-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SWA531N4Szpyiyke2SrpWTBty1uSZWxCA2vUBEAv8TksY0WeJ9Pmh/7h2j4aMz2l WqltYwv8GsqORafMsapwAA== 0000100826-02-000012.txt : 20020515 0000100826-02-000012.hdr.sgml : 20020515 20020515165449 ACCESSION NUMBER: 0000100826-02-000012 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020331 FILED AS OF DATE: 20020515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UNION ELECTRIC CO CENTRAL INDEX KEY: 0000100826 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 430559760 STATE OF INCORPORATION: MO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-02967 FILM NUMBER: 02653368 BUSINESS ADDRESS: STREET 1: 1901 CHOUTEAU AVENUE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166 BUSINESS PHONE: 3146213222 MAIL ADDRESS: STREET 1: 1901 CHOUTEAU AVENUE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166 10-Q 1 ue10q0302.txt UE10Q0302 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For Quarterly Period Ended March 31, 2002 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period From to Commission file number 1-2967. UNION ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Missouri 43-0559760 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1901 Chouteau Avenue, St. Louis, Missouri 63103 (Address of principal executive offices and Zip Code) Registrant's telephone number, including area code: (314) 621-3222 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . ------------ ------------ Shares outstanding of each of the registrant's classes of common stock as of May 10, 2002: Common Stock, $5 par value, held by Ameren Corporation (parent company of registrant) - 102,123,834 UNION ELECTRIC COMPANY INDEX Page ---- PART I Financial Information ITEM 1. Financial Statements Balance Sheet at March 31, 2002 and December 31, 2001............ 2 Statement of Income for the three months ended March 31, 2002 and 2001.......................................... 3 Statement of Cash Flows for the three months ended March 31, 2002 and 2001.......................................... 4 Statement of Common Stockholder's Equity for the three months ended March 31, 2002 and 2001.................................... 5 Notes to Financial Statements.................................... 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................ 11 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk....... 17 PART II Other Information ITEM 1. Legal Proceedings................................................ 21 ITEM 6. Exhibits and Reports on Form 8-K................................. 21 SIGNATURE................................................................... 22 1 PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements
UNION ELECTRIC COMPANY BALANCE SHEET (In Millions, Except Per Share Amounts) March 31, December 31, 2002 2001 ----------- ------------ (Unaudited) ASSETS: Property and plant, at original cost: Electric $ 9,919 $ 9,828 Gas 255 252 Other 37 37 -------- -------- 10,211 10,117 Less accumulated depreciation and amortization 4,862 4,802 -------- -------- 5,349 5,315 Construction work in progress: Nuclear fuel in process 102 97 Other 288 298 -------- -------- Total property and plant, net 5,739 5,710 -------- -------- Investments and other assets: Nuclear decommissioning trust fund 188 187 Other 84 75 -------- -------- Total investments and other assets 272 262 -------- -------- Current assets: Cash and cash equivalents 12 15 Accounts receivable - trade (less allowance for doubtful accounts of $8 and $7, respectively) 222 234 Other accounts and notes receivable 30 73 Intercompany notes receivable - 84 Materials and supplies, at average cost - Fossil fuel 56 71 Other 86 85 Other 13 16 -------- -------- Total current assets 419 578 -------- -------- Regulatory assets: Deferred income taxes 604 604 Other 131 134 -------- -------- Total regulatory assets 735 738 -------- -------- Total Assets $ 7,165 $ 7,288 ======== ======== CAPITAL AND LIABILITIES: Capitalization: Common stock, $5 par value, 150.0 shares authorized - 102.1 shares outstanding $ 511 $ 511 Other paid-in capital, principally premium on common stock 702 702 Retained earnings 1,413 1,440 Accumulated other comprehensive income (1) 1 -------- -------- Total common stockholder's equity 2,625 2,654 -------- -------- Preferred stock not subject to mandatory redemption 155 155 Long-term debt 1,605 1,599 -------- -------- Total capitalization 4,385 4,408 -------- -------- Current liabilities: Current maturity of long-term debt 89 92 Short-term debt - 186 Intercompany notes payable 192 - Accounts and wages payable 135 305 Accumulated deferred income taxes 34 35 Taxes accrued 158 104 Other 126 128 -------- -------- Total current liabilities 734 850 -------- -------- Accumulated deferred income taxes 1,322 1,326 Accumulated deferred investment tax credits 127 129 Regulatory liabilities 137 137 Other deferred credits and liabilities 460 438 -------- -------- Total Capital and Liabilities $ 7,165 $ 7,288 ======== ========
See Notes to Financial Statements. 2 UNION ELECTRIC COMPANY STATEMENT OF INCOME UNAUDITED (In Millions) Three Months Ended March 31, ------------------------- 2002 2001 OPERATING REVENUES: ---- ---- Electric $ 684 $ 597 Gas 50 69 ----- ----- Total operating revenues 734 666 OPERATING EXPENSES: Operations Fuel and purchased power 294 219 Gas 32 46 Other 129 130 ----- ----- 455 395 Maintenance 55 58 Depreciation and amortization 72 69 Income taxes 28 31 Other taxes 52 50 ----- ----- Total operating expenses 662 603 ----- ----- OPERATING INCOME 72 63 OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction 1 1 Miscellaneous, net 3 7 ----- ----- Total other income and (deductions) 4 8 INCOME BEFORE INTEREST CHARGES 76 71 INTEREST CHARGES: Interest 27 30 Allowance for borrowed funds used during construction (2) (2) ----- ----- Net interest charges 25 28 ----- ----- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 51 43 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES - (5) ----- ----- NET INCOME 51 38 PREFERRED STOCK DIVIDENDS 2 2 ----- ----- NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 49 $ 36 ===== ===== See Notes to Financial Statements. 3 UNION ELECTRIC COMPANY STATEMENT OF CASH FLOWS UNAUDITED (In Millions) Three Months Ended March 31, --------------------- 2002 2001 ---- ---- Cash Flows From Operating: Net income $ 51 $ 38 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle - 5 Depreciation and amortization 69 65 Amortization of nuclear fuel 7 9 Allowance for funds used during construction (3) (3) Deferred income taxes, net (4) (6) Deferred investment tax credits, net (2) (2) Changes in assets and liabilities: Receivables, net 55 9 Materials and supplies 14 9 Accounts and wages payable (170) (69) Taxes accrued 54 56 Other, net 14 18 ----- ----- Net cash provided by operating activities 85 129 Cash Flows From Investing: Construction expenditures (101) (89) Allowance for funds used during construction 3 3 Nuclear fuel expenditures (5) (8) Intercompany notes receivable 84 18 ----- ----- Net cash used in investing activities (19) (76) Cash Flows From Financing: Dividends on common stock (76) (54) Dividends on preferred stock (2) (2) Redemptions: Nuclear fuel lease - (35) Short-term debt (186) - Issuances: Nuclear fuel lease 3 2 Long-term debt - 41 Intercompany notes payable 192 - ----- ----- Net cash used in financing activities (69) (48) ----- ----- Net change in cash and cash equivalents (3) 5 Cash and cash equivalents at beginning of year 15 20 ----- ----- Cash and cash equivalents at end of period $ 12 $ 25 ===== ===== Cash paid during the periods: Interest (net of amount capitalized) $ 19 $ 21 Income taxes, net $ 4 $ - See Notes to Financial Statements. 4
