-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, FTCCp8Xek5dl02IVX8hJIEE/gT4OnEXJN5+O91ERZy1COaqdLHZCbs/OWtdgaOcx EHXlje9H2QS33FpCfqltaQ== 0000100826-02-000025.txt : 20020814 0000100826-02-000025.hdr.sgml : 20020814 20020814174738 ACCESSION NUMBER: 0000100826-02-000025 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020630 FILED AS OF DATE: 20020814 FILER: COMPANY DATA: COMPANY CONFORMED NAME: UNION ELECTRIC CO CENTRAL INDEX KEY: 0000100826 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 430559760 STATE OF INCORPORATION: MO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-02967 FILM NUMBER: 02737342 BUSINESS ADDRESS: STREET 1: 1901 CHOUTEAU AVENUE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166 BUSINESS PHONE: 3146213222 MAIL ADDRESS: STREET 1: 1901 CHOUTEAU AVENUE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166 10-Q 1 ue10q0602.txt UE'S 2ND QUARTER 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 June 30, 2002 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period From to Commission file number 1-2967. UNION ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Missouri 43-0559760 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1901 Chouteau Avenue, St. Louis, Missouri 63103 (Address of principal executive offices and Zip Code) Registrant's telephone number, including area code: (314) 621-3222 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . ------------ ------------ Shares outstanding of each of the registrant's classes of common stock as of August 9, 2002: Common Stock, $5 par value, held by Ameren Corporation (parent company of registrant) - 102,123,834 UNION ELECTRIC COMPANY INDEX Page ---- PART I. Financial Information ITEM 1. Financial Statements (Unaudited) Balance Sheet at June 30, 2002 and December 31, 2001......... 2 Statement of Income for the three and six months ended June 30, 2002 and 2001...................................... 3 Statement of Cash Flows for the six months ended June 30, 2002 and 2001...................................... 4 Statement of Common Stockholder's Equity for the three and six months ended June 30, 2002 and 2001................. 5 Notes to Financial Statements................................ 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................................... 13 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk... 21 PART II. Other Information ITEM 1. Legal Proceedings............................................ 24 ITEM 4. Submission of Matters to a Vote of Security Holders.......... 24 ITEM 5. Other Information............................................ 24 ITEM 6. Exhibits and Reports on Form 8-K............................. 25 SIGNATURE............................................................... 26 1
PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements UNION ELECTRIC COMPANY BALANCE SHEET (Unaudited, in millions, except per share amounts) June 30, December 31, 2002 2001 ---------- ------------- ASSETS: Property and plant, at original cost: Electric $ 10,165 $ 9,828 Gas 259 252 Other 37 37 ---------- ------------ 10,461 10,117 Less accumulated depreciation and amortization 4,913 4,802 ---------- ------------ 5,548 5,315 Construction work in progress: Nuclear fuel in process 114 97 Other 161 298 ---------- ------------ Total property and plant, net 5,823 5,710 ---------- ------------ Investments and other assets: Nuclear decommissioning trust fund 175 187 Other 96 75 ---------- ------------ Total investments and other assets 271 262 ---------- ------------ Current assets: Cash and cash equivalents 8 15 Accounts receivable - trade (less allowance for doubtful accounts of $9 and $7, respectively) 180 144 Unbilled revenue 166 90 Other accounts and notes receivable 24 73 Intercompany notes receivable - 84 Materials and supplies, at average cost - Fossil fuel 62 71 Other 86 85 Other 12 16 ---------- ------------ Total current assets 538 578 ---------- ------------ Regulatory assets: Deferred income taxes 579 604 Other 128 134 ---------- ------------ Total regulatory assets 707 738 ---------- ------------ Total Assets $ 7,339 $ 7,288 ========== ============ CAPITAL AND LIABILITIES: Capitalization: Common stock, $5 par value, 150.0 shares authorized - 102.1 shares outstanding $ 511 $ 511 Other paid-in capital, principally premium on common stock 702 702 Retained earnings 1,442 1,440 Accumulated other comprehensive income 1 1 ---------- ------------ Total common stockholder's equity 2,656 2,654 ---------- ------------ Preferred stock not subject to mandatory redemption 155 155 Long-term debt 1,599 1,599 ---------- ------------ Total capitalization 4,410 4,408 ---------- ------------ Current liabilities: Current maturities of long-term debt 98 92 Short-term debt - 186 Intercompany notes payable 260 - Accounts and wages payable 186 305 Accumulated deferred income taxes 35 35 Taxes accrued 186 104 Other 140 128 ---------- ------------ Total current liabilities 905 850 ---------- ------------ Accumulated deferred income taxes 1,291 1,326 Accumulated deferred investment tax credits 126 129 Regulatory liabilities 138 137 Other deferred credits and liabilities 469 438 ---------- ------------ Total Capital and Liabilities $ 7,339 $ 7,288 ========== ============ See Notes to Financial Statements.
