10-Q 1 ue10-q033103.txt UE'S 2003 1Q 10-Q 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, 2003 [ ] 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 ( ). Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ( ). No (X). Shares outstanding of the registrant's common stock as of May 14, 2003: Common Stock, $5 par value, held by Ameren Corporation (parent company of the registrant) - 102,123,834.
UNION ELECTRIC COMPANY TABLE OF CONTENTS Page ---- PART I Financial Information ITEM 1. Financial Statements (Unaudited) Consolidated Balance Sheet at March 31, 2003 and December 31, 2002................................... 2 Consolidated Statement of Income for the three months ended March 31, 2003 and 2002.................. 3 Consolidated Statement of Cash Flows for the three months ended March 31, 2003 and 2002.............. 4 Consolidated Statement of Common Stockholder's Equity for the three months ended March 31, 2003 and 2002............................................................................................. 5 Notes to Consolidated Financial Statements........................................................... 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 14 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk........................................... 24 ITEM 4. Controls and Procedures.............................................................................. 26 PART II Other Information ITEM 1. Legal Proceedings.................................................................................... 28 ITEM 6. Exhibits and Reports on Form 8-K..................................................................... 28 SIGNATURE......................................................................................................... 30 CERTIFICATIONS.................................................................................................... 30
This Form 10-Q contains "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Part I, Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations," under the heading "Forward-Looking Statements." Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects," and similar expressions. 1
PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements. UNION ELECTRIC COMPANY CONSOLIDATED BALANCE SHEET (Unaudited, in millions, except per share amounts) March 31, December 31, 2003 2002 ----------- ------------ ASSETS: Property and plant, net $ 6,093 $ 5,991 Investments and other assets: Nuclear decommissioning trust fund 172 172 Other assets 238 235 ----------- ------------ Total investments and other assets 410 407 ----------- ------------ Current assets: Cash and cash equivalents 118 9 Accounts receivable - trade (less allowance for doubtful accounts of $5 and $6, respectively) 171 171 Unbilled revenue 89 101 Miscellaneous accounts and notes receivable 54 49 Materials and supplies, at average cost 147 162 Other current assets 23 26 ----------- ------------ Total current assets 602 518 ----------- ------------ Regulatory assets 776 659 ----------- ------------ Total Assets $ 7,881 $ 7,575 =========== ============ 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 1,462 1,477 Accumulated other comprehensive income (59) (58) ----------- ------------ Total common stockholder's equity 2,616 2,632 ----------- ------------ Preferred stock not subject to mandatory redemption 113 113 Long-term debt, net 1,862 1,687 ----------- ------------ Total capitalization 4,591 4,432 ----------- ------------ Current liabilities: Current maturities of long-term debt 135 130 Short-term debt - 250 Intercompany notes payable 332 15 Accounts and wages payable 155 348 Accumulated deferred income taxes 3 2 Taxes accrued 178 118 Other current liabilities 96 94 ----------- ------------ Total current liabilities 899 957 ----------- ------------ Accumulated deferred income taxes 1,320 1,344 Accumulated deferred investment tax credits 120 121 Regulatory liabilities 114 121 Asset retirement obligation 391 174 Accrued pension liabilities 261 252 Other deferred credits and liabilities 185 174 ----------- ------------ Total Capital and Liabilities $ 7,881 $ 7,575 =========== ============ See Notes to Consolidated Financial Statements.
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UNION ELECTRIC COMPANY CONSOLIDATED STATEMENT OF INCOME (Unaudited, in millions) Three Months Ended March 31, ------------------------------- 2003 2002 ------------- ------------- OPERATING REVENUES: Electric $ 555 $ 534 Gas 65 50 ------------- ------------- Total operating revenues 620 584 ------------- ------------- OPERATING EXPENSES: Fuel and purchased power 141 144 Gas 39 32 Other operations and maintenance 186 184 Depreciation and amortization 70 72 Income taxes 38 28 Other taxes 53 52 ------------- ------------- Total operating expenses 527 512 ------------- ------------- OPERATING INCOME 93 72 OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction - 1 Miscellaneous, net - Miscellaneous income 1 6 Miscellaneous expense (1) (2) Income taxes - (1) ------------- ------------- Total other income and (deductions) - 4 ------------- ------------- INTEREST CHARGES: Interest 26 27 Allowance for borrowed funds used during construction (1) (2) ------------- ------------- Net interest charges 25 25 ------------- ------------- NET INCOME 68 51 PREFERRED STOCK DIVIDENDS 1 2 ------------- ------------- NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 67 $ 49 ============= ============= See Notes to Consolidated Financial Statements.
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UNION ELECTRIC COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions) Three Months Ended March 31, ------------------------------ 2003 2002 ------------ ------------- Cash Flows From Operating: Net income $ 68 $ 51 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 70 72 Amortization of nuclear fuel 7 7 Amortization of debt issuance costs and premium/discounts 1 1 Allowance for funds used during construction (1) (3) Deferred income taxes, net (5) (4) Deferred investment tax credits, net (1) (2) Other (1) (2) Changes in assets and liabilities: Receivables, net 7 55 Materials and supplies 15 14 Accounts and wages payable (193) (170) Taxes accrued 60 54 Assets, other (9) (7) Liabilities, other 26 19 ------------ ------------- Net cash provided by operating activities 44 85 ------------ ------------- Cash Flows From Investing: Construction expenditures (101) (101) Allowance for funds used during construction 1 3 Nuclear fuel expenditures - (5) Intercompany notes receivable - 84 ------------ ------------- Net cash used in investing activities (100) (19) ------------ ------------- Cash Flows From Financing: Dividends on common stock (82) (76) Dividends on preferred stock (1) (2) Capital issuance costs (1) - Redemptions: Nuclear fuel lease (2) - Short-term debt (250) (186) Issuances: Nuclear fuel lease - 3 Long-term debt 184 - Intercompany notes payable 317 192 ------------ ------------- Net cash provided by (used in) financing activities 165 (69) ------------ ------------- Net change in cash and cash equivalents 109 (3) Cash and cash equivalents at beginning of year 9 15 ------------ ------------- Cash and cash equivalents at end of period $ 118 $ 12 ============ ============= Cash paid during the periods: Interest $ 23 $ 19 Income taxes, net 7 4 See Notes to Consolidated Financial Statements.
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UNION ELECTRIC COMPANY CONSOLIDATED STATEMENT OF COMMON STOCKHOLDER'S EQUITY (Unaudited, in millions) Three Months Ended March 31, -------------------------------- 2003 2002 ------------- ------------- Common stock $ 511 $ 511 Other paid-in capital 702 702 Retained earnings Beginning balance 1,477 1,440 Net income 68 51 Common stock dividends (82) (76) Preferred stock dividends (1) (2) ------------- ------------- 1,462 1,413 ------------- ------------- Accumulated other comprehensive income Beginning balance - derivative financial instruments 4 1 Change in derivative financial instruments in current period (1) (2) ------------- ------------- 3 (1) ------------- ------------- Beginning balance - minimum pension liability (62) - Change in minimum pension liability in current period - - ------------- ------------- (62) - ------------- ------------- (59) (1) ------------- ------------- Total common stockholder's equity $2,616 $2,625 ============= ============= Comprehensive income, net of taxes Net income $ 68 $ 51 Unrealized net gain/(loss) on derivative hedging instruments, net of income taxes of $- and $-, respectively - 1 Reclassification adjustments for gains/(losses) included in net income, net of income taxes of $- and $(1), respectively (1) (3) ------------- ------------- Total comprehensive income, net of taxes $ 67 $ 49 ============= ============= See Notes to Consolidated Financial Statements.