UNION ELECTRIC COMPANY STATEMENT OF COMMON STOCKHOLDER'S EQUITY UNAUDITED (In Millions) Three Months Ended March 31, --------------------- 2002 2001 ---- ---- Common stock $ 511 $ 511 Other paid-in capital 702 702 Retained earnings Beginning balance 1,440 1,358 Net income 51 38 Common stock dividends (76) (54) Preferred stock dividends (2) (2) ------------ ---------- 1,413 1,340 Accumulated other comprehensive income Beginning balance 1 - Change in current period (2) (2) ------------ ---------- (1) (2) Total common stockholder's equity $ 2,625 $ 2,551 ============ ========== Comprehensive income, net of taxes Net income $ 51 $ 38 Unrealized net gain/(loss) on derivative hedging instruments (2) 6 Cumulative effect of accounting change - (8) ------------ ---------- $ 49 $ 36 ============ ==========
See Notes to Financial Statements. 5 UNION ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS (UNAUDITED) March 31, 2002 NOTE 1 - Summary of Significant Accounting Policies Basis of Presentation Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of the interim results. These statements should be read in conjunction with the financial statements and the notes thereto included in our 2001 Annual Report on Form 10-K. When we refer to AmerenUE, our, we or us, we are referring to Union Electric Company. All dollar amounts are in millions, unless otherwise indicated. Accounting Changes In January 2001, we adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." The impact of that adoption resulted in a cumulative effect charge of $5 million after taxes to the income statement, and a cumulative effect adjustment of $8 million after taxes to Accumulated Other Comprehensive Income (OCI), which reduced common stockholder's equity. On January 1, 2002, we adopted SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business combinations to be accounted for under the purchase method of accounting, which requires one party in the transaction to be identified as the acquiring enterprise and for that party to allocate the purchase price to the assets and liabilities of the acquired enterprise based on fair market value. SFAS 142 requires goodwill and indefinite-lived intangible assets recorded in the financial statements to be tested for impairment at least annually, rather than amortized over a fixed period, with impairment losses recorded in the income statement. SFAS 141 and SFAS 142 did not have any effect on our financial position, results of operations or liquidity upon adoption. In July 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued. SFAS 143 requires an entity to record a liability and corresponding asset representing the present value of legal obligations associated with the retirement of tangible, long-lived assets. SFAS 143 is effective for us on January 1, 2003. At this time, we are assessing the impact of SFAS 143 on our financial position, results of operations and liquidity upon adoption. However, as a result of this new standard we expect significant increases to our reported assets and liabilities as a result of obligations associated with Callaway Nuclear Plant decommissioning costs which are being fully recovered in our rates. On January 1, 2002 we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 144 retains the guidance related to calculating and recording impairment losses, but adds guidance on the accounting for discontinued operations, previously accounted for under Accounting Principles Board Opinion No. 30. SFAS 144 did not have any effect on our financial position, results of operations or liquidity upon adoption. NOTE 2 - Rate and Regulatory Matters Missouri Electric From July 1, 1995 through June 30, 2001, we operated under experimental alternative regulation plans in Missouri that provided for the sharing of earnings with customers if our regulatory return on equity exceeded defined threshold levels. At March 31, 2002, we had an accrual representing the estimated credit 6 that we expect to pay our Missouri electric customers of $40 million for the plan year ended June 30, 2001. In 2002, the Missouri Public Service Commission (MoPSC) Staff and the Missouri Office of Public Counsel (OPC) Staff filed testimony with the MoPSC on this matter. Combined, the MoPSC Staff and OPC Staff recommend that the credit to customers for the plan year ended June 30, 2001, should approximate $80 million. The MoPSC is not bound by their recommendations. To date, a procedural schedule and hearing dates on this matter have not been established by the MoPSC. At this time, we continue to believe that our accrual is adequate in all material respects. Following expiration of the experimental alternative regulation plan on June 30, 2001, the MoPSC Staff filed an excess earnings complaint against us. Based upon a January 2002 MoPSC order, on March 1, 2002, the MoPSC Staff filed a recommendation that we reduce our annual Missouri electric revenues by $246 million to $285 million. The MoPSC Staff's recommendation is based on a return to traditional cost of service ratemaking, a return on equity ranging from 8.91% to 9.91%, a reduction in our depreciation rates, and other cost of service adjustments. The MoPSC is not bound by the Staff's recommendation. On May 10, 2002, we filed rebuttal testimony in response to the MoPSC Staff's recommendation. In our testimony, we stated that a return to traditional cost of service ratemaking would result in an increase in our annual Missouri electric revenues by approximately $150 million. Our position is based on a 12.5% return on equity, higher depreciation rates and other adjustments. However, a key component of our testimony is our recommendation that a new alternative rate regulation plan (Alt Reg Plan) be adopted by the MoPSC. In our filing, we included a new Alt Reg Plan proposal. Key provisions of the Alt Reg Plan include the following: o A three-year plan from July 1, 2002 through June 30, 2005 which would require us to share earnings over certain regulatory return on equity (ROE) thresholds for the 12 months ending July 1 through June 30; o The proposed earnings sharing grid would require us to provide sharing credits of $17 million if our regulatory ROE is between 10.5% and 12.5%. Additional credits of 55% of our earnings between a regulatory ROE of 12.5% and 15% would be provided, 90% of earnings between a regulatory ROE of 15% and 16%, and 100% of any earnings above 16%. o An immediate one-time credit to customers bills of $15 million; o An annualized $15 million permanent rate reduction, retroactive to April 1, 2002; o An immediate funding of $5 million to a low-income customer assistance program and $5 million to an economic development program; o A commitment of $1.5 billion to $1.75 billion in energy infrastructure investment from January 1, 2002 through