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UNION ELECTRIC COMPANY STATEMENT OF INCOME (Unaudited, in millions) Three Months Ended Six Months Ended June 30, June 30, ---------------------- -------------------- 2002 2001 2002 2001 ---- ---- ---- ---- OPERATING REVENUES: Electric $ 732 $ 765 $ 1,416 $ 1,362 Gas 18 18 68 87 ------- ------- --------- --------- Total operating revenues 750 783 1,484 1,449 ------- ------- --------- --------- OPERATING EXPENSES: Operations Fuel and purchased power 210 261 504 480 Gas 10 11 42 57 Other 139 133 268 263 ------- ------- --------- --------- 359 405 814 800 Maintenance 68 101 123 159 Depreciation and amortization 69 70 141 139 Income taxes 53 48 81 79 Other taxes 55 53 107 103 ------- ------- --------- --------- Total operating expenses 604 677 1,266 1,280 ------- ------- --------- --------- OPERATING INCOME 146 106 218 169 OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction 1 3 2 4 Miscellaneous, net - Miscellaneous income 17 4 23 17 Miscellaneous expense 29) (3) (31) (7) Income taxes (1) 1 (2) (1) ------- ------- --------- --------- Total other income and (deductions) (12) 5 (8) 13 ------- ------- --------- --------- INTEREST CHARGES: Interest 27 31 54 61 Allowance for borrowed funds used during construction - (2) (2) (4) ------- ------- --------- --------- Net interest charges 27 29 52 57 ------- ------- --------- --------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 107 82 158 125 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES - - - (5) ------- ------- --------- --------- NET INCOME 107 82 158 120 PREFERRED STOCK DIVIDENDS 2 2 4 4 ------- ------- --------- --------- NET INCOME AFTER PREFERRED STOCK DIVIDENDS $ 105 $ 80 $ 154 $ 116 ======= ======= ========= ========= See Notes to Financial Statements.
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UNION ELECTRIC COMPANY STATEMENT OF CASH FLOWS (Unaudited, in millions) Six Months Ended June 30, ------------------------- 2002 2001 ---- ---- Cash Flows From Operating: Net income $ 158 $ 120 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle - 5 Depreciation and amortization 141 139 Amortization of nuclear fuel 16 12 Amortization of debt issuance costs and premium/discounts 2 2 Allowance for funds used during construction (4) (8) Deferred income taxes, net (9) 15 Deferred investment tax credits, net (3) (1) Other - (4) Changes in assets and liabilities: Receivables, net (63) (48) Materials and supplies 8 (17) Accounts and wages payable (119) (29) Taxes accrued 82 81 Assets, other (9) (8) Liabilities, other 43 (34) --------- --------- Net cash provided by operating activities 243 225 --------- --------- Cash Flows From Investing: Construction expenditures (246) (253) Allowance for funds used during construction 4 8 Nuclear fuel expenditures (16) (12) Intercompany notes receivable 84 78 --------- --------- Net cash used in investing activities (174) (179) --------- --------- Cash Flows From Financing: Dividends on common stock (152) (141) Dividends on preferred stock (4) (4) Redemptions: Nuclear fuel lease - (64) Short-term debt (186) - Issuances: Nuclear fuel lease 6 2 Long-term debt - 146 Intercompany notes payable 260 - --------- --------- Net cash used in financing activities (76) (61) --------- --------- Net change in cash and cash equivalents (7) (15) Cash and cash equivalents at beginning of year 15 20 --------- --------- Cash and cash equivalents at end of period $ 8 $ 5 ========= ========= Cash paid during the periods: Interest $ 48 $ 53 Income taxes, net 63 31 See Notes to Financial Statements.
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UNION ELECTRIC COMPANY STATEMENT OF COMMON STOCKHOLDER'S EQUITY (Unaudited, in millions) Three Months Ended Six Months Ended June 30, June 30, ---------------------------- ----------------------- 2002 2001 2002 2001 ---- ---- ---- ---- Common stock $ 511 $ 511 $ 511 $ 511 Other paid-in capital 702 702 702 702 Retained earnings Beginning balance 1,413 1,340 1,440 1,358 Net income 107 82 158 120 Common stock dividends (76) (87) (152) (141) Preferred stock dividends (2) (2) (4) (4) ----------- ----------- ---------- --------- 1,442 1,333 1,442 1,333 ----------- ----------- ---------- --------- Accumulated other comprehensive income Beginning balance (1) (2) 1 - Change in current period (see below) 2 (2) - (4) ----------- ----------- ---------- --------- 1 (4) 1 (4) ----------- ----------- ---------- --------- Total common stockholder's equity $ 2,656 $ 2,542 $2,656 2,542 =========== =========== ========== ========= Comprehensive income, net of taxes Net income $ 107 $ 82 $ 158 $ 120 Unrealized net gain/(loss) on derivative hedging instruments (net of income taxes of $1, $(2), $1 and $(1), respectively) 1 (3) 2 (2) Reclassification adjustments for gains/(losses) included in net income (net of income taxes of $ -, $1, $(1) and $4, respectively) 1 1 (2) 6 Cumulative effect of accounting change, net of income taxes of $(5) - - - (8) ----------- ----------- ---------- --------- Total comprehensive income, net of taxes $ 109 $ 80 $ 158 $ 116 =========== =========== ========== ========= See Notes to Financial Statements.
5 UNION ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS (UNAUDITED) June 30, 2002 NOTE 1 - Summary of Significant Accounting Policies Basis of Presentation Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of the interim results. These statements should be read in conjunction with the financial statements and the notes thereto included in our 2001 Annual Report on Form 10-K. When we refer to AmerenUE, our, we or us, we are referring to Union Electric Company. All dollar amounts are in millions, unless otherwise indicated. Accounting Changes In January 2001, we adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." The impact of that adoption resulted in a cumulative effect charge of $5 million after taxes to the income statement, and a cumulative effect adjustment of $8 million, after taxes, to Accumulated Other Comprehensive Income (OCI), which reduced common stockholder's equity. On January 1, 2002, we adopted SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business combinations to be accounted for under the purchase method of accounting, which