within the range between the bid and ask prices. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price of the bid ask prices if we have a long position and the ask price if we have a short position. This provides for a conservative valuation net of the reserves. The use of these models to fair value open long-term trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects on future results of operations and cash flows could occur if market prices, at the time of settlement, do not correlate with the Company developed price models. The effect on the Consolidated Statements of Income of marking to market open electricity trading contracts in the Company's regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Unrealized mark-to-market gains and losses from trading are reported as assets and liabilities, respectively. The following table shows net revenues (revenues less fuel and purchased energy expense) and their relationship to the mark-to-market revenues (the change in fair value of open trading positions). Six Months Ended June 30, 2002 (in millions) Revenues (including mark-to-market adjustment) $27,942 Fuel and Purchased Energy Expense 23,813 ------- Net Revenues $ 4,129 ======= Mark-to-Market Revenues on Open Trading Positions $87* === Percentage of Net Revenues Represented by Mark-to-Market on Open Trading Positions 2% = *Excludes reversal of $294 million of mark to market for contracts that settled in 2002. The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Energy Trading Contracts and Related Derivatives" shows how the net fair value of energy trading contracts was derived from the amounts included in the balance sheet line item "energy trading and derivative contracts." The next table "Energy Trading Contracts and Related Derivatives" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts and related derivatives at December 31, 2001 of $448 million to June 30, 2002 of $187 million. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Energy Trading Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value. Net Fair Value of Energy Trading Contracts and Related Derivatives June 30, December 31, --------------- ------------ 2002 2001 ---- ---- (in millions) (in millions) Energy Trading and Derivative Contracts: Current Asset $ 9,466 $ 8,572 Long-term Asset 3,672 2,370 Current Liability (9,538) (8,311) Long-term Liability (3,444) (2,183) ------- ------- Net Fair Value of Energy Trading Contracts and Derivative Contracts 156 448 Less non-trading related derivatives (31) - ------- ------- Net Fair Value of Energy Trading Contracts and Related Derivatives $ 187 $ 448 ======= ======= The above net fair value of energy trading contracts and related derivatives includes $47 million, at June 30, 2002, in unrealized mark-to-market gains that are recognized in the income statement at June 30, 2002. Also included in the above net fair value of energy trading contracts and related derivatives are option premiums that are deferred until the related contracts settle and the portion of changes in fair values of electricity trading contracts that are deferred for ratemaking purposes.
AEP Consolidated Energy Trading Contracts and Related Derivatives (in millions) Total Net Fair Value of Energy Trading Contracts and Related Derivatives at December 31, 2001 $ 448 (Gain) Loss from Contracts realized/settled during period (367) (a) Adjustments to (gain) Loss for Contracts entered into and Settled during period 108 (a) Fair Value of new open contracts when entered into during the period 50 (b) Net option premium payments 21 Change In fair value due to Methodology Changes 1 (c) Changes in market value of contracts (74) (d) ----- Net Fair Value of Energy Trading Contracts and Commodity Derivatives at June 30, 2002 $ 187 (e) =====
(a) (Gain) Loss from Contracts Realized or Otherwise Settled During the Period" include realized gains from energy trading contracts and related derivatives that settled during 2002 that were entered into prior to 2002, as well as during 2002. "Adjustments to gains or losses for Contracts Entered into and Settled During the Period" discloses the realized gains from settled energy trading contracts that were both entered into and closed within 2002 that are included in the total gains of $367 million, but not included in the ending balance of open contracts. (b) The "Fair Value of New Open Contracts When Entered Into During Period" represents the fair value of long-term contracts entered into with customers during 2002. 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 representative of the delivery location. (c) The Company changed the discount rate applied to its trading portfolio from BBB+ Utility to LIBOR in the second quarter which increased fair value by $10 million. In addition, the Company changed its methodology in valuing a spread option model so as to more accurately reflect the exercising of power transactions at optimal prices which reduced fair value by $9 million. (d) "Change in market Value of Contracts" represents the fair value change in the trading portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. (e) The net change in the fair value of energy trading contracts for 2002 that resulted in a decrease of $261 million ($187 million less $448 million) represents the balance sheet change. The net mark-to-market gain on energy trading contracts of $47 million and net mark-to-market gain on gas inventory positions of $40 million represent the impact on earnings related to open trading positions as of June 30, 2002. The difference is related primarily to settlement of prior period open energy trading contracts ($294 million decrease); regulatory deferrals of certain mark-to-market gains that were recorded as regulatory liabilities and not reflected in the income statement for those companies that operate in regulated jurisdictions; and deferrals of option premiums included in the above analysis, which do not have a mark-to-market income statement impact.