June 30, 2005. Hearings for this case are scheduled to commence in mid-July 2002 and be completed in early August 2002. A final decision on this matter may not occur until the fourth quarter of 2002. In the interim, we plan to continue negotiations with all pertinent parties with the intent to continue with an incentive regulation plan. We cannot predict the outcome of the MoPSC's decision in this matter or its impact on our financial statements, results of operations or liquidity. However, the impact could be material. In order to satisfy our regulatory load requirements for 2001, we purchased, through a competitive bidding process, 450 megawatts of capacity and energy under a one-year contract from our affiliate, Ameren Energy Marketing Company (Marketing Company), at market-based rates. For 2002, we again, through a competitive bidding process, entered into a one-year contract with Marketing Company for the purchase of 200 megawatts of capacity and energy. For the four summer months of 2002, we also entered into contracts with two other power suppliers for an aggregate 200 megawatts of additional capacity and energy. In May 2001, the MoPSC filed a pleading with the Securities and Exchange Commission (SEC) relating to our agreement to purchase 450 megawatts of capacity and energy from Marketing Company during 2001 (the 2001 Marketing Company - AmerenUE agreement). The pleading requested an investigation into the contractual relationship between us, Marketing Company and our affiliate, AmerenEnergy Generating Company (Generating Company), in the context of the 2001 Marketing Company - AmerenUE agreement and requested that the SEC find that such relationship violates a provision of PUHCA which requires state utility commission approval of power sales contracts between an electric utility company and an affiliated electric wholesale generator, like Generating Company. We believe that the MoPSC's approval of the power sales agreement under PUHCA is not required because Generating Company is not a party to the agreement. As a remedy, the MoPSC proposes that the SEC require us to 7 contract directly with Generating Company and submit such contract to the MoPSC for review. The SEC has not responded to this matter to date. On May 9, 2002, the MoPSC filed a similar pleading with the SEC relating to AmerenUE's agreement to purchase 200 megawatts of capacity and energy from Marketing Company during 2002. At this time, management is unable to predict the outcome of these pleadings or the ultimate impact on our future financial position, results of operations or liquidity. Illinois In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Illinois Law) providing for electric utility restructuring in Illinois. This legislation introduced competition into the retail supply of electric energy in Illinois. Illinois residential customers were offered choice in suppliers on May 1, 2002. Industrial and commercial customers were already offered this choice. The offering of choice to our industrial and commercial customers has not had a material adverse effect on our business and we do not expect the offering of choice to our residential customers to have a material adverse effect on our business either. In addition, the Illinois Law contains a provision freezing residential electric rates through January 1, 2005. Legislation has been introduced in the Illinois House of Representatives and Senate that would extend the rate freeze to December 31, 2006. At this time, we cannot predict whether that legislation will ultimately be passed. Federal - Midwest ISO and Alliance RTO In December 1999, the Federal Energy Regulatory Commission (FERC) issued Order 2000, requiring all utilities, subject to FERC jurisdiction, to state their intentions for joining a regional transmission organization (RTO). RTOs are independent organizations that will functionally control the transmission assets of utilities in order to improve the wholesale power market. Since January 2001, we along with several other utilities have been seeking approval from the FERC to participate in an RTO known as the Alliance RTO. We had previously been a member of the Midwest Independent System Operator (MISO) and recorded a pretax charge to earnings in 2000 of $17 million ($10 million after taxes) for an exit fee and other costs when we left that organization. We felt the for-profit Alliance RTO business model was superior to the not-for-profit MISO business model and provided us with a more equitable return on our transmission assets. In late 2001, the FERC issued an order that rejected the formation of the Alliance RTO and ordered the Alliance RTO companies and the MISO to discuss how the Alliance RTO business model could be accommodated within the MISO. On April 25, 2002, after the Alliance RTO and MISO failed to reach an agreement, and after a series of filings by the two parties with the FERC, the FERC issued a declaratory order setting forth the division of responsibilities between the MISO and National Grid (the managing member of the transmission company formed by the Alliance companies) and approved the rate design and the revenue distribution methodology proposed by the Alliance companies. However, the FERC denied a request by the Alliance companies and the National Grid to purchase certain services from the MISO at incremental cost rather than MISO's full tariff rates. The FERC also ordered the MISO to return the exit fee paid by AmerenUE to leave the MISO, provided AmerenUE returns to the MISO and agrees to pay its proportional share of the startup and ongoing operational expenses of the MISO. Moreover, the FERC required the Alliance companies to select the RTO in which they will participate within thirty days of the order. At this time, we continue to evaluate our alternatives and are in the process of determining the impact that the FERC's April 2002 ruling will have on our future financial condition, results of operations or liquidity. NOTE 3 - Related Party Transactions AmerenUE has transactions in the normal course of business with Ameren Corporation, our parent company, and its subsidiaries. These transactions are primarily comprised of power purchases and sales and services received or rendered. Intercompany power purchases from joint dispatch and other agreements were approximately $27 million for the three months ended March 31, 2002, compared to $23 million for the three months ended March 31, 2001. Intercompany power sales totaled $20 million for the three months ended March 31, 2002, compared to $28 million for the three months ended March 31, 2001. Intercompany receivables included in Other Accounts and Notes Receivable were approximately $14 million as of March 31, 2002 (December 31, 2001 - $38 million). Intercompany payables included in Accounts and Wages Payable totaled approximately $47 million as of March 31, 2002 (December 31, 2001 - $70 million). 