requires one party in the transaction to be identified as the acquiring enterprise and for that party to allocate the purchase price to the assets and liabilities of the acquired enterprise based on fair market value. SFAS 142 requires goodwill and indefinite-lived intangible assets recorded in the financial statements to be tested for impairment at least annually, rather than amortized over a fixed period, with impairment losses recorded in the income statement. SFAS 141 and SFAS 142 did not have any effect on our financial position, results of operations or liquidity upon adoption. See Note 6 - "CILCORP Acquisition." In July 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations," was issued. SFAS 143 requires an entity to record a liability and corresponding asset representing the present value of legal obligations associated with the retirement of tangible, long-lived assets. SFAS 143 is effective for us on January 1, 2003. At this time, we are assessing the impact of SFAS 143 on our financial position, results of operations and liquidity upon adoption. However, as a result of this new standard we expect significant increases to our reported assets and liabilities, including those resulting from obligations associated with our Callaway nuclear plant's decommissioning costs and associated regulatory rate cost recovery. On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 144 retains the guidance related to calculating and recording impairment losses, but adds guidance on the accounting for discontinued operations, previously accounted for under Accounting Principles Board Opinion No. 30. We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared with the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. SFAS 144 did not have any effect on our financial position, results of operations or liquidity upon adoption. Historically, 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 - Operations - Fuel and Purchased Power in our income statement. This means that revenues were recorded for the notional amount of the power sale contracts with a corresponding charge to income for the cost of the energy that has been generated or for the notional amount of a purchased power contract. In June 2002, the Emerging Issues Task Force (or EITF) reached a consensus in Issue 02-03, "Accounting 6 for Contracts Involved in Energy Trading and Risk Management Activities," that certain energy contracts should be shown on a net basis in the income statement. The consensus on this issue is applicable to financial statements for periods ending after July 15, 2002, with a requirement to conform prior periods to this presentation. As a result of the EITF's accounting guidance and other factors that exist within our industry, beginning with the period ending September 30, 2002, we will change our accounting practice to present, on a net basis in our income statement, all contracts within our power risk management program that have been net settled. All prior periods included in our prospective financial statements will be reclassified to reflect this change in accounting practice. We are still in the process of evaluating the impact of this change to our income statement, but our revenues and operating expenses will be reduced in future periods with no impact on our earnings. See Note 4 - "Derivative Financial Instruments" for more information. Interchange Revenues Interchange revenues included in Operating Revenues - Electric were $140 million for the three months ended June 30, 2002 (2001 - $161 million) and $369 million for the six months ended June 30, 2002 (2001 - $324 million). Purchased Power Purchased power included in Operating Expenses, Operations - Fuel and Purchased Power was $131 million for the three months ended June 30, 2002 (2001 - - $184 million) and $346 million for the six months ended June 30, 2002 (2001 - $310 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 applicable to Illinois electric customer bills are imposed on the consumer and are recorded as tax collections payable. Excise taxes recorded in Operating Revenues and Other Taxes for the three months ended June 30, 2002 were $28 million (2001 - $25 million) and $49 million for the six-month period ended June 30, 2002 (2001 - $46 million). NOTE 2 - Rate and Regulatory Matters Missouri Electric From July 1, 1995 through June 30, 2001, we operated under experimental alternative regulation plans in Missouri that provided for the sharing of earnings with customers if our regulatory return on equity exceeded defined threshold levels. After our experimental alternative regulation plan for our Missouri retail electric customers expired, the Missouri Public Service Commission (MoPSC) Staff filed an excess earnings complaint against us with the MoPSC in July 2001. In March 2002, the MoPSC Staff filed a recommendation that we reduce our annual Missouri electric revenues by $246 million to $285 million. The MoPSC Staff's recommendation was based on a return to traditional cost of service ratemaking, a lowered return on equity, a reduction in our depreciation rates and other cost of service adjustments. In May 2002, we filed testimony supporting a rate increase of at least $150 million and proposed a new alternative regulation plan that included a rate decrease. On July 16, 2002, AmerenUE, the MoPSC Staff, and all of the other parties to the proceeding submitted to the MoPSC a stipulation and agreement resolving this case. On July 24, 2002, the MoPSC held a hearing on the stipulation and agreement. On July 25, 2002, the MoPSC approved the stipulation and agreement, and on August 4, 2002, it became effective. The stipulation and agreement includes the following principal features: o the phase-in of $110 million of electric rate