5 UNION ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) March 31, 2003 NOTE 1 - Summary of Significant Accounting Policies General Union Electric Company, headquartered in St. Louis, Missouri, is a wholly-owned subsidiary of Ameren Corporation (Ameren) and operates as AmerenUE. Our principal business is the rate-regulated generation, transmission and distribution of electricity, and the rate-regulated distribution of natural gas to residential, commercial, industrial and wholesale users in Missouri and Illinois. Ameren is a public utility holding company registered with the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) and is also headquartered in St. Louis, Missouri. 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 subsidiaries and our affiliates are as follows: o Central Illinois Public Service Company, which operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP), which operates a rate-regulated electric transmission and distribution business, an electric generation business, and a rate-regulated natural gas distribution business in Illinois as AmerenCILCO. Ameren completed its acquisition of CILCORP on January 31, 2003. o AmerenEnergy Resources Company (Resources Company), which consists of non rate-regulated operations. Subsidiaries include AmerenEnergy Generating Company (Generating Company), which operates non rate-regulated electric generation in Missouri and Illinois, AmerenEnergy Marketing Company (Marketing Company), which markets power for periods over one year, AmerenEnergy Fuels and Services Company, which procures fuel and manages the related risks for Ameren affiliated companies and AmerenEnergy Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric generation plant. On February 4, 2003, Ameren completed its acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) and renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC. o AmerenEnergy, Inc. (AmerenEnergy), 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 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. Resources Company also owns a 20% interest in EEI. o Ameren Services Company (Ameren Services), which provides shared support services to Ameren and its subsidiaries, including us. Charges are based upon the actual costs incurred by Ameren Services, as required by the PUHCA. When we refer to AmerenUE, our, we or us, we are referring to Union Electric Company and its subsidiary, Union Electric Development Corporation, on a consolidated basis. Union Electric Development Corporation owns and invests in civic and community development enterprises. In some cases, we are referring to our agents, Ameren Energy and Ameren Energy Fuels and Services Company. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated. The accounting policies of AmerenUE conform to generally accepted accounting principles in the United States (GAAP). Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our interim results. These statements should be read in conjunction with the financial statements and the notes thereto included in our 2002 Annual Report on Form 10-K. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates. Certain reclassifications have been made to prior years' financial statements to conform to 2003 reporting. 6 Accounting Changes and Other Matters Statement of Financial Accounting Standards (SFAS) No. 143 - "Accounting for Asset Retirement Obligations" We adopted the provisions of SFAS 143 on January 1, 2003. SFAS 143 requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value. Upon adoption of this standard on January 1, 2003, we recognized additional asset retirement obligations of approximately $213 million and a net increase in net property and plant of approximately $76 million related primarily to the Callaway nuclear decommissioning costs and retirement costs for a river structure. The difference between the net asset and the liability recorded upon adoption of SFAS 143 related to rate-regulated assets was recorded as an additional regulatory asset of approximately $136 million because we expect to continue to recover in electric rates the cost of Callaway nuclear decommissioning and other costs of removal. These asset retirement obligations and associated assets are in addition to assets and liabilities of $174 million we previously recorded related to our future obligations and funds accumulated to decommission the Callaway nuclear plant. Asset retirement obligations also increased during the quarter due to accretion of $4 million. In addition to those obligations that were identified and valued, we determined that certain other asset retirement obligations exist. However, we are unable to estimate the fair value of those obligations because the probability, timing or cash flows associated with the obligations are indeterminable. We do not believe that these obligations, when incurred, will have a material adverse impact on our financial position, results of operations or liquidity. Historically, we have included an estimated cost of dismantling and removing plant from service upon retirement. Because these estimated costs of removal have been included in the cost of service upon which our present utility rates are based, and with the expectation that this practice will continue in the jurisdictions in which we operate, adoption of SFAS 143 did not result in any change in the deprecation accounting practices of our rate-regulated operations. We have estimated future removal costs embedded in accumulated depreciation related to rate-regulated plant assets were approximately $534 million at March 31, 2003. Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10 In the quarters ended September 30, 2002 and December 31, 2002, we adopted the provisions of EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," that require revenues and costs associated with certain energy contracts to be shown on a net basis in the income statement. Prior to adopting EITF 02-3 and the rescission of EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," our accounting practice was to present all settled energy purchase or sale contracts within our power risk management program on a gross basis in Operating Revenues - Electric and in Operating Expenses - Fuel and Purchased Power. This meant that revenues were recorded for the notional amount of the power sales contracts with a corresponding charge to income for the costs of the energy that was generated, or for the notional amount of a purchased power contract. In October 2002, the EITF reached a consensus to rescind EITF 98-10. The effective date for the full rescission of EITF 98-10 was for fiscal periods beginning after December 15, 2002, with early adoption permitted. In addition, the EITF reached a consensus in October 2002 that all SFAS No. 133 ("Accounting for Derivative Instruments and Hedging Activities") trading derivatives (subsequent to the rescission of EITF 98-10) should be shown net in the income statement, whether or not physically settled. This consensus applies to all energy and non-energy related trading derivatives that meet the definition of a derivative pursuant to SFAS 133. We have adopted and applied this guidance to 2002 and 2001, which had no impact on previously reported earnings or stockholder's equity. The operating revenues and costs netted for the three months ended March 31, 2002 were $150 million, which reduced interchange revenues and 7 purchased power costs by equal amounts. The adoption of EITF 02-3, the rescission of EITF 98-10 and the related transition guidance resulted in netting of energy contracts and lowered our reported revenues and costs with no impact on earnings. FASB Interpretation No. (FIN) 45 - "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" FIN 45 was issued in November 2002 and requires that upon issuance of certain guarantees, a guarantor must recognize a liability for the fair value of the obligation assumed under the guarantee. These recognition provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. FIN 45 also requires additional disclosures by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002. Because we do not have such obligations, the recognition provisions of FIN 45 did not have any effect on our financial position, results of operations or liquidity in the first quarter of 2003. SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" In April 2003, SFAS 149 was issued. SFAS 149 clarifies under what circumstances a contract with initial net investment meets the characteristic of a derivative as discussed in SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 149 is effective for hedging relationships designated and contracts entered into or modified after June 30, 2003. At this time, we are assessing the impact of SFAS 149 on our financial position, results of operations and liquidity upon adoption. Revenue We accrue an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period. Interchange revenues included in Operating Revenues - Electric were $102 million for the three months ended March 31, 2003 (2002 - $78 million). Purchased Power Purchased power included in Operating Expenses - Fuel and Purchased Power was $45 million for the three months ended March 31, 2003 (2002 - $65 million). Excise Taxes Excise taxes on Missouri electric and gas, and Illinois gas customer bills are imposed on us and are recorded gross in Operating Revenues and Other Taxes. Excise taxes recorded in Operating Revenues and Other Taxes for the three months ended March 31, 2003 were $23 million (2002 - $22 million). Excise taxes applicable to Illinois electric customer bills are imposed on the consumer and are recorded as tax collections payable and included in Taxes Accrued on the Consolidated Balance Sheet. NOTE 2 - Rate and Regulatory Matters Intercompany Purchase of Electric Generating Facilities As a part of the settlement of the Missouri electric rate case in 2002, we committed to making certain infrastructure investments from January 1, 2002 through June 30, 2006. The requirements are expected to be satisfied in part by the proposed purchase at net book value (approximately $260 million) by us of approximately 550 megawatts of combustion turbine generating units at Pinckneyville and Kinmundy, Illinois from Generating Company, which is subject to receipt of necessary regulatory approvals. Approval by the Missouri Public Service Commission (MoPSC) is not required in order for this purchase to occur. However, the MoPSC has jurisdiction over our ability to recover the cost of the purchased generating facilities from our electric customers in our rates. As part of the settlement of the Missouri electric rate case in 2002, we are subject to a rate moratorium providing for no changes in electric rates before June 30, 2006, subject to certain statutory and other exceptions. 