8 Support services provided by our affiliates, Ameren Services and AmerenEnergy, including wages, employee benefits, professional services and other expenses are based on actual costs incurred. For the three months ended March 31, 2002, Other Operating Expenses provided by Ameren Services and AmerenEnergy totaled $48 million, compared to $47 million for the same period in 2001. We have the ability to borrow up to approximately $425 million from Ameren or our affiliate, AmerenCIPS, through a regulated money pool agreement. The total amount available to us at any given time from the regulated money pool is reduced by the amount of borrowings by AmerenCIPS or Ameren Services, but increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds or the availability of other external borrowing sources. AmerenUE, AmerenCIPS and Ameren Services rely on the regulated money pool to coordinate and provide for certain short-term cash and working capital requirements. Ameren Services administers the regulated money pool. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. For the three months ended March 31, 2002, the average interest rate for the regulated money pool was 1.79% (2001 - 5.50%). As of March 31, 2002, we had outstanding intercompany payables of $192 million through the regulated money pool. At December 31, 2001, we had outstanding intercompany receivables of $84 million through the regulated money pool. At March 31, 2002, at least $357 million was available through the regulated money pool. NOTE 4 - Derivative Financial Instruments We utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause: o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory or under the firm commitment; and o actual cash outlays for the purchase of these commodities in certain circumstances to differ from anticipated cash outlays. The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internal forecasts of forward prices and modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, we believe these transactions serve to reduce price risk for AmerenUE. As of March 31, 2002, we recorded the fair value of derivative financial instrument assets of $20 million in Other Assets and the fair value of derivative financial instrument liabilities of $24 million in Other Deferred Credits and Liabilities. Cash Flow Hedges We routinely enter into forward purchase and sales contracts for electricity based on forecasted levels of economic generation and load requirements. The relative balance between load and economic generation varies throughout the year. The contracts typically cover a period of twelve months or less. The purpose of these contracts is to hedge against possible price fluctuations in the spot market for the period covered under the contracts. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objective and strategy for undertaking various hedge transactions. For the three months ended March 31, 2002, the pretax net gain, which represented the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, as well as the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, was approximately $1 million. As of March 31, 2002, the entire net loss on power forward derivative instruments of approximately $6 million, or approximately $4 million after tax, accumulated in OCI is expected to be recognized in earnings during the next twelve months upon delivery of the commodity being hedged. 9 We also hold a call option for coal with a supplier. This option to purchase coal expires October 15, 2003. The entire gain of approximately $5 million, or approximately $3 million after tax, accumulated in OCI is expected to be recognized in earnings prior to that date. Other Derivatives We enter into option transactions to manage our positions in sulfur dioxide (SO2) allowances, coal, and electricity. Most of these transactions are treated as non-hedge transactions under SFAS 133. Therefore, the net change in the market value of these options is recorded as Miscellaneous, net in the statement of income and was immaterial at March 31, 2002. NOTE 5 - Subsequent Event On April 28, 2002, Ameren entered into an agreement with The AES Corporation to purchase all or the outstanding stock of CILCORP Inc. CILCORP is the parent company of Peoria-based Central Illinois Light Company, which operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4), L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant. The total purchase price is approximately $1.4 billion, subject to adjustment for changes in CILCORP's working capital, and includes the assumption of CILCORP and AES Medina Valley debt at closing, estimated at approximately $900 million, with the balance of the purchase price in cash. Ameren currently expects to finance a significant portion of the cash component of the purchase price through the issuance of new common equity. The purchase will include CILCORP's regulated natural gas and electric businesses in Illinois serving approximately 200,000 and 205,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. In addition, the purchase includes approximately 1,200 megawatts of largely coal-fired generating capacity most of which is expected to be nonregulated by closing. Upon completion of the acquisition, expected within 12 months, CILCO will become an Ameren subsidiary, but will remain a separate utility company, operating as AmerenCILCO. The transaction is subject to the approval of the Illinois Commerce Commission, the SEC, the FERC, the expiration of the waiting period under the Hart-Scott-Rodino Act and other customary closing conditions. For the period ended December 31, 2001, CILCORP had revenues of $815 million, operating income of $126 million, and net income from continuing operations of $28 million, and as of December 31, 2001 had total assets of $1.8 billion. 10 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. OVERVIEW Union Electric Company is a wholly-owned subsidiary of Ameren Corporation operating as AmerenUE. Our principal business is the regulated generation, transmission and distribution of electricity, and the regulated distribution of natural gas to residential, commercial, industrial and wholesale users in Missouri and Illinois. Ameren Corporation is a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). Ameren's principal business is the generation, transmission and distribution of electricity, and the distribution of natural gas to residential, commercial, industrial and wholesale users in the central United States. In addition to us, Ameren's principal operating subsidiaries and our affiliates are as follows: o Central Illinois Public Service Company, which operates a regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. o AmerenEnergy Resources Company (Resources Company), which consists of nonregulated operations. Subsidiaries include AmerenEnergy Generating Company (Generating Company) that operates nonregulated electric generation in Missouri and Illinois, AmerenEnergy Marketing Company (Marketing Company), which markets power for periods over one year, and AmerenEnergy Fuels and Services Company, which procures fuel and manages the related risks for Ameren affiliated companies. o AmerenEnergy, Inc. which serves as a power marketing and risk management agent for Ameren affiliated companies for transactions of primarily less than one year. o Electric Energy, Inc. (EEI), which owns and/or operates electric generation and transmission facilities in Illinois. We have a 40% ownership interest in EEI and have accounted for it under the equity method of accounting. o Ameren Services Company, which provides shared support