Energy Trading Contracts (in thousands) APCo CPL CSPCo Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 75,701 $ 3,857 $ 48,449 (Gain) Loss from Contracts realized/settled during period (19,026) (1,133) (12,470) Change in Fair Value Due To Methodology Changes 350 42 228 Adjustments to (gain) loss for Contracts entered into and settled during the period 7,419 761 4,848 Fair Value of new open Contracts when entered into during period 9,031 1,897 5,901 Net option premium payments 354 - 232 Changes in market value of Contracts 14,669 (5,498) 12,522 -------- ------- -------- Net Fair Value of Energy Trading Contracts at June 30, 2002 $ 88,498 $ (74) $ 59,710 ======== ======= ========
Energy Trading Contracts (in thousands) I&M KPCo OPCo Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 61,345 $12,729 $ 65,446 (Gain) Loss from Contracts realized/settled during period (13,492) (4,921) (16,959) Change in Fair Value Due To Methodology Changes 247 90 311 Adjustments to (gain) loss for Contracts entered into and settled During the period 5,246 1,915 6,593 Fair Value of new open Contracts when entered into during period 6,385 2,331 8,025 Net option premium payments 251 92 315 Changes in market value of Contracts (1,014) 4,972 26,175 ------- ------- -------- Net Fair Value of Energy Trading Contracts at June 30, 2002 $ 58,968 $17,208 $ 89,906 ======== ======= ========
Energy Trading Contracts (in thousands) PSO SWEPCo WTU Net Fair Value of Energy Trading Contracts at December 31, 2001 $ 2,434 $ 2,900 $ 915 (Gain) Loss from Contracts realized/settled during the period (863) (990) (336) Change in Fair Value Due To Methodology Changes 32 36 12 Adjustments to (gain) loss for Contracts Entered into and settled during period 579 665 226 Fair Value of new open Contracts when entered into during period 605 694 2,246 Net option premium payments - - - Changes in market value of Contracts (7,178) (8,239) (1,013) ------- ------- ------- Net Fair Value of Energy Trading Contracts at June 30, 2002 $(4,391) $(4,934) $ 2,050 ======= ======= =======
Energy Trading Contract Maturities Fair Value of Contracts at June 30, 2002 Maturities (in millions) Total AEP Consolidated Less than 4-5 In Excess Fair Source of Fair Value 1 year 1-3 years years Of 5 years Value -------------------- ------ --------- ----- ---------- ----- Prices actively quoted (a) $(134) $ 84 $ - $ - $(50) Prices provided by other external Sources (b) 74 115 8 - 197 Prices based on models and other Valuation methods (c) (2) (26) 40 28 40 ----- ---- --- --- ---- Total $ (62) $173 $48 $28 $187 ===== ==== === === ====
Energy Trading Contract Maturities Fair Value of Contracts at June 30, 2002 Maturities (in thousands) Total Less than 4-5 In Excess Fair Source of Fair Value 1 year 1-3 years years Of 5 years Value -------------------- ------ --------- ----- ---------- ----- APCo Prices provided by other External Sources (b) $23,532 $14,422 $ 2,358 $ - $40,312 Prices based on models and other Valuation methods (c) 6,079 23,757 9,655 8,695 48,186 ------- ------- ------- ------ ------- Total $29,611 $38,179 $12,013 $8,695 $88,498 ======= ======= ======= ====== ======= CPL Prices provided by other External Sources (b) $(2,458) $ 739 $121 $ - $(1,598) Prices based on models and other Valuation methods (c) (635) 1,218 495 446 1,524 -------- ------ ---- ---- ------- Total $(3,093) $1,957 $616 $446 $ (74) ======== ====== ==== ==== ======= CSP Prices provided by other External Sources (b) $16,874 $ 9,423 $1,540 $ - $27,837 Prices based on models and other Valuation methods (c) 4,359 15,523 6,309 5,682 31,873 ------- ------- ------ ------ ------- Total $21,233 $24,946 $7,849 $5,682 $59,710 ======= ======= ====== ====== ======= KPCo Prices provided by other External Sources (b) $1,599 $3,722 $ 608 $ - $ 5,929 Prices based on models and other Valuation methods (c) 413 6,130 2,492 2,244 11,279 ------ ------ ------ ------ ------- Total $2,012 $9,852 $3,100 $2,244 $17,208 ====== ====== ====== ====== =======