8 In February 2003, we sought approval from the Federal Energy Regulatory Commission (FERC) and the Illinois Commerce Commission (ICC) to purchase the 550 megawatts from Generating Company. Several independent power producers have objected to our request at the FERC based on a claim that the purchase may harm competition for the sale of electricity at wholesale. In April 2003, NRG Energy Inc. (NRG) and some of its affiliates, filed testimony contending that NRG's 640 megawatt generating facility at Vandalia, Missouri, known as the Audrain Facility, was a better resource for us to acquire as compared to the Kinmundy and Pinckneyville combustion turbine generating units. In addition, in April 2003, in the ICC proceeding, the ICC Staff filed testimony which expressed concerns about the purchase as to whether it is the least cost resource for us and recommended that the ICC deny approval of the purchase. We will have an opportunity to file testimony responding to the recommendations of the ICC Staff and NRG. On May 5, 2003, the FERC issued an order which set for hearing the effect of the proposed purchase on competition in wholesale electric markets. We will have an opportunity to file testimony addressing this issue at the hearing to be scheduled. We can not predict the ultimate outcome of these proceedings or the timing of the decisions of the FERC and the ICC. Affiliate Rules On April 22, 2003, the Missouri Supreme Court issued an opinion upholding the adoption of affiliate rules by the MoPSC for Missouri's gas and electric utilities. We had objected to the Missouri asymmetric pricing provisions contained in the rules. These provisions require that the utility pay the lower of cost or market when it is receiving services from an affiliate, and charge the higher of cost or market when it is providing services to an affiliate. In general, the rules are intended to prevent regulated utilities from subsidizing their affiliates' non rate-regulated operations. As a registered holding company under the PUHCA, Ameren and its affiliates are already subject to extensive regulation designed to prevent cross-subsidization. The asymmetric pricing provisions of the MoPSC affiliate rules are expected to impose additional administrative burdens on us. In May 2003, we filed with the Missouri Supreme Court a motion for reconsideration of its April 22 opinion. We do not expect that the rules would have a material adverse impact on our future financial position, cash flows or results of operations in the event that our motion is denied. Regional Transmission Organization Since April 2002, we and AmerenCIPS and subsidiaries of FirstEnergy Corporation and NiSource Inc. (collectively the GridAmerica Companies) have participated in a number of filings at the FERC in an effort to form GridAmerica LLC as an independent transmission company (ITC). On December 19, 2002, the FERC issued an order conditionally approving the formation and operation of GridAmerica as an ITC within the Midwest Independent System Operator (Midwest ISO), subject to further compliance filings. In response to the December 19, 2002 order, the GridAmerica Companies made three additional filings at the FERC. On January 31, 2003 the GridAmerica Companies filed a request for authorization to transfer functional control of certain transmission assets to GridAmerica. On February 18, 2003, the GridAmerica Companies filed revised agreements codifying the formation and operation of GridAmerica to reflect changes requested by the FERC in the December 19, 2002 order. On February 28, 2003, the GridAmerica Companies together with the Midwest ISO filed revisions to the Midwest ISO Open Access Transmission Tariff (OATT) to provide rates for service over the transmission facilities to be transferred to GridAmerica by the GridAmerica Companies. On April 30 2003, the FERC issued orders in response to the January 31, 2003 and February 28, 2003 filings. In its order regarding the GridAmerica Companies' request to transfer functional control of their transmission assets to GridAmerica, the FERC authorized the transfer. In response to the February 28, 2003 filing, the FERC accepted the amendments to the Midwest ISO OATT effective upon the commencement of service over the GridAmerica transmission facilities under the Midwest ISO OATT, suspended the proposed rates for a nominal period, subject to refund, and established hearing and settlement judge procedures to determine the justness and reasonableness of the proposed rate amendments to the Midwest ISO OATT. An order in response to the February 18, 2003 filing is still pending. Until the tariffs and other material terms of ours and AmerenCIPS' participation in GridAmerica, and GridAmerica's participation in the Midwest ISO, are finalized and approved by the FERC, we are unable to 9 predict the impact that on-going regional transmission organization developments will have on our financial position, results of operations or liquidity. Our participation in GridAmerica is subject to MoPSC approval. An order from the MoPSC is expected during 2003. Standard Market Design Notice of Proposed Rulemaking (NOPR) On July 31, 2002, the FERC issued a Standard Market Design NOPR. The NOPR proposes a number of changes to the way the current wholesale transmission service and energy markets are operated. Specifically, the NOPR calls for all jurisdictional transmission facilities to be placed under the control of an independent transmission provider (similar to an RTO), proposes a new transmission service tariff that provides a single form of transmission service for all users of the transmission system including bundled retail load, and proposes a new energy market and congestion management system that uses locational marginal pricing as its basis. On November 15, 2002, we filed our initial comments on the NOPR with the FERC expressing concern with the potential impact of the proposed rules in their current form on the cost and reliability of service to retail customers. We also proposed that certain modifications be made to the proposed rules in order to protect transmission owners from the possibility of trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies. We filed additional comments on the remaining sections of the NOPR during the first quarter of 2003. On April 28, 2003, the FERC issued a "white paper" reflecting comments received in response to the NOPR. More specifically, the white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service and will insure that existing bundled retail customers retain their existing transmission rights and retain rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule's implementation. Even though issuance of the final rule and its implementation schedule are still unknown, the Midwest ISO is already in the process of implementing a market design similar to the proposed market design in the NOPR. The Midwest ISO has targeted March 2004 as the start date for implementation. We are in the process of reviewing the FERC's white paper. Until the FERC issues a final rule, we are unable to predict the ultimate impact on our future financial position, results of operations or liquidity. Illinois Gas In November 2002, we filed a request with the ICC to increase annual rates for natural gas service by approximately $4 million. The ICC has until October 2003 to render a decision on this gas case; however, the ICC Staff has recommended an annual increase of approximately $2 million. Missouri Gas In May 2003, we expect to file a request with the MoPSC to increase annual rates for natural gas service. NOTE 3 - Related Party Transactions We have transactions in the normal course of business with our parent, Ameren, and its other subsidiaries. These transactions are primarily comprised of power purchases and sales, as well as other services received or rendered. Intercompany power purchases from joint dispatch and other agreements were approximately $27 million for the three months ended March 31, 2003 (2002 - $27 million). Intercompany power sales totaled $32 million for the three months ended March 31, 2003 (2002 - $20 million). Interchange revenues from outside sales of available generation through AmerenEnergy were $70 million for the three months ended March 31, 2003 (2002 - $54 million). Purchased power derived from AmerenEnergy was $17 million for the three months ended March 31, 2003 (2002 - $37 million). Support services provided by our affiliates, Ameren Services and AmerenEnergy, including wages, employee benefits and professional services are based on actual costs incurred. For the three months ended 10 March 31, 2003, support services provided by Ameren Services and AmerenEnergy included in Operating Expenses - Other Operations and Maintenance totaled $50 million (2002 - $48 million). As of March 31, 