services to Ameren and its subsidiaries, including AmerenUE. Charges are based upon the actual costs incurred by Ameren Services, as required by PUHCA. You should read the following discussion and analysis in conjunction with: o The financial statements and related notes included in this Quarterly Report on Form 10-Q. o Management's Discussion and Analysis of Financial Condition and Results of Operations that appears in our Annual Report on Form 10-K for the period ended December 31, 2001. o The audited financial statements and related notes that appear in our Annual Report on Form 10-K for the period ended December 31, 2001. When we refer to AmerenUE, our, we or us, we are referring to Union Electric Company. All dollar amounts are in millions, unless otherwise indicated. Our results of operations and financial position are impacted by many factors, including both controllable and uncontrollable factors. Weather, economic conditions, and the actions of key customers or competitors can significantly impact the demand for our services. Our results are also impacted by seasonal fluctuations caused by winter heating and summer cooling demand. With nearly all of our revenues subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. We principally utilize coal, natural gas and nuclear fuel in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, production levels and many other factors. We do not have fuel recovery mechanisms in Missouri and Illinois, but do have gas cost recovery mechanisms in each state. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plant, and transmission and distribution systems, and the level of operating and administrative costs and capital investment are key factors that we seek to control in order to optimize our results of operations, cash flows and financial position. RESULTS OF OPERATIONS Our net income increased by 34% to $51 million in the first quarter of 2002 from $38 million in the first quarter of 2001. In the first quarter of 2001, we recorded a charge of $5 million due to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." See Accounting Matters. As a result, income before cumulative effect of change in 11 accounting principle in the first quarter of 2002 was $51 million compared to $43 million in the first quarter of 2001. Income before cumulative effect of change in accounting principle increased in the first quarter of 2002 versus the prior year primarily due to internal weather-normalized growth and the $9 million after-tax benefit of the lack of estimated credits to Missouri electric customers due to the expiration of our incentive rate plan on June 30, 2001. Partially offsetting these benefits was the effect of the extremely mild winter weather in our service territory. According to National Weather Service data, there were approximately 15% fewer heating degree days in our service territory in the first quarter of 2002 as compared to 2001 and normal weather conditions. As a result, weather-sensitive residential electric kilowatt-hour sales decreased by 5%, commercial electric kilowatt-hour sales decreased by 3% and gas sales decreased by 9% in the first quarter of 2002 compared to 2001. In addition, industrial electric kilowatt-hour sales decreased 7% due to the continued soft economy. Despite the warmer winter weather, total electric revenues increased 15% for the first quarter of 2002, compared to the year-ago period, primarily due to higher interchange sales. However, we realized lower margins on these sales compared to the prior year, due to lower wholesale electricity prices. Recent Developments On April 28, 2002, Ameren entered into an agreement with The AES Corporation to purchase all of the outstanding stock of CILCORP Inc. CILCORP is the parent company of Peoria-based Central Illinois Light Company, which operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4), L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant. The total purchase price is approximately $1.4 billion, subject to adjustment for changes in CILCORP's working capital, and includes the assumption of CILCORP and AES Medina Valley debt at closing, estimated at approximately $900 million, with the balance of the purchase price in cash. Ameren currently expects to finance a significant portion of the cash component of the purchase price through the issuance of new common equity. The purchase will include CILCORP's regulated natural gas and electric businesses in Illinois serving approximately 200,000 and 205,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. In addition, the purchase includes approximately 1,200 megawatts of largely coal-fired generating capacity most of which is expected to be nonregulated by closing. Upon completion of the acquisition, expected within 12 months, CILCO will become an Ameren subsidiary, but will remain a separate utility company, operating as AmerenCILCO. The transaction is subject to the approval of the Illinois Commerce Commission, the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the expiration of the waiting period under the Hart-Scott-Rodino Act and other customary closing conditions. For the period ended December 31, 2001, CILCORP had revenues of $815 million, operating income of $126 million, and net income from continuing operations of $28 million, and as of December 31, 2001 had total assets of $1.8 billion. As a result of the continuing uncertainty associated with our pending Missouri electric rate case, and the CILCORP transaction and related assumption of debt, credit rating agencies placed Ameren Corporation's debt under review for possible downgrade or negative credit watch. Standard & Poor's placed the ratings of our debt and AmerenCIPS debt on negative credit watch and placed the ratings of Generating Company's debt on positive credit watch. However, Standard & Poor's stated they expect the corporate credit ratings of Ameren and its subsidiaries to be in the "A" rating category following completion of the acquisition. Moody's Investor Service stated they envisioned a one notch downgrade of Ameren's issuer, senior unsecured debt and commercial paper ratings. Currently, Ameren's corporate credit rating is A+ at Standard and Poor's and A2 at Moody's. If the ratings of our first mortgage bonds fall below investment grade, lenders under our $300 million revolving credit facility may elect not to make advances and/or declare outstanding borrowings due and payable. In addition, a decrease in Ameren's ratings may indirectly reduce our access to capital and/or increase the costs of borrowings resulting in a negative impact on earnings. 12 Electric Operations The following table represents the favorable (unfavorable) variation for the three months ended March 31, 2002 from the comparable period in 2001: - -------------------------------------------------------------------------------- Three Months - -------------------------------------------------------------------------------- Operating Revenues: Credit to customers......................................... $ 15 Effect of abnormal weather (estimate)....................... (12) Growth and other (estimate)................................. 18 Interchange sales........................................... 