reductions through April 2004, $50 million of which is retroactively effective as of April 1, 2002, $30 million of which will become effective on April 1, 2003, and $30 million of which will become effective on April 1, 2004, o a rate moratorium providing for no requests for changes in our electric rates as established by the stipulation and agreement before January 1, 2006 and no resulting changes in rates before June 30, 2006, subject to certain statutory and other exceptions, 7 o a commitment to contribute, as early as September 2002, $14 million to programs for low income energy assistance and weatherization, promotion of energy efficiency and economic development in our service territory, with additional payments of $3 million made annually on June 30, 2003 through June 30, 2006, o a commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at our nuclear power plant. The 700 megawatts of new generation includes 240 megawatts already added this year and may include the transfer at book value to us of generation assets from our non-regulated affiliates. The amount of energy infrastructure investments through June 2006 described in the stipulation and agreement is consistent with our previously-disclosed estimate of the construction expenditures we expect to make over the same time period, o an annual reduction in our depreciation rates by $20 million, retroactive to April 1, 2002, based on an updated analysis of asset values, service lives and accumulated depreciation levels, and o a one-time credit of $40 million to be paid to our Missouri retail electric customers as early as August 2002 for settlement of the final sharing period under the alternative regulation plan that expired June 30, 2001. At June 30, 2002, we had accrued $40 million in Current Liabilities - Other. In total, the stipulation and agreement is estimated to reduce 2002 net earnings by $32 million. Net earnings are expected to be reduced in 2002 due to the rate reduction ($26 million, net of taxes, including $8 million, net of taxes, in the quarter ended June 30, 2002), the expensing in the quarter ended June 30, 2002 of the entire obligation to fund certain programs ($15 million, net of taxes), offset, in part, by the reduction in depreciation expense ($9 million, net of taxes, including $3 million, net of taxes, in the quarter ended June 30, 2002). Net earnings were reduced by $20 million in the quarter ended June 30, 2002 due to the stipulation and agreement. We expect earnings to be reduced by $9 million in the third quarter of 2002 and $3 million in the fourth quarter of 2002. In order to satisfy our regulatory load requirements for 2001, we purchased, under a one year contract, 450 megawatts of capacity and energy from our affiliate, AmerenEnergy Marketing Company (Marketing Company) (the 2001 Marketing Company - AmerenUE agreement). This agreement was entered into through a competitive bidding process and reflected market-based rates. For 2002, we similarly entered into a one-year contract with Marketing Company for the purchase of 200 megawatts of capacity and energy (the 2002 Marketing Company - AmerenUE agreement). For the four summer months of 2002, we also entered into contracts with two other power suppliers for an aggregate 200 megawatts of additional capacity and energy. In May 2001, the MoPSC filed a complaint with the Securities and Exchange Commission (SEC) relating to the 2001 Marketing Company - AmerenUE agreement. The complaint requested an investigation into the contractual relationship between AmerenUE, Marketing Company and AmerenEnergy Generating Company (Generating Company), also our affiliate, in the context of the 2001 Marketing Company - AmerenUE agreement and requests that the SEC find that such relationship violates a provision of the Public Utility Holding Company Act of 1935 (or PUHCA), which requires state utility commission approval of power sales contracts between an electric utility company and an affiliated electric wholesale generator, like Generating Company. We believe that the MoPSC's approval of the power sales agreement under PUHCA is not required because Generating Company is not a party to the agreement. As a remedy, the MoPSC proposes that the SEC require us to contract directly with Generating Company and submit such contract to the MoPSC for review. On May 9, 2002, the MoPSC filed a similar complaint with the SEC relating to the 2002 Marketing Company - AmerenUE agreement. The SEC is investigating these matters. Also, with respect to the 2002 Marketing Company - AmerenUE agreement, on May 31, 2002, the Federal Energy Regulatory Commission (FERC) accepted the agreement, subject to refund, and scheduled the matter for a January 2003 hearing to assess the appropriateness of the rates charged. At this time, management is unable to predict the outcome of these proceedings or the ultimate impact on our future financial position, results of operations or liquidity. Illinois In December 1997, the Electric Service Customer Choice and Rate Relief Law of 1997 (the Illinois Law) was enacted providing for electric utility restructuring in Illinois. This legislation introduced competition into the retail supply of electric energy in Illinois. Illinois residential customers were offered choice in suppliers on May 1, 2002. Industrial and commercial customers were previously offered this choice. 