2003, intercompany receivables included in Miscellaneous Accounts and Notes Receivable were approximately $37 million (December 31, 2002 - $25 million). As of March 31, 2003, intercompany payables included in Accounts and Wages Payable totaled approximately $45 million (December 31, 2002 - $103 million). We have the ability to borrow from Ameren and AmerenCIPS through a utility money pool agreement. Ameren Services administers the utility money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary source of external funds for the utility money pool at March 31, 2003 was our commercial paper program. Through the utility money pool we can access committed credit facilities at Ameren and AmerenCIPS, which totaled $615 million at March 31, 2003. These facilities are in addition to our own $79 million in committed credit facilities. The total amount available to us at any given time from the utility money pool is reduced by the amount of borrowings by our affiliates, but increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds and the availability of other external borrowing sources. Surplus funds providing additional liquidity available to us through the utility money pool totaled $260 million at March 31, 2003. The availability of funds is also determined by funding requirement limits established by the PUHCA. We, along with AmerenCIPS and Ameren Services, rely on the utility money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the utility money pool. For the three months ended March 31, 2003, the average interest rate for the utility money pool was 1.32% (2002 - 1.79%). At March 31, 2003, we had outstanding intercompany payables of $332 million, sourced by internal funds through the utility money pool (December 31, 2002 - $15 million). On April 1, 2003, we entered into an additional 364-day committed credit facility totaling $75 million to be used for general corporate purposes, including support of commercial paper programs. This facility makes borrowings available at various interest rates based on LIBOR, agreed rates and other options. Ameren and AmerenCIPS can access this facility through the utility money pool. NOTE 4 - Derivative Financial Instruments As of March 31, 2003, we recorded the fair value of derivative financial instrument assets of $9 million in Other Assets and the fair value of derivative financial instrument liabilities of $3 million in Other Deferred Credits and Liabilities. Cash Flow Hedges The pretax net gain or loss on power forward derivative instruments, 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 Accumulated Other Comprehensive Income (OCI) due to transactions going to delivery or settlement, was approximately a $1 million loss for the three months ended March 31, 2003 (2002 - $1 million gain). As of March 31, 2003, we had hedged a portion of the electricity price exposure for the upcoming twelve-month period. The mark-to-market value accumulated in OCI for the effective portion of hedges of electricity price exposure was a net gain of approximately $1 million (less than $1 million, net of taxes). We also hold two call options for coal with two suppliers. These options to purchase coal expire October 2003 and July 2005. As of March 31, 2003, a mark-to-market gain of approximately $6 million ($4 million, net of taxes) associated with these options was included in OCI. The final value of the options will be recognized as a reduction in fuel costs as the hedged coal is burned. Other Derivatives We enter into option transactions to manage our positions in sulfur dioxide allowances, coal and electricity. Most of these transactions are treated as non-hedge transactions under SFAS 133. The net 11 change in the market value of these options is recorded as Miscellaneous, Net in the income statement. The net change in the market values of sulfur dioxide, coal and electricity options was a gain of $0.1 million for the three months ended March 31, 2003 (2002 - gain of $1 million). NOTE 5 - Property and Plant, Net Property and plant, net consisted of the following at March 31, 2003 and December 31, 2002: ================================================================================ March 31, December 31, 2003 2002 -------------------------------------------------------------------------------- Property and plant, at original cost: Electric $10,494 $10,294 Gas 271 268 Other 37 36 -------------------------------------------------------------------------------- 10,802 10,598 Less accumulated depreciation and amortization 5,088 4,968 -------------------------------------------------------------------------------- 5,714 5,630 Construction work in progress: Nuclear fuel in process 82 81 Other 297 280 -------------------------------------------------------------------------------- Property and plant, net $ 6,093 $5,991 -------------------------------------------------------------------------------- NOTE 6 - Debt Financings In August 2002, our shelf registration statement filed with the SEC on Form S-3 was declared effective. This statement authorized 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 preferred stock, and for general corporate purposes, including the repayment of short-term debt incurred to finance construction expenditures and other working capital needs. In March 2003, we issued, pursuant to the shelf registration, $184 million of 5.50% Senior Secured Notes due March 15, 2034. We received net proceeds after fees of $180 million, which, along with other funds, were used to redeem $104 million principal amount of outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption price of 103.61% of par, plus accrued interest, in April 2003, prior to maturity, and to repay short-term debt incurred to pay at maturity $75 million principal amount of 8.33% first mortgage bonds that were due in December 2002. In April 2003, we issued, pursuant to the shelf registration, $114 million of 4.75% Senior Secured Notes due April 1, 2015. We received net proceeds after fees of $113 million, which, along with other funds, were used to redeem $85 million principal amount of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce short-term money pool debt. We may sell all, or a portion of, the remaining registered securities under our shelf registration statement if warranted by market conditions and our capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder. At April 30, 2003, the amount remaining on the shelf registration statement was $279 million. At March 31, 2003, neither Ameren, nor any of its subsidiaries, including us, had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. At this time, we do not expect to engage in any significant off-balance sheet financing arrangements. Amortization of debt issuance costs and any premium or discounts for the three months ended March 31, 2003 were $1 million (2002 - $1 million) and were included in interest expense in the income statement. At March 31, 2003, Ameren and its subsidiaries, including us, were in compliance with their financial agreement provisions and covenants. 12 NOTE 7 - Miscellaneous, Net Miscellaneous, net for the three months ended March 31, 2003 and 2002 consisted of the following: ================================================================================ Three Months -------------------------------------------------------------------------------- 2003 2002 Miscellaneous income: Equity in earnings of subsidiaries $ 1 $ 1 Other - 5 -------------------------------------------------------------------------------- Total miscellaneous income $ 1 $ 6 ================================================================================ Miscellaneous expense: Other $ (1) $ (2) -------------------------------------------------------------------------------- Total miscellaneous expense $ (1) $ (2) ================================================================================ 13 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. OVERVIEW Union Electric Company, headquartered in St. Louis, Missouri, is a wholly-owned subsidiary of Ameren Corporation (Ameren) and operates as AmerenUE. Our principal business is the rate-regulated generation, transmission and distribution of electricity, and the rate-regulated distribution of natural gas to residential, commercial, industrial and wholesale users in Missouri and Illinois. Ameren is a public utility holding company registered with the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) and is also headquartered in St. Louis, Missouri. 