66 - -------------------------------------------------------------------------------- 87 Fuel and Purchased Power: Fuel: Generation................................................ $ 8 Price..................................................... 6 Purchased power ............................................ (89) - -------------------------------------------------------------------------------- (75) - -------------------------------------------------------------------------------- Change in electric margin $ 12 - -------------------------------------------------------------------------------- Electric margins increased $12 million in the first three months of 2002 compared to the year-ago quarter. Revenues were favorably impacted in 2002 by the lack of estimated credits to Missouri electric customers (see Note 2 - "Regulatory Matters" to the financial statements). We also experienced growth in electric revenues due to the expansion of our weather-normalized native load, sales of SO2 allowances and an 80% increase in interchange sales. However, these increased interchange revenues were more than offset by the related increase in purchased power, resulting in lower margins than 2001. The increases in revenues were also partially offset by decreases in weather-sensitive residential and commercial sales caused by the milder winter weather referenced above, and lower industrial sales resulting from the continued soft economy in our service territory. Interchange revenues for the first quarter of 2002 included sales to related parties of $20 million, compared to $28 million in the first quarter of 2001. Fuel and purchased power costs for the first quarter of 2002 included purchases of $27 million from related parties under joint dispatch and other agreements, compared to $23 million for the first quarter of 2001. See Note 3 - "Related Party Transactions" to the financial statements. Gas Operations Our gas revenues decreased $19 million, and our gas costs decreased $14 million, in first quarter of 2002 as compared to the year-ago quarter primarily due to reduced sales of 9% caused by the milder winter weather and lower natural gas prices. As a result, our gas margins decreased by $5 million in the first quarter of 2002 as compared to the same period a year ago. Other Operating Expenses Other operating expenses in the first quarter of 2002 were comparable to the year-ago period. Ameren Services and AmerenEnergy provided services to us for the three months ended March 31, 2002 of approximately $48 million (2001 - $47 million) that were included in Other Operating Expenses. See Note 3 - "Related Party Transactions" to the financial statements. Maintenance expenses decreased $3 million in the first quarter of 2002 compared to the year-ago period, primarily due to decreased coal power plant maintenance, partially offset by higher tree-trimming expenses, which were accelerated, in part, to take advantage of mild weather. Depreciation and amortization expenses increased $3 million in the first quarter of 2002 compared to the year-ago period, primarily due to an increase in depreciable property related to the investment in our coal electric generating plants. 13 Taxes Income tax expense decreased $3 million in the first quarter of 2002, compared to the year-ago period, primarily due to a lower effective tax rate. Other tax expense increased $2 million in the first quarter of 2002, compared to the year-ago period, primarily due to higher Missouri property tax assessments and higher gross receipts taxes resulting from increased electric sales. Other Income and Deductions Other income and deductions decreased $4 million in the first quarter of 2002, compared to the year-ago period primarily due to lower intercompany interest earned on funds loaned to the regulated money pool resulting from lower average intercompany notes receivable balances. See Note 3 - "Related Party Transactions" to financial statements. Interest Interest expense decreased $3 million in the first quarter of 2002 compared to the year-ago period primarily due to lower interest rates on our variable rate environmental bonds ($2 million), as well as lower interest expense associated with a decreased balance under our nuclear fuel lease ($1 million). Rate and Regulatory Matters Missouri Electric From July 1, 1995 through June 30, 2001, we operated under experimental alternative regulation plans in Missouri that provided for the sharing of earnings with customers if our regulatory return on equity exceeded defined threshold levels. At March 31, 2002, we had an accrual representing the estimated credit that we expect to pay our Missouri electric customers of $40 million for the plan year ended June 30, 2001. In 2002, the Missouri Public Service Commission (MoPSC) Staff and the Missouri Office of Public Counsel (OPC) Staff filed testimony with the MoPSC on this matter. Combined, the MoPSC Staff and OPC Staff recommend that the credit to customers for the plan year ended June 30, 2001, should approximate $80 million. The MoPSC is not bound by their recommendations. To date, a procedural schedule and hearing dates on this matter have not been established by the MoPSC. At this time, we continue to believe that our accrual is adequate in all material respects. Following expiration of the experimental alternative regulation plan on June 30, 2001, the MoPSC Staff filed an excess earnings complaint against us. Based upon a January 2002 MoPSC order, on March 1, 2002, the MoPSC Staff filed a recommendation that we reduce our annual Missouri electric revenues by $246 million to $285 million. The MoPSC Staff's recommendation is based on a return to traditional cost of service ratemaking, a return on equity ranging from 8.91% to 9.91%, a reduction in our depreciation rates, and other cost of service adjustments. The MoPSC is not bound by the Staff's recommendation. On May 10, 2002, we filed rebuttal testimony in response to the MoPSC Staff's recommendation. In our testimony, we stated that a return to traditional cost of service ratemaking would result in an increase in our annual Missouri electric revenues by approximately $150 million. Our position is based on a 12.5% return on equity, higher depreciation rates and other adjustments. However, a key component of our testimony is our recommendation that a new alternative rate regulation plan (Alt Reg Plan) be adopted by the MoPSC. In our filing, we included a new Alt Reg Plan proposal. Key provisions of the Alt Reg Plan include the following: o A three-year plan from July 1, 2002 through June 30, 2005 which would require us to share earnings over certain regulatory return on equity (ROE) thresholds for the 12 months ending July 1 through June 30; o The proposed earnings sharing grid would require us to provide sharing credits of $17 million if our regulatory ROE is between 10.5% and 12.5%. Additional credits of 55% of our earnings between a regulatory ROE of 12.5% and 15% would be provided, 90% of earnings between a regulatory ROE of 15% and 16%, and 100% of any earnings above 16%. o An immediate one-time credit to customers bills of $15 million; o An annualized $15 million permanent rate reduction, retroactive to April 1, 2002; 14 o An immediate funding of $5 million to a low-income customer assistance program