8 The Illinois Law contained a provision freezing retail bundled electric rates through January 1, 2005. In 2002, legislation was passed and signed into law that extended the rate freeze period through January 1, 2007. The offering of choice to our industrial and commercial customers has not had a material adverse effect on our business and we do not expect the offering of choice to our residential customers, or the extension of the rate freeze, to have a material adverse effect on our business. Federal - Regional Transmission Organizations In December 1999, the FERC issued Order 2000, requiring all utilities, subject to FERC jurisdiction, to state their intentions for joining a regional transmission organization (RTO). RTOs are independent organizations that will functionally control the transmission assets of utilities in order to improve the wholesale power market. Since January 2001, we, along with several other utilities, were seeking approval from the FERC to participate in an RTO known as the Alliance RTO. We had previously been a member of the Midwest Independent System Operator (MISO) and recorded a pretax charge to earnings in 2000 of $17 million ($10 million after taxes) for an exit fee and other costs when we left that organization. We felt the for-profit Alliance RTO business model was superior to the not-for-profit MISO business model and provided us with a more equitable return on our transmission assets. In late 2001, the FERC issued an order that rejected the formation of the Alliance RTO and ordered the Alliance RTO companies and the MISO to discuss how the Alliance RTO business model could be accommodated within the MISO. On April 25, 2002, after the Alliance RTO and MISO failed to reach an agreement, and after a series of filings by the two parties with the FERC, the FERC issued a declaratory order setting forth the division of responsibilities between the MISO and National Grid (the managing member of the transmission company formed by the Alliance companies) and approved the rate design and the revenue distribution methodology proposed by the Alliance companies. However, the FERC denied a request by the Alliance companies and the National Grid to purchase certain services from the MISO at incremental cost rather than MISO's full tariff rates. The FERC also ordered the MISO to return the exit fee paid by AmerenUE to leave the MISO, provided AmerenUE returns to the MISO and agrees to pay its proportional share of the startup and ongoing operational expenses of the MISO. Moreover, the FERC required the Alliance companies to select the RTO in which they will participate within thirty days of the order. Since the April 2002 FERC order, we and our affiliate, Central Illinois Public Service Company (known as AmerenCIPS) made filings with the FERC indicating that we would return to the MISO and that membership would be through a new independent transmission company, GridAmerica LLC, that was agreed to be formed by AmerenUE and AmerenCIPS, along with subsidiaries of FirstEnergy Corporation and NiSource Inc. If the FERC approves the definitive agreements establishing GridAmerica, National Grid will serve as the managing member of GridAmerica and will manage the transmission assets of the three companies and participate in the MISO on behalf of GridAmerica. Other Alliance RTO companies announced their intentions to join the Pennsylvania - Jersey - Maryland (PJM) RTO. On July 25, 2002, the Ameren companies filed a motion with the FERC requesting that it condition the approval of the choices of other Illinois utilities to join the PJM RTO on MISO and PJM entering into an agreement addressing important reliability and rate-barrier issues. On July 31, 2002, the FERC issued an order accepting the formation of GridAmerica as an independent transmission company under the MISO subject to further compliance filings ordered by the FERC. The FERC also issued an order accepting the elections made by the other Illinois utilities to join the PJM RTO on the condition PJM and MISO immediately begin a process to address the reliability and rate-barrier issues raised by the Ameren companies and other market participants in previous filings. Until the reliability and rate-barrier issues are resolved as ordered by the FERC, and the tariffs and other material terms of our participation in GridAmerica, and GridAmerica's participation in the MISO, are finalized and approved by the FERC, we are unable to predict whether the Ameren companies will in fact become a member of GridAmerica or MISO, or the impact that on-going RTO developments will have on our financial condition, results of operation or liquidity. NOTE 3 - Related Party Transactions AmerenUE has transactions in the normal course of business with its parent, Ameren Corporation (Ameren), and its other subsidiaries. These transactions are primarily comprised of power purchases and 9 sales, as well as other services received or rendered. Intercompany power purchases from joint dispatch and other agreements were approximately $23 million for the three months ended June 30, 2002 (2001 - $21 million) and $50 million for the six months ended June 30, 2002 (2001 - $44 million). Intercompany power sales totaled $17 million for the three months ended June 30, 2002 (2001 - $12 million) and $37 million for the six months ended June 30, 2002 (2001 - $40 million). Support services provided by our affiliates, Ameren Services Company and AmerenEnergy, Inc., including wages, employee benefits and professional services are based on actual costs incurred. For the three months ended June 30, 2002, Other Operating Expenses provided by Ameren Services and AmerenEnergy totaled $48 million (2001 - $43 million) and $96 million (2001 - $90 million) for the six months ended June 30, 2002. We have the ability to borrow from Ameren and AmerenCIPS through a regulated money pool agreement. Ameren Services administers the regulated money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the money pool from participants. The primary source of external funds for the regulated money pool at June 30, 2002 was our commercial paper program, which was