I&M Prices provided by other External Sources (b) $17,626 $ 9,009 $1,473 $ - $28,108 Prices based on models and other Valuation methods (c) 4,554 14,841 6,032 5,433 30,860 ------- ------- ------ ------ ------- Total $22,180 $23,850 $7,505 $5,433 $58,968 ======= ======= ====== ====== ======= OPCo Prices provided by other External Sources (b) $27,625 $13,505 $ 2,208 $ - $43,338 Prices based on models and other Valuation methods (c) 7,137 22,246 9,042 8,143 46,568 ------- ------- ------- ------ ------- Total $34,762 $35,751 $11,250 $8,143 $89,906 ======= ======= ======= ====== ======= PSO Prices provided by other External Sources (b) $(4,924) $ 442 $ 72 $ - $(4,410) Prices based on models and other Valuation methods (c) (1,272) 728 296 267 19 -------- ------ ---- ---- ------- Total $(6,196) $1,170 $368 $267 $(4,391) ======== ====== ==== ==== ======= SWEPCo Prices provided by other External Sources (b) $(5,568) $ 507 $ 83 $ - $(4,977) Prices based on models and other Valuation methods (c) (1,438) 836 340 306 43 -------- ------ ---- ---- ------- Total $(7,006) $1,343 $423 $306 $(4,934) ======== ====== ==== ==== ======= WTU Prices provided by other External Sources (b) $220 $ 434 $ 71 $ - $ 725 Prices based on models and other Valuation methods (c) 57 715 291 262 1,325 ---- ------ ---- ---- ------ Total $277 $1,149 $362 $262 $2,050 ==== ====== ==== ==== ======
(a) "Prices Actively Quoted" represents the Company's exchange traded natural gas futures. (b) "Prices Provided by Other External Sources" represents the Company's positions in natural gas, power, and coal at points where over-the-counter broker quotes are available. Some prices from external sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this category. (c) "Prices Based on Models and Other Valuation Methods" contain the following: the value of the Company's adjustments for liquidity and counterparty credit exposure, the value of contracts not quoted by an exchange or an over-the-counter broker, the value of transactions for which an internally developed price curve was developed as a result of the long dated nature of certain transactions, and the value of certain structured transactions. Item 4. Submission of Matters to a Vote of Security Holders. --------------------------------------------------- AEP The annual meeting of shareholders was held in Columbus, Ohio, on April 23, 2002. The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following three matters, as indicated below: 1. Election of thirteen directors to hold office until the next annual meeting and until their successors are duly elected. Each nominee for director received the votes of shareholders as follows:
Number of Shares Number of Nominee Voted For Votes Withheld E. R. Brooks 201,037,003 55,252,755 Donald M. Carlton 248,549,741 7,740,017 John P. DesBarres 252,026,061 4,263,697 E. Linn Draper, Jr. 249,765,263 6,524,495 Robert W. Fri 251,979,293 4,310,465 William R. Howell 247,814,513 8,475,245 Lester A. Hudson, Jr. 249,730,186 6,559,572 Leonard J. Kujawa 251,840,096 4,449,662 Richard L. Sandor 252,037,196 4,252,562 Thomas V. Shockley, III 251,929,822 4,359,936 Donald G. Smith 252,372,686 3,917,072 Linda Gillespie Stuntz 251,968,011 4,321,747 Kathryn D. Sullivan 249,653,889 6,635,869
2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as independent auditors of AEP for the year 2002. The proposal was approved by a vote of the shareholders as follows: Votes FOR 244,793,710 Votes AGAINST 9,303,198 Votes ABSTAINED 6,062,395 Broker NON-VOTES* 0 3. Shareholder proposal submitted by Ronald Marsico. The proposal was disapproved by a vote of the shareholders as follows: Votes FOR 14,495,798 Votes AGAINST 192,849,019 Votes ABSTAINED 6,062,395 Broker NON-VOTES* 42,882,546 *A non-vote occurs when a nominee holding shares for a beneficial owner votes on one proposal, but does not vote on another proposal because the nominee does not have discretionary voting power and has not received instructions from the beneficial owner. APCo The annual meeting of stockholders was held on April 23, 2002 at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers CPL Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 11, 2002, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers I&M Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 23, 2002, the following thirteen persons were elected directors to hold office for one year or until their successors are elected and qualify: Karl G. Boyd Robert P. Powers E. Linn Draper, Jr. John R. Sampson John E. Ehler Thomas V. Shockley, III