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 subsidiaries and our affiliates are as follows: o Central Illinois Public Service Company, which operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP), which operates a rate-regulated electric transmission and distribution business, an electric generation business, and a rate-regulated natural gas distribution business in Illinois as AmerenCILCO. Ameren completed its acquisition of CILCORP on January 31, 2003. See Recent Developments for further information. o AmerenEnergy Resources Company (Resources Company), which consists of non rate-regulated operations. Subsidiaries include AmerenEnergy Generating Company (Generating Company), which operates non rate-regulated electric generation in Missouri and Illinois, AmerenEnergy Marketing Company (Marketing Company), which markets power for periods over one year, AmerenEnergy Fuels and Services Company, which procures fuel and manages the related risks for Ameren affiliated companies and AmerenEnergy Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric generation plant. On February 4, 2003, Ameren completed its acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) and renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Recent Developments for further information. o AmerenEnergy, Inc. (AmerenEnergy), 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 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. Resources Company also owns a 20% interest in EEI. o Ameren Services Company (Ameren Services), which provides shared support services to Ameren and its subsidiaries, including us. Charges are based upon the actual costs incurred by Ameren Services, as required by the 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, 2002. o The audited financial statements and related notes that appear in our Annual Report on Form 10-K for the period ended December 31, 2002. When we refer to AmerenUE, our, we or us, we are referring to Union Electric Company and its subsidiary, Union Electric Development Corporation on a consolidated basis. Union Electric Development Corporation owns and invests in civic and community development enterprises. In some cases, we are referring to our agents, Ameren Energy and Ameren Energy Fuels and Services Company. All tabular 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 directly 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, nuclear fuel, natural gas and oil 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 or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas utility businesses. In addition, our electric rates in 14 Missouri and Illinois are largely set through 2006. 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 plants, 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 Earnings Summary Our net income increased to $68 million in the first quarter of 2003 from $51 million in the first quarter of 2002. The increase was primarily due to favorable weather conditions in our service territory ($15 million, net of taxes), increased electric margin due to greater use of low-cost generating units to serve native customers ($2 million, net of taxes) and increased earnings from interchange sales ($17 million, net of taxes) due to approximately 90% higher power prices in the energy markets than the prior period. Weather-sensitive residential electric kilowatthour sales increased by 14%, commercial electric kilowatthour sales increased by 8% and gas sales increased by 7% in the first quarter of 2003 compared to the first quarter of 2002. Partially offsetting the benefit on net income of weather, interchange margin and generation availability in the first quarter of 2003 were higher employee benefit costs ($4 million, net of taxes) related to benefit plan performance and increasing healthcare costs, no sales of emission credits in the first quarter of 2003 ($8 million, net of taxes) and the impact of the 2002 settlement of the Missouri electric rate case ($4 million, net of taxes). Recent Developments Acquisitions On January 31, 2003, Ameren completed its acquisition of all of the outstanding common stock of CILCORP from The AES Corporation. CILCORP is the parent company of Peoria, Illinois-based Central Illinois Light Company, which operated as CILCO. With the acquisition, CILCO became an Ameren subsidiary, but remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, Ameren also completed its acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley), which indirectly owns a 40 megawatt, gas-fired electric generation plant. With the acquisition, Medina Valley, which was renamed as AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned subsidiary of Resources Company. The results of operations for CILCORP and AmerenEnergy Medina Valley Cogen (No. 4), LLC were included in Ameren's consolidated financial statements effective with the January and February 2003 acquisition dates. Our results of operations for the quarter ended March 31, 2003 were not impacted by these acquisitions. Ameren acquired CILCORP to complement its existing Illinois gas and electric operations. The purchase included CILCO's rate-regulated electric and natural gas businesses in Illinois serving approximately 200,000 and 205,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. CILCO's service territory is contiguous to Ameren's service territory. CILCO also has a non rate-regulated electric and gas marketing business principally focused in the Chicago, Illinois region. Finally, the purchase included approximately 1,200 megawatts of largely coal-fired generating capacity, most of which is expected to become non rate-regulated in 2003. The total purchase price was approximately $1.4 billion and included the assumption of CILCORP and Medina Valley debt and preferred stock at closing of $895 million and consideration of $488 million in cash, including related acquisition costs, net of cash acquired. The purchase price is subject to certain adjustments for working capital and other changes pending the finalization of CILCORP's closing balance sheet. The cash component of the purchase price came from Ameren's issuances in September 2002 of 8.05 million common shares and its issuance in early 2003 of an additional 6.325 million common shares which together generated aggregate net proceeds of $575 million. Debt Issuances In March 2003, we issued $184 million of 5.50% Senior Secured Notes due March 15, 2034. We received net proceeds after fees of $180 million, which, along with other funds, were used to redeem $104 million principal amount of outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption 15 price of 103.61% of par, plus accrued interest, in April 2003, prior to maturity, and to repay short-term debt incurred to pay at maturity $75 million principal amount of 8.33% first mortgage bonds due in December 2002. In April 2003, we issued $114 million of 4.75% Senior Secured Notes due April 1, 2015. We received net proceeds after fees of $113 million, which, along with other funds, were used to redeem $85 million principal amount of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce short-term money pool debt. Credit Ratings In April 2002, as a result of our then pending Missouri electric earnings complaint case and the CILCORP transaction and related assumption of debt, credit rating agencies placed Ameren's and its subsidiaries' debt under review. Following the completion of the acquisition of CILCORP in January 2003, Standard & Poor's lowered the ratings of Ameren, AmerenUE and AmerenCIPS and increased the ratings of Generating Company, CILCORP and AmerenCILCO. At the same time, Standard & Poor's changed the outlook assigned to all of Ameren's and its subsidiaries' ratings to stable. Moody's also lowered Ameren's and AmerenUE's ratings subsequent to the acquisition and changed the outlook on these ratings to stable. These actions were consistent with the actions the rating agencies disclosed they were considering following the announcement of the CILCORP acquisition. As of April 30, 2003, selected ratings by Moody's and Standard & Poor's were as follows: ================================================================================ Moody's Standard & Poor's -------------------------------------------------------------------------------- Ameren Corporation: Issuer/Corporate credit rating A3 A- Unsecured debt A3 BBB+ Commercial paper P-2 A-2 AmerenUE: Secured debt A1 A- Unsecured debt A2 BBB+ Commercial paper P-1 A-2 CILCORP: Unsecured debt Baa2 BBB+ AmerenCILCO: Secured debt A2 A- AmerenCIPS: Secured debt A1 A- Unsecured debt A2 BBB+ Generating Company: Unsecured debt A3/Baa2 A- ================================================================================ Any adverse change in our, Ameren's or its other subsidiaries' credit ratings may reduce our access to capital and/or increase the costs of borrowings resulting in a negative impact on earnings. A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. 16 Electric Operations The following table represents the favorable (unfavorable) variation on electric margins for the three months ended March 31, 2003 from the comparable period in 2002: ================================================================================ Three Months -------------------------------------------------------------------------------- Electric Revenues: Interchange revenues $ 24 Effect of weather (estimate) 21 Rate reductions (11) Growth and other (estimate) (13) -------------------------------------------------------------------------------- Total variation in electric operating revenues 21 Fuel and Purchased Power: Fuel: Generation $ (16) Price - Generation efficiencies and other (1) Purchased power 20 -------------------------------------------------------------------------------- Total variation in fuel and purchased power 3 ================================================================================ Change in electric margin $ 24 ================================================================================ Electric margin increased $24 million for the three months ended March 31, 2003 compared to the same period in 2002. Increases in electric margin in the first quarter of 2003 were primarily attributable to increased interchange margins and higher native load customer demand resulting from colder winter weather. Residential kilowatthour sales increased 14% and commercial kilowatthour sales increased 8% in the first quarter of 2003. Interchange margins increased due to improved power prices in the energy markets and solid low-cost generation availability. Average power prices increased from approximately $22 per megawatthour in the first quarter of 2002 to approximately $42 per megawatthour in the first quarter of 2003. Partially offsetting the benefit of these increases in electric margin were an 8% decline in industrial sales in the first quarter of 2003 due to the continued soft economy, no sales of emission credits in the first quarter of 2003 (2002 - $13 million) and rate reductions in Missouri relating to a 2002 rate settlement ($11 million). Revenues will continue to be negatively affected by the settlement