backed by bank credit agreements totaling $430 million. The total amount available to us at any given time from the regulated 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. The availability of funds is also determined by funding requirement limits established by PUHCA. AmerenUE, AmerenCIPS and Ameren Services rely on the regulated money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the regulated 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 regulated money pool. For the three months ended June 30, 2002, the average interest rate for the regulated money pool was 1.75% (2001 - 4.38%) and for the six months ended June 30, 2002 was 1.77% (2001 - 4.94%). As of June 30, 2002, we had the ability to borrow up to $425 million, all of which was unused and available, through the regulated money pool, which was in addition to amounts available under our $430 million commercial paper program. At June 30, 2002, we had outstanding intercompany payables of $260 million, sourced by internal funds through the money pool. At December 31, 2001, we had outstanding intercompany receivables of $84 million through the money pool. In July 2002, Ameren entered into new credit agreements for $400 million in revolving credit facilities to be used for general corporate purposes, including support of commercial paper programs. The $400 million in new facilities includes a $270 million 364-day revolving credit facility and a $130 million 3-year revolving credit facility. The 3-year facility has a $50 million sub-limit for the issuance of letters of credit. These new credit facilities replaced our existing $300 million revolving credit facility that was in place as of June 30, 2002 with a maturity of August 15, 2002. There were no amounts outstanding under this facility at June 30, 2002. In July 2002, we also did not renew a $25 million committed line of credit. As a result of these changes in facilities, at July 31, 2002, we had the ability to borrow up to $500 million, all of which was unused and available, from Ameren through our regulated money pool agreement. Intercompany receivables included in Other Accounts and Notes Receivable were approximately $15 million as of June 30, 2002 (December 31, 2001 - $38 million). Intercompany payables included in Accounts and Wages Payable totaled approximately $50 million as of June 30, 2002 (December 31, 2001 - $70 million). NOTE 4 - Derivative Financial Instruments We utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause: o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory or under the firm commitment; and o actual cash outlays for the purchase of these commodities in certain circumstances to differ from anticipated cash outlays. 10 The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internal forecasts of forward prices. We actively manage our exposure to power price risk through our power risk management program carried out under our risk management guidelines to modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, we believe these transactions serve to reduce price risk for us. In addition, we may purchase additional megawatts, again within risk management guidelines, in anticipation of future price changes. Certain derivative contracts we enter into on a regular basis as part of our power risk management program do not qualify for hedge accounting or the normal purchase, normal sale exception under SFAS 133. Accordingly, these contracts are recorded at fair value with changes in the fair value charged or credited to the income statement in the period in which the change occurred. Contracts we enter into as part of our power risk management program may be settled by either physical delivery or financially settled with the counterparty. See Note 1 - "Summary of Significant Accounting Policies." As of June 30, 2002, we recorded the fair value of derivative financial instrument assets of $21 million in Other Assets and the fair value of derivative financial instrument liabilities of $19 million in Other Deferred Credits and Liabilities. Cash Flow Hedges We routinely enter into forward purchase and sales contracts for electricity based on forecasted levels of economic generation and load requirements. The relative balance between load and economic generation varies throughout the year. The contracts typically cover a period of twelve months or less. The purpose of these contracts is to hedge against possible price fluctuations in the spot market for the period covered under the contracts. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objective and strategy for undertaking various hedge transactions. The mark-to-market value of cash flow hedges will continue to fluctuate with changes in market prices up to contract expiration. For the three months ended June 30, 2002, the pretax net 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 OCI due to transactions going to delivery or settlement, was approximately $1 million. The loss from these transactions for the three months in the prior year was immaterial. For the six months ended June 30, 2002, the second quarter loss on power forward derivative instruments offset the gain of $1 million from the first quarter. In the prior year six-month period, we recognized a pretax net gain of $6 million. As of June 30, 2002, we had hedged a portion of the price exposure related to the relative balance between load and economic generation for the upcoming twelve-month period. The mark-to-market value accumulated in OCI for the effective portion of hedges of electricity price exposure is a net loss of approximately $4 million ($2 million, net of taxes). We also hold a call option for coal deliverable in 2004 with a supplier. This option to purchase coal expires in October 2003. As of June 30, 2002, the mark-to-market value accumulated in OCI is a gain of $5 million ($3 million, net of taxes). The final value of the option 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, heating oil, and electricity. Most of these transactions are treated as non-hedge transactions under SFAS 133. The net change in the market value of sulfur dioxide options is recorded as Operating Revenues - Electric Revenues, while the net change in the market value of coal, heating oil, and electricity options is recorded as Operating Expense - Operations - Fuel and Purchased Power in the income statement. The net change in the market values of sulfur dioxide options, coal, heating oil, and electricity options was a gain of $2 million for the three months ended June 30, 2002 and $3 million for the six months ended June 30, 2002. 