and $5 million to an economic development program; o A commitment of $1.5 billion to $1.75 billion in energy infrastructure investment from January 1, 2002 through June 30, 2005. Hearings for this case are scheduled to commence in mid-July 2002 and be completed in early August 2002. A final decision on this matter may not occur until the fourth quarter of 2002. In the interim, we plan to continue negotiations with all pertinent parties with the intent to continue with an incentive regulation plan. We cannot predict the outcome of the MoPSC's decision in this matter or its impact on our financial statements, results of operations or liquidity. However, the impact could be material. LIQUIDITY AND CAPITAL RESOURCES Operating Our cash flows provided by operating activities decreased $44 million to $85 million in the first quarter of 2002 compared to the year-ago period, primarily due to changes in working capital requirements resulting from a decrease in accounts and wages payable utilizing cash received from the decrease in receivables. These decreases were partially offset by increased earnings. Our tariff-based gross margins continue to be our principal source of cash from operating activities. Our diversified retail customer mix of residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. We plan to utilize short-term debt to support normal operations and other temporary capital requirements. AmerenUE is authorized by the SEC under PUHCA to have up to $1 billion of short-term unsecured debt instruments outstanding at any one time. Short-term borrowings typically consist of commercial paper (maturities generally within 1 to 45 days). We have several bank credit agreements expiring in 2002 that support our commercial paper program totaling $430 million. At March 31, 2002, all of these bank credit agreements were unused and available. Ameren expects to replace these bank credit agreements prior to their maturity. We also have the ability to borrow up to approximately $425 million from Ameren or from AmerenCIPS, through a regulated money pool agreement. The total amount available to us at any given time from the regulated money pool is reduced by the amount of borrowings by AmerenCIPS or Ameren Services, but increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds or the availability of other external borrowing sources. AmerenUE, AmerenCIPS and Ameren Services rely on the regulated money pool to coordinate and provide for certain short-term cash and working capital requirements. Ameren Services administers the regulated money pool. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. For the three months ended March 31, 2002, the average interest rate for the regulated money pool was 1.79% (2001 - 5.50%). As of March 31, 2002, we had outstanding intercompany payables of $192 million and at least $357 million available through the regulated money pool. At December 31, 2001, we had outstanding intercompany receivables of $84 million through the regulated money pool. We also have a lease agreement that provides for the financing of nuclear fuel. At March 31, 2002, the maximum amount that could be financed under the agreement was $120 million, of which $67 million was utilized. Our short-term financial agreements include customary default provisions that could impact the continued availability of credit or result in the acceleration of repayment. These events include bankruptcy, defaults in payment of other indebtedness, certain judgments that are not paid or insured, or failure to meet or maintain covenants. At March 31, 2002, we were in compliance with these provisions. Investing Our net cash used in investing activities was $19 million in the first quarter of 2002 compared to $76 million in the first quarter of 2001. In the first quarter of 2002, construction expenditures were $101 million (2001 - $89 million), primarily related to various upgrades at our coal power plants and further construction of combustion turbine generating units. Our capital expenditures are expected to approximate 15 $500 million in 2002. Also, during the first quarter of 2002, AmerenUE was repaid $84 million (2001 - $18 million) from the regulated money pool. Financing Our cash flows used in financing activities were $69 million in the first quarter of 2002 compared to $48 million in the year-ago period. Our principal financing activities for the period included the redemption of short-term debt and the payment of dividends, partially offset by the issuance of intercompany notes payable. In May 2002, we filed a shelf registration statement with the SEC on Form S-3 that upon its effectiveness will allow the offering from time to time of up to $750 million of various forms of long-term debt and trust preferred securities to refinance existing debt and for general corporate purposes, including the repayment of short-term debt incurred to finance construction expenditures and other working capital needs. This registration has not yet been declared effective by the SEC. In the ordinary course of business, we evaluate several strategies to enhance our financial position, earnings, and liquidity. These strategies may include potential acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives in order to increase shareholder value. We are unable to predict which, if any, of these initiatives will be executed, as well as the impact these initiatives may have on our future financial position, results of operations or liquidity. Electric Industry Restructuring Illinois See Note 2 - "Rate and Regulatory Matters" to the financial statements. Federal - Midwest ISO and Alliance RTO See Note 2 - "Rate and Regulatory Matters" to the financial statements. ACCOUNTING MATTERS Critical Accounting Policies Preparation of the financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. Our application of these policies involves judgments regarding many factors, which, in and of themselves, could materially impact the financial statements and disclosures. A future change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results. In the table below, we have outlined those accounting policies that we believe are most difficult, subjective or complex: Accounting Policy Judgments/Uncertainties Affecting Application - ----------------- --------------------------------------------- Regulatory Mechanisms & Cost Recovery We defer costs as regulatory o Regulatory environment, external assets in accordance with SFAS 71 regulatory decisions and requirements and make investments that we o Anticipated future regulatory assume we will be able to decisions and their impact collect in future rates. o Impact of deregulation and competition on ratemaking process and ability to recover costs Nuclear Plant Decommissioning Costs In our rates and earnings we assume o Estimates of future decommissioning the Department of Energy will o Availability of facilities for waste disposal develop a permanent storage site o Approved methods for waste disposal for spent nuclear fuel, the and decommissioning Callaway plant will have a useful o Useful lives of nuclear power plants life of 40 years and estimated costs to dismantle the plant are accurate. See Note 12 to our financial statements for the year ended December 31, 2001.