of the Missouri electric rate case, which requires the phase-in of $30 million of electric rate reductions effective April 1, 2003 and $30 million effective April 1, 2004. During 2002, we adopted the provisions of Emerging Issues Task Force (EITF) Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," that required revenues and costs associated with certain energy contracts to be shown on a net basis in the income statement. The operating revenues and costs netted for the three months ended March 31, 2002 were $150 million, which reduced interchange revenues and purchased power costs by equal amounts. See Note 1 - Summary of Significant Accounting Policies to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. Gas Operations Our gas margin increased $8 million in the first quarter of 2003, compared to the first quarter of 2002, with revenues increasing by $15 million and costs increasing by $7 million. The increase in margin was primarily due to increased customer demand resulting from colder winter weather and the prior year's warmer than normal conditions. Other Operating Expenses Other Operations and Maintenance Other operations and maintenance expenses increased $2 million in the first quarter of 2003, compared to the first quarter of 2002, primarily due to higher employee benefit costs related to increasing healthcare costs and the investment performance of employee benefit plans' assets ($7 million), partially offset by higher tree-trimming expenses in the first quarter of 2002, which were accelerated, in part, to take advantage of mild weather. 17 Ameren Services and AmerenEnergy provided services to us, including wages, employee benefits and professional services that were included in other operations and maintenance expenses. See Note 3 - Related Party Transactions to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. Depreciation and Amortization Depreciation and amortization expenses decreased $2 million in the first quarter of 2003 compared to the prior period. The decrease was primarily due to a reduction of depreciation rates based on an updated analysis of asset values, service lives and accumulated depreciation levels that was included in our 2002 Missouri electric rate case settlement ($5 million), partially offset by capital additions in 2002. Income Taxes Income tax expense increased $9 million in the first quarter of 2003, compared to the 2002 period, primarily due to higher pretax income. Other Taxes Other taxes expense increased $1 million in the first quarter of 2003, compared to the 2002 period, primarily due to an increase in gross receipts taxes related to increased native sales. Other Income and Deductions Other income and deductions (excluding income taxes) for the three months ended March 31, 2003 decreased $4 million, compared to the first quarter of 2002 primarily due to decreased gains on derivative contracts. See Note 7 - Miscellaneous, Net to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. Interest Interest expense decreased $1 million in the first quarter of 2003 compared to the 2002 period, primarily due to lower interest rates on new issuances of first mortgage bonds as compared to the issues redeemed. LIQUIDITY AND CAPITAL RESOURCES Operating Our cash flows provided by operating activities were $44 million for the first quarter of 2003, compared to $85 million for the same period in 2002. Cash provided by operations decreased in the first quarter of 2003, primarily as a result of the timing of receipts on receivables, net and payments on accounts and wages payable, partially offset by higher cash earnings from higher electric and gas margins. Our tariff-based gross margins continue to be our principal source of cash from operating activities. Our diversified retail customer mix of rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. In addition, we plan to utilize short-term debt to support normal operations and other temporary capital requirements. Investing Our net cash used in investing activities was $100 million in the first quarter of 2003 compared to $19 million for the same period in 2002. The increase over the prior year period was due to first quarter of 2002 receipt of $84 million previously invested in the utility money pool. In the first quarter of 2003, construction expenditures were $101 million (2002 - $101 million), primarily related to various upgrades at our power plants. Our capital expenditures are expected to approximate $485 million in 2003. We continually review our generation portfolio and expected electrical needs and, as a result, we could modify our plan for generation asset purchases, which could include the timing of when certain assets will 18 be added to, or removed from our portfolio, the type of generation asset technology that will be employed, or whether capacity may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material. Financing Our cash flows provided by financing activities totaled $165 million in the first quarter of 2003 compared to cash flows used in financing activities of $69 million in the first quarter of 2002. Our principal financing activities for the first quarter of 2003 included the issuances of intercompany notes payable and long-term debt, partially offset by the redemption of short-term debt and the payment of dividends. We are authorized by the SEC under the PUHCA to have up to $1 billion of short-term unsecured debt instruments outstanding at any time. Short-Term Debt and Liquidity Short-term debt consists of commercial paper, intercompany borrowings through Ameren's utility money pool and bank loans (maturities generally within 1 to 45 days). At March 31, 2003, Ameren and its subsidiaries had committed credit facilities, expiring at various dates between 2003 and 2005, totaling $694 million, excluding AmerenCILCO facilities of $60 million, EEI facilities of $45 million and our nuclear fuel lease facilities of $120 million. This amount includes $79 million of our committed credit facilities and $615 million of committed credit facilities at Ameren and AmerenCIPS. We access these combined facilities through Ameren's utility money pool arrangement. AmerenCIPS and Ameren Services may also borrow under this arrangement. These committed credit facilities are used to support our commercial paper program, under which no amounts were outstanding at March 31, 2003. At March 31, 2003, $694 million was unused and available under these committed credit facilities. Subject to the receipt of regulatory approval, which is being pursued, AmerenCILCO will participate in Ameren's utility money pool arrangement. Under this arrangement, AmerenCILCO will have access to up to $694 million of additional committed liquidity, subject to reduction based on the use by other utility money pool participants, but increased to the extent other pool participants have surplus cash balances, which may be used to fund pool needs. At March 31, 2003, AmerenCILCO had committed credit facilities, expiring at various dates during 2003, totaling $60 million, one of which totaling $25 million was subsequently renewed to 2004. On April 1, 2003, we entered into an additional 364-day committed credit facility totaling $75 million to be used for general corporate purposes, including support of commercial paper programs. This facility makes borrowings available at various interest rates based on LIBOR, agreed rates and other options. Ameren and AmerenCIPS can access this facility through the utility money pool. EEI also has two bank credit agreements totaling $45 million that expire in 2003. At March 31, 2003, $32 million was unused and available under these committed credit facilities. We also have a lease agreement that provides for the financing of nuclear fuel. At March 31, 2003, the maximum amount that could be financed under the agreement was $120 million. At March 31, 2003, $111 million was financed under the lease. In addition to committed credit facilities, a further source of liquidity for Ameren is available cash and cash equivalents. At March 31, 2003, Ameren had $260 million of cash, all of which was available for borrowings by us under the utility money pool. In the first quarter of 2003, Ameren paid a total of $488 million of cash on hand, including related acquisition costs, net of cash acquired, to acquire CILCORP and Medina Valley. We rely on access to short-term and long-term capital markets as a significant source of funding for capital requirements not satisfied by our operating cash flows. The inability by us to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty 19 in the capital markets such that our cost of capital would increase or our ability to access the capital markets would be adversely affected. Financial Agreement Provisions and Covenants Ameren's and our financial agreements include customary default or cross default provisions that could impact the continued availability of credit or result in the acceleration of repayment. Ameren's and its subsidiaries' committed credit facilities require the borrower to represent, in connection with any borrowing under the facility that no material adverse change has occurred since certain dates. None of our, Ameren's nor its other subsidiaries' financing arrangements contain credit rating triggers, except for three funded bank term loans at AmerenCILCO totaling $105 million at March 31, 2003. Ameren's and its subsidiaries' committed credit facilities include provisions related to the funded status of Ameren's pension plan. These provisions either require Ameren to meet minimum Employee Retirement Income Security Act of 1974 funding requirements or limit the unfunded liability status of the plan. Under the most restrictive of these provisions impacting Ameren facilities totaling $400 million, an event of default will result if the unfunded