11 The change in market values in the prior year resulted in losses of $2 million for the three-month period and $4 million for the six-month period. NOTE 5 - Miscellaneous, Net Miscellaneous, net for the three and six months ended June 30, 2002 and 2001 consisted of the following: - ------------------------------------------------------ --------------------- --------------------- Three Months Six Months - ------------------------------------------------------ --------------------- --------------------- 2002 2001 2002 2001 ---- ---- ---- ---- Miscellaneous income: Interest and dividend income $ 2 $ 2 $ 2 $ 6 Equity in earnings of subsidiary 10 1 11 2 Gain on disposition of property and other assets 5 - 8 8 Other - 1 2 1 - -------------------------------------------------------------------------------------------------- Total miscellaneous income $ 17 $ 4 $ 23 $ 17 - -------------------------------------------------------------------------------------------------- Miscellaneous expense: Plant acquisition amortization $ - $ - $ (1) $ (1) Loss on disposition of property and other assets (1) (2) - (4) Donations - rate settlement (26) - (26) - Other (2) (1) (4) (2) - -------------------------------------------------------------------------------------------------- Total miscellaneous expense $(29) $ (3) $(31) $ (7) - --------------------------------------------------------------------------------------------------
NOTE 6 - CILCORP Acquisition On April 28, 2002, Ameren entered into an agreement with The AES Corporation to purchase all of the outstanding stock of CILCORP Inc. CILCORP is the parent company of Peoria-based Central Illinois Light Company, which operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4), L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant. The total purchase price is approximately $1.4 billion, subject to adjustment for changes in CILCORP's working capital, and includes the assumption of CILCORP and AES Medina Valley debt at closing, estimated at approximately $900 million, with the balance of the purchase price in cash. Ameren expects to finance a significant portion of the cash component of the purchase price through the issuance of new common equity. The purchase will include CILCORP's regulated natural gas and electric businesses in Illinois serving approximately 205,000 and 200,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. In addition, the purchase includes approximately 1,200 megawatts of largely coal-fired generating capacity, most of which is expected to be non-regulated by closing. Upon completion of the acquisition, expected by March 2003, CILCO will become an Ameren subsidiary, but will remain a separate utility company, operating as AmerenCILCO. The transaction is subject to the approval of the Illinois Commerce Commission, the SEC, the FERC, the expiration of the waiting period under the Hart-Scott-Rodino Act, the Federal Communications Commission and other customary closing conditions. For the period ended December 31, 2001, CILCORP had revenues of $815 million, operating income of $126 million, and net income from continuing operations of $28 million, and as of December 31, 2001 had total assets of $1.8 billion. 12 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations OVERVIEW Union Electric Company is a wholly-owned subsidiary of Ameren Corporation and operates as AmerenUE. Our principal business is the regulated generation, transmission and distribution of electricity, and the regulated distribution of natural gas to residential, commercial, industrial and wholesale users in Missouri and Illinois. Ameren Corporation is a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). Ameren's principal business is the generation, transmission and distribution of electricity, and the distribution of natural gas to residential, commercial, industrial and wholesale users in the central United States. In addition to us, Ameren's principal subsidiaries and our affiliates are as follows: o Central Illinois Public Service Company, which operates a regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. o AmerenEnergy Resources Company (Resources Company), which consists of non-regulated operations. Subsidiaries include AmerenEnergy Generating Company (Generating Company) that operates non-regulated electric generation in Missouri and Illinois, AmerenEnergy Marketing Company (Marketing Company) which markets power for periods over one year, and AmerenEnergy Fuels and Services Company, which procures fuel and manages the related risks for Ameren affiliated companies. o AmerenEnergy, Inc. which serves as a power marketing and risk management agent for Ameren affiliated companies for transactions of primarily less than one year. o Electric Energy, Inc. (EEI), which owns and/or operates electric generation and transmission facilities in Illinois. We have a 40% ownership interest in EEI and have accounted for it under the equity