16 Environmental Costs We accrue for all known environmental o Extent of contamination contamination where remediation can o Responsible party determination be reasonably estimated, but some of o Approved methods of cleanup our operations have existed for over o Present and future legislation 100 years and previous contamination governmental regulations and may be unknown to us. standards o Results of ongoing research and development regarding environmental impacts Unbilled Revenue At the end of each period, we o Projecting customer energy usage estimate, based on expected usage, o Estimating impacts of weather and the amount of revenue to record for other usage-affecting factors services that have been provided to for the unbilled period customers, but not billed. This period can be up to one month. Benefit Plan Accounting Based on actuarial calculations, we o Future rate of return on pension accrue costs of providing future and other plan assets employee benefits in accordance with o Interest rates used in valuing SFAS 87, 106 and 112. See Note 10 benefit obligation 106 and 112. See Note 10 to our o Healthcare cost trend rates financial statements for the year ended December 31, 2001. Derivative Financial Instruments We record all derivatives at their o Market conditions in the energy fair market value in accordance industry, especially the effects of with SFAS 133. The identification price volatility on contractual and classification of a derivative commodity commitments and the fair value of such derivative o Regulatory and political must be determined. See Note 4 to our environments and requirements financial statements for the year o Fair value estimations on longer ended December 31, 2001. term contracts Impact of Future Accounting Pronouncements See Note 1 - "Summary of Significant Accounting Policies" to the financial statements. ITEM 3. Quantitative and Qualitative Disclosures about Market Risk. Market risk represents the risk of changes in value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g. interest rates, etc.). The following discussion of Ameren's, including AmerenUE's, risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those projected in the "forward-looking" statements. Ameren manages market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren and our Company also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, and operational risk and are not represented in the following analysis. Ameren's risk management objective is to optimize its physical generating assets within prudent risk parameters. Risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers. 17 Interest Rate Risk We are exposed to market risk through changes in interest rates associated with our issuance of both long-term and short-term variable-rate debt, fixed-rate debt and commercial paper. We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates. Utilizing our debt outstanding at March 31, 2002, if interest rates increased by 1%, our annual interest expense would increase by approximately $5 million and net income would decrease by approximately $3 million. The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure. Fuel Price Risk Over 95% of the required 2002 supply of coal for our coal plants has been acquired at fixed prices. As such, we have minimal coal price risk for 2002. In addition, approximately 70% of our coal requirements through 2006 are covered by contracts. Fair Value of Contracts We utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause: o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory and under firm commitment; and o actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays. The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internally forecast forward prices and modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, these transactions serve to reduce our price risk. The following summarizes changes in the fair value of all contracts marked to market during the first quarter of 2002: - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Fair value of contracts at January 1, 2002 $ (2) Contracts at January 1, 2002 which were realized or otherwise settled during first quarter of 2002 -- Changes in fair values attributable to changes in valuation techniques and assumptions -- Fair value of new contracts entered into during first quarter 2002 -- Other changes in fair value (2) - -------------------------------------------------------------------------------- Fair value of contracts outstanding at March 31, 2002 $ (4) - -------------------------------------------------------------------------------- 18
Fair value of contracts as of March 31, 2002 were as follows: - ---------------------------------------------------------------------------------------------------------- Maturity Maturity in less than Maturity Maturity excess of 5 Total fair Sources of fair value 1 year 1-3 years 4-5 years years value (a) - ---------------------------------------------------------------------------------------------------------- Prices actively quoted $ -- $ -- $ -- $ -- $ -- Prices provided by other external sources (b) (2) -- -- -- (2) Prices based on models and other valuation methods (c) (3) 2 (1) -- (2) - ----------------------------------------------------------------------------------------------------------- Total $ (5) $ 2 $ (1) $ -- $ (4) - ----------------------------------------------------------------------------------------------------------- (a) Nearly 100% of contracts were with investment-grade rated counterparties. (b) Principally power forward hedges valued based on NYMEX prices for over-the-counter contracts. (c) Principally coal and SO2 options valued based on a Black-Scholes model that includes information from external sources and our estimates.
SAFE HARBOR STATEMENT Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in the Annual Report on Form 10-K for the year ended December 31, 2001, and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: o the effects of our pending excess earnings complaint case and other regulatory actions, including changes in regulatory policy; o changes in laws and other governmental actions, including monetary and fiscal policies; o the impact on us of current regulations related to the opportunity for customers to choose alternative energy suppliers in Illinois; o the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels; o the effects of participation in a FERC-approved Regional Transmission Organization (RTO), including activities associated with the Midwest Independent System Operator and the Alliance RTO; o availability and future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial and derivative instruments and volatility of changes in market prices; o average rates for electricity in the Midwest; o business and economic conditions; o the impact of the adoption of new accounting standards; o interest rates and the availability of capital; o actions of rating agencies and the effects of such actions; o weather conditions; o generation plant construction, installation and performance; o the effects of strategic initiatives, including acquisitions and divestitures; o operation of nuclear power facilities and decommissioning costs; o the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; o future wages and employee benefits costs; o competition from other generating facilities including new facilities that may be developed in the future; o delays in receipt of regulatory approvals for the acquisition of CILCORP or unexpected adverse conditions or terms of those approvals; o difficulties in integrating CILCO with Ameren's other businesses; o changes in the coal markets, environmental laws or regulations or other factors adversely impacting synergy assumptions in connection with the CILCORP acquisition; 19 o disruptions of the capital markets or other events making AmerenUE's access to necessary capital more difficult or costly; o cost and availability of transmission capacity for the energy generated by our generating facilities or required to satisfy energy sales made by AmerenUE; and o legal and administrative proceedings. 20 PART II - OTHER INFORMATION ITEM 1. Legal Proceedings. Reference is made to Item 3. Legal Proceedings in Part I of our Annual Report on Form 10-K for the year ended December 31, 2001 for a discussion of a number of lawsuits that name our affiliate, Central Illinois Public Service Company operating as AmerenCIPS, our parent, Ameren Corporation, and us (which we refer to as the Ameren companies), along with numerous other parties, as defendants that have been filed by plaintiffs claiming varying degrees of injury from asbestos exposure. With respect to nine of those lawsuits, the Ameren companies have reached settlements with the plaintiffs for monetary amounts not material to the Ameren companies and in three cases, the Ameren companies have been voluntarily dismissed. Twenty-two additional lawsuits claiming injury from asbestos exposure have been filed against the Ameren companies since year-end 2001. These lawsuits, like the previous cases, were mostly filed in the Circuit Court of Madison County, Illinois, involve a large number of total defendants (over one hundred in many cases) and seek unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants. Currently, thirty asbestos-related lawsuits are pending against the Ameren companies. We believe that the final disposition of these proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. ITEM 6. Exhibits and Reports on Form 8-K. (a) Exhibits Incorporated by Reference. 10.1 - Power Sales Agreement between AmerenEnergy Marketing Company and AmerenUE dated March 20, 2002 (March 31, 2002 AmerenEnergy Generating Company Form 10-Q, Exhibit 10.1). (b) Reports on Form 8-K. AmerenUE filed a report on Form 8-K dated January 7, 2002 incorporating a press release issued by Ameren Corporation relating to the earnings complaint case filed by the Missouri Public Service Commission staff against AmerenUE and announcing a revision to Ameren Corporation's 2001 earnings estimate. Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-14756. Reports of Central Illinois Public Service Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-3672. Reports of AmerenEnergy Generating Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 333-56594. 21 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. UNION ELECTRIC COMPANY (Registrant) By /s/ Martin J. Lyons ----------------------- Martin J. Lyons Controller (Principal Accounting Officer) Date: May 15, 2002 22 -----END PRIVACY-ENHANCED MESSAGE-----