liability status (as defined in the underlying credit agreements) of Ameren's pension plan exceeds $300 million in the aggregate. Based on the most recent valuation report available to Ameren at December 31, 2002, which was based on January 2002 asset and liability valuations, the unfunded liability status (as defined) was $31 million. While an updated valuation report will not be available until the second half of 2003, Ameren believes that the unfunded liability status of its pension plans (as defined) could exceed $300 million based on the investment performance of the pension plan assets and interest rate changes since January 1, 2002. As a result, Ameren may need to renegotiate the facility provisions, terminate or replace the affected facilities, or fund any unfunded liability shortfall. Should Ameren elect to terminate these facilities, Ameren believes it would otherwise have sufficient liquidity to manage its short-term funding requirements. At March 31, 2003, Ameren and its subsidiaries, including us, were in compliance with their financial agreement provisions and covenants. Debt Financings See Note 6 - Debt Financings to our Consolidated Financial Statements under Item 1 of Part I of this report for information about financings during the first quarter of 2003. Off-Balance Sheet Arrangements At March 31, 2003, neither Ameren, nor any of its subsidiaries, including us, had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. At this time, we do not expect to engage in any significant off-balance sheet financing arrangements. OUTLOOK We believe there will be challenges to earnings in 2003 and beyond due to industry-wide trends and company-specific issues. The following are expected to put pressure on earnings in 2003 and beyond: o Weak economic conditions, which impacts native load demand; o Power prices in the Midwest will impact the amount of revenues we can generate by marketing any excess power into the interchange markets. Long-term power prices continue to be generally soft in the Midwest, despite the fact that short-term power prices have strengthened significantly from the prior year in the first quarter of 2003 due primarily to higher prices for natural gas; o A rate settlement approved in 2002 by the Missouri Public Service Commission that required electric rate reductions of $50 million on April 1, 2002 and $30 million on April 1, 2003 with an additional $30 million reduction required for April 1, 2004; o The adverse effects of rising employee benefit costs, higher insurance costs and increased security costs associated with additional measures we have taken, or may have to take, at our Callaway nuclear plant related to world events; and o An assumed return to more normal weather patterns relative to 2002. 20 In late 2002, we and Ameren announced the following actions to mitigate the effect of these challenges: o A voluntary retirement program that was accepted by approximately 550 Ameren employees, including approximately 230 of our employees and additional employees providing support functions to us through Ameren Services; o Modifications to retiree employee benefit plans to increase co-payments and limit our overall cost; o A wage freeze in 2003 for all management employees; o Suspension of operations at two 1940's-era Ameren generating plants, including our Venice, Illinois plant, to reduce operating costs; and o Reductions of 2003 expected capital expenditures. We are pursuing an annual gas rate increase of approximately $4 million in Illinois and we expect to file an annual gas rate increase in Missouri. Ameren is also considering additional actions, including modifications to active employee benefits, further staffing reductions and other initiatives. In early May 2003, our service territory experienced several severe storms that damaged parts of our transmission and distribution system. As a result, we expect to incur increased costs in the quarter ending June 30, 2003 for repairs required to our system. We are currently unable to estimate the impact on our future financial position, results of operations or cash flows. In the ordinary course of business, we and Ameren evaluate strategies to enhance our financial position, results of operations and liquidity. These strategies may include potential acquisitions, divestitures and opportunities to reduce costs or increase revenues and other strategic initiatives in order to increase Ameren's 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. REGULATORY MATTERS See Note 2 - Rate and Regulatory Matters to our Consolidated Financial Statements under Item 1 of Part I of this report for information. 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 Uncertainties Affecting Application ----------------- ----------------------------------- Regulatory Mechanisms and Cost Recovery We defer costs as regulatory assets in o Regulatory environment, external regulatory accordance with SFAS 71 and make decisions and requirements investments that we assume we will be able o Anticipated future regulatory decisions and to collect in future rates. their impact o Impact of deregulation and competition on ratemaking process and ability to recover costs
Basis for Judgment We determine that costs are recoverable based on previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. 21 Accounting Policy (Continued) Uncertainties Affecting Application (Continued) ----------------------------- ----------------------------------------------- Nuclear Plant Decommissioning Costs In our rates and earnings we assume the o Estimates of future decommissioning costs Department of Energy will develop a permanent o Availability of facilities for waste disposal storage site for spent nuclear fuel, the o Approved methods for waste disposal and Callaway nuclear plant will have a useful decommissioning life of 40 years and estimated costs of o Useful lives of nuclear power plants approximately $515 million to dismantle the plant are accurate. See Note 15 - Callaway Nuclear Plant to our Financial Statements in our 2002 Annual Report on Form 10-K. Basis for Judgment We determine that decommissioning costs are reasonable, or require adjustment, based on third party decommissioning studies that are completed every three years, the evaluation of our facilities by our engineers and the monitoring of industry trends. Environmental Costs We accrue for all known environmental o Extent of contamination contamination where remediation can be o Responsible party determination reasonably estimated, but some of our o Approved methods for cleanup operations have existed for over 100 years o Present and future legislation and governmental and previous contamination may be unknown to regulations and standards us. o Results of ongoing research and development regarding environmental impacts Basis for Judgment We determine the proper amounts to accrue for environmental contamination based on internal and third party estimates of clean-up costs in the context of current remediation standards and available technology. Unbilled Revenue At the end of each period, we estimate, based o Projecting customer energy usage on expected usage, the amount of revenue to o Estimating impacts of weather and other record for services that have been provided usage-affecting factors for the unbilled period to customers, but not billed. This period can be up to one month. Basis for Judgment We determine the proper amount of unbilled revenue to accrue each period based on the volume of energy delivered as valued by a model of billing cycles and historical usage rates and growth by customer class for our service area, as adjusted for the modeled impact of seasonal and weather variations based on historical results.
22 Accounting Policy (Continued) Uncertainties Affecting Application (Continued) ----------------------------- ----------------------------------------------- Benefit Plan Accounting Based on actuarial calculations, we accrue o Future rate of return on pension and other plan costs of providing future employee benefits assets in accordance with SFAS 87, 106 and 112. See o Interest rates used in valuing benefit Note 13 - Retirement Benefits to our obligations Financial Statements in our 2002 Annual o Healthcare cost trend rates Report on Form 10-K. o Timing of employee retirements Basis for Judgment We utilize a third party consultant to assist us in evaluating and recording the proper amount for future employee benefits. Our ultimate selection of the discount rate, healthcare trend rate and expected rate of return on pension assets is based on our review of available current, historical and projected rates, as applicable. Derivative Financial Instruments We record all derivatives at their fair o Market conditions in the energy industry, market value in accordance with SFAS 133. especially the effects of price volatility on The identification and classification of a contractual commodity commitments derivative and the fair value of such o Regulatory and political environments and derivative must be determined. We designate requirements certain derivatives as hedges of future cash o Fair value estimations on longer term contracts flows. See Note 4 - Derivative Financial o Complexity of financial instruments and Instruments to our Consolidated Financial accounting rules Statements under Item 1 of Part I of this o Effectiveness of our derivatives that have been report. designated as hedges Basis for Judgment We determine whether a transaction is a derivative versus a normal purchase or sale based on historical practice and our intention at the time we enter a transaction. We utilize actively quoted prices, prices provided by external sources and prices based on internal models and other valuation methods to determine the fair market value of derivative financial instruments.