Henry W. Fayne David B. Synowiec David L. Lahrman Susan Tomasky Marc E. Lewis Joseph H. Vipperman Susanne M. Moorman OPCo The annual meeting of shareholders was held on May 7, 2002 at 1 Riverside Plaza, Columbus, Ohio. At the meeting there were 27,952,473 votes cast FOR: 1. Each of the following seven persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley, III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers 2. Approval of amendment to Article Second of the Amended Articles of Incorporation of OPCo providing that the principal office of OPCo is to be located at 1 Riverside Plaza, Columbus, Franklin County, Ohio, and there were no votes against, abstentions or broker non-votes. SWEPCo Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 10, 2002, the following seven persons were elected directors to hold office for one year or until their successors are elected and qualify: E. Linn Draper, Jr. Thomas V. Shockley III Henry W. Fayne Susan Tomasky Armando A. Pena Joseph H. Vipperman Robert P. Powers Item 5. Other Information. AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Reference is made to page 29 of the Annual Report on Form 10-K for the year ended December 31, 2001 (2001 10-K) for a discussion of regional haze. On May 24, 2002, the D.C. Circuit Court issued an opinion and order vacating in part and upholding in part the regional haze rule. The court held that Federal EPA could not establish Best Available Retrofit Technology standards for entire groups of emission sources without regard to improvement in visibility attributable to individual source controls. Federal EPA has filed a petition seeking rehearing by the entire D.C. Circuit Court. AEP Reference is made to pages 31 through 33 of the 2001 10-K for a discussion of the Clean Water Act. On May 8, 2002, the U.S. District Court for the Southern District of West Virginia issued an injunction prohibiting the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the primary purpose of disposal of waste mining overburden and spoil. On June 17, 2002, the court denied a request for stay filed by the U.S. Department of Justice and intervenor, Kentucky Coal Association. The court clarified that the decision only applies to the Corps' Huntington District. The court also advised that the ruling does not apply to dredged material placed back in the stream but does apply to activities other than coal mining that require Section 404 permits. The intervenor-defendants have filed an appeal to the U.S. Fourth Circuit Court of Appeals and the court has set a briefing schedule. The effect on permitting activities of certain AEP subsidiaries under Section 404 cannot be predicted but could be significant. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: OPCo Exhibit 3(d) - Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated June 3, 2002. Exhibit 3(e) - Composite copy of the Amended Articles of Incorporation of OPCo (amended as of June 3, 2002). AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges. AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU 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: Company Reporting Date of Report Item Reported AEP June 5, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits APCo June 13, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits AEP June 18, 2002 Item 5. Other Events and Regulation FD Disclosure SWEPCo June 20, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits KPCo June 25, 2002 Item 5. Other Events and Regulation FD Disclosure Item 7. Financial Statements and Exhibits AEGCo, CPL, CSPCo, I&M, OPCo, PSO, and WTU No reports on Form 8-K were filed during the quarter ended June 30, 2002. Signature Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. AMERICAN ELECTRIC POWER COMPANY, INC. By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto ----------------------- ---------------------------- Armando A. Pena Joseph M. Buonaiuto Treasurer Controller and Chief Accounting Officer AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY INDIANA MICHIGAN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto ----------------------- ---------------------------- Armando A. Pena Joseph M. Buonaiuto Vice President and Controller and Chief Accounting Officer Treasurer Date: August 13, 2002