Impact of Future Accounting Pronouncements See Note 1 - "Summary of Significant Accounting Policies" to our Consolidated Financial Statements under Item 1 of Part I of this report for information. 23 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 handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren and AmerenUE also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal and operational risks and are not represented in the following discussion. Ameren's risk management objective is to optimize its physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers. Interest Rate Risk We are exposed to market risk through changes in interest rates associated with 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, 2003, if interest rates increase by 1%, our annual interest expense would increase by approximately $9 million and net income would decrease by approximately $6 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. Credit Risk Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties in the transaction. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising our customer base. No customer represents greater than 10% of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. We analyze each counterparty's financial condition prior to entering into sales, forwards, swaps, futures or option contracts. We also establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program which involves daily exposure reporting to senior management, master trading and netting agreements, and credit support management such as letters of credit and parental guarantees. Equity Price Risk We, along with other subsidiaries of Ameren, are a participant in Ameren's defined benefit plans and postretirement benefit plans and are responsible for our proportional share of the costs. Ameren's costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Ameren's plan assets has been affected by declines in the equity market since 2000 for the pension and postretirement plans. As a result, at December 31, 2002, Ameren and its subsidiaries, including us, recognized an additional minimum pension liability as prescribed by SFAS No. 87, "Employers' Accounting for Pensions." The liability resulted in a reduction to equity as a result of a charge to Ameren's Accumulated Other Comprehensive Income (OCI) 24 of $102 million, net of taxes. Our portion of this charge to OCI was $62 million, net of taxes. The amount of the liability was the result of asset returns experienced through 2002, interest rates and Ameren's contributions to the plan during 2002. Neither Ameren's nor our portion of the minimum pension liability changed at March 31, 2003. In future years, the liability recorded, the costs reflected in net income or OCI, or cash contributions to the plans could increase materially without a recovery in equity markets in excess of our assumed return on plan assets. If the fair value of the plan assets were to grow and exceed the accumulated benefit obligations in the future, then the recorded liability would be reduced and a corresponding amount of equity would be restored in the Consolidated Balance Sheet. We also maintain trust funds, as required by the Nuclear Regulatory Commission and Missouri and Illinois state laws, to fund certain costs of nuclear decommissioning. By maintaining a portfolio that includes long-term equity investments, we seek to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in our portfolio are exposed to price fluctuations in equity markets and the fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor our portfolio by benchmarking the performance of our investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of our trusts to various investment options. Our exposure to equity price market risk is, in large part, mitigated due to the fact that we are currently allowed to recover decommissioning costs in our rates. 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 under the 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, we believe these transactions serve to reduce our price risk. See Note 4 - Derivative Financial Instruments to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. The following summarizes the favorable (unfavorable) changes in the fair value of all contracts marked-to-market during the first quarter of 2003: ------------------------------------------------------------------------------------------------------------- Fair value of contracts at beginning of period, net $ 6 Contracts which were realized or otherwise settled during the period (1) Changes in fair values attributable to changes in valuation techniques and assumptions - Fair value of new contracts entered into during the period - Other changes in fair value - ------------------------------------------------------------------------------------------------------------- Fair value of contracts outstanding at end of period, net $ 5 -------------------------------------------------------------------------------------------------------------
Maturities of contracts as of March 31, 2003 were as follows: ====================================================================================================================== Maturity Maturity less than Maturity Maturity in excess Total fair Sources of fair value 1 year 1-3 years 4-5 years of 5 years value (a) ---------------------------------------------------------------------------------------------------------------------- Prices actively quoted $ - $ - $ - $ - $ - Prices provided by other external sources (b) 1 - - - 1 Prices based on models and other valuation methods (c) 4 1 (1) - 4 ---------------------------------------------------------------------------------------------------------------------- Total $ 5 $ 1 $ (1) $ - $ 5 ----------------------------------------------------------------------------------------------------------------------
(a) Contracts of approximately 5% of the absolute fair value were with non-investment-grade rated counterparties. (b) Principally power forward values based on NYMEX prices for over-the-counter contracts. (c) Principally coal and sulfur dioxide options valued based on a Black-Scholes model that includes information from external sources and our estimates. 25 ITEM 4. Controls and Procedures. (a) Evaluation of Disclosure Controls and Procedures Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14 under the Securities Exchange act of 1934, as amended. Based upon that evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to AmerenUE which is required to be included in our periodic Securities and Exchange Commission filings. (b) Change in Internal Controls There have been no significant changes in our internal controls or in other factors which could significantly affect internal controls subsequent to the date we carried out our evaluation. FORWARD-LOOKING STATEMENTS 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 some 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 subsequent securities filings and others, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: o the effects of the stipulation and agreement relating to our Missouri electric 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 Federal Energy Regulatory Commission-approved Regional Transmission Organization, including activities associated with the Midwest System Independent Operator; o availability and future market prices for fuel for the production of electricity, such as coal and natural gas, purchased power, electricity and natural gas for distribution, including the use of financial and derivative instruments, the volatility of changes in market prices and the ability to recover increased costs; o average rates for electricity in the Midwest; o business and economic conditions; o the impact of the adoption of new accounting standards on the application of appropriate technical accounting rules and guidance; 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 operation of nuclear power facilities and decommissioning costs; o the effects of strategic initiatives, including acquisitions and divestitures; 26 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 benefit costs, including changes in returns of benefit plan assets; o disruptions of the capital markets or other events making Ameren's or our access to necessary capital more difficult or costly; o competition from other generating facilities, including new facilities that may be developed in the future; o cost and availability of transmission capacity for the energy generated by our generating facilities or required to satisfy our energy sales; and o legal and administrative proceedings. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 27 PART II. OTHER INFORMATION ITEM 1. Legal Proceedings Reference is made to Note 14 under Item 8 "Financial Statements and Supplementary Data" in Part II of our 2002 Annual Report on Form 10-K and Note 7 under Item 8 "Financial Statements and Supplementary Data" in Part II of the 2002 Annual Report on Form 10-K of our affiliates, CILCORP Inc. and Central Illinois Light Company, operating as AmerenCILCO, for a discussion of a number of lawsuits that name our affiliates, Central Illinois Public Service Company, operating as AmerenCIPS and AmerenCILCO, 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. Since the filing of the 2002 Annual Reports on Form 10-K, 25 additional lawsuits have been filed against AmerenCIPS and AmerenUE, but no additional lawsuits have been filed against AmerenCILCO. These lawsuits, like the previous cases, were mostly filed in the Circuit Court of Madison County, Illinois, involve a large number of total defendants and seek unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants. Also since the filing of the 2002 Annual Reports on Form 10-K, the Ameren companies have been voluntarily dismissed in 58 cases and have settled six cases. To date, a total of 152 asbestos-related lawsuits have been filed against the Ameren companies, of which 72 are pending, 16 have been settled and 64 have been dismissed. 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. Note 2 - Rate and Regulatory Matters to our Consolidated Financial Statements under Item 1 of Part I of this report contains additional information on legal and administrative proceedings which is incorporated by reference under this item. ITEM 6. Exhibits and Reports on Form 8-K. (a)(i) Exhibits filed herewith. 99.1 - Certificate of Chief Executive Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 - Certificate of Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. (a)(ii) Exhibits incorporated by reference. 10.1 - * 2003 Ameren Executive Incentive Plan (Ameren Corporation quarterly report on Form 10-Q for the quarter ended March 31, 2003, Exhibit 10.1) ---------------------------- * Management compensatory plan or arrangement. 28 (b) Reports on Form 8-K. Union Electric Company filed the following report on Form 8-K during the quarterly period ended March 31, 2003: ====================================================================== Items Reported Financial Date of Report Statements Filed ---------------------------------------------------------------------- March 10, 2003 5, 7 None Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-4756. 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. Reports of CILCORP Inc. on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 2-95569. Reports of Central Illinois Light Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-2732. 29 SIGNATURE 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 Vice President and Controller (Principal Accounting Officer) Date: May 14, 2003 CERTIFICATIONS I, Charles W. Mueller, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Union Electric Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and 30 CERTIFICATIONS (CONTINUED) b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 14, 2003 /s/ Charles W. Mueller ------------------------------------ Charles W. Mueller Chairman and Chief Executive Officer (Principal Executive Officer) I, Warner L. Baxter, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Union Electric Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and 31 CERTIFICATIONS (CONTINUED) b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 14, 2003 /s/ Warner L. Baxter ------------------------------ Warner L. Baxter Senior Vice President, Finance (Principal Financial Officer) 32