method of accounting. Our affiliate, Resources Company, also owns a 20% interest. o Ameren Services Company, 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 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 The audited financial statements and related notes that are included in our Annual Report on Form 10-K for the period ended December 31, 2001. o Management's Discussion and Analysis of Financial Condition and Results of Operations that appears in our Annual Report on Form 10-K for the period ended December 31, 2001. When we refer to AmerenUE, our, we or us, we are referring to Union Electric Company. All dollar amounts are in millions, unless otherwise indicated. Our results of operations and financial position are impacted by many factors, including both controllable and uncontrollable factors. Weather, economic conditions, and the actions of key customers or competitors can significantly impact the demand for our services. Our results are also impacted by seasonal fluctuations caused by winter heating, and summer cooling, demand. With nearly all of our revenues subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. We principally utilize coal, nuclear fuel and natural gas in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, production levels and many other factors. We do not have fuel recovery mechanisms in Missouri and Illinois, but do have gas cost recovery mechanisms in each state. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power 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. 13 RESULTS OF OPERATIONS Summary Our net income increased 30% to $107 million in the second quarter of 2002, from $82 million in the second quarter of 2001. Earnings for the six months ended June 30, 2002, were $158 million, an increase of $38 million from the first six months of 2001. The increase in both periods was primarily due to favorable weather conditions (second quarter - $11 million; year to date - $6 million), increased sales of emission credits, including EEI (second quarter - $9 million; year to date - $17 million), and the lack of a Callaway nuclear plant refueling outage to date in 2002 (second quarter - $16 million; year to date - $19 million). These increases were partially offset by the impact of the settlement of our Missouri electric rate case (second quarter and year to date - $20 million) (see below) and a reduction of an accrual in 2001 (second quarter - $15 million; year to date - $6 million) for expected customer sharing credits under the Missouri experimental alternative regulation plan that expired in June 2001 (see Note 2 - "Rate and Regulatory Matters" to our financial statements). In January 2001, we also recorded a charge of $5 million due to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." Recent Developments Missouri Electric Rate Case From July 1, 1995 through June 30, 2001, we operated under experimental alternative regulation plans in Missouri that provided for the sharing of earnings with customers if our regulatory return on equity exceeded defined threshold levels. After our experimental alternative regulation plan for our Missouri retail electric customers expired, the Missouri Public Service Commission (MoPSC) Staff filed an excess earnings complaint against us with the MoPSC in July 2001. In March 2002, the MoPSC Staff filed a recommendation that we reduce our annual Missouri electric revenues by $246 million to $285 million. The MoPSC Staff's recommendation was based on a return to traditional cost of service ratemaking, a lowered return on equity, a reduction in our depreciation rates and other cost of service adjustments. In May 2002, we filed testimony supporting a rate increase of at least $150 million and proposed a new alternative regulation plan that included a rate decrease. On July 16, 2002, AmerenUE, the MoPSC Staff, and all of the other parties to the proceeding submitted to the MoPSC a stipulation and agreement resolving this case. On July 24, 2002, the MoPSC held a hearing on the stipulation and agreement. On July 25, 2002, the MoPSC approved the stipulation and agreement, and on August 4, 2002, it became effective. The stipulation and agreement includes the following principal features: o the phase-in of $110 million of electric rate reductions through April 2004, $50 million of which is retroactively effective as of April 1, 2002, $30 million of which will become effective on April 1, 2003, and $30 million of which will become effective on April 1, 2004, o a rate moratorium providing for no requests for changes in our electric rates as established by the stipulation and agreement before January 1, 2006 and no resulting changes in rates before June 30, 2006, subject to certain statutory and other exceptions, o a commitment to contribute, as early as September 2002, $14 million to programs for low income energy assistance and weatherization, promotion of energy efficiency and economic development in our service territory, with additional payments of $3 million made annually on June 30, 2003 through June 30, 2006, o a commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at our nuclear power plant. The 700 megawatts of new generation includes 240 megawatts already added this year and may include the transfer at book value to us of generation assets from our non-regulated affiliates. The amount of energy infrastructure investments through June 2006 described in the stipulation and agreement is consistent with our previously-disclosed estimate of the construction expenditures we expect to make over the same time period, 14 o an annual reduction in our depreciation rates by $20 million, retroactive to April 1, 2002, based on an updated analysis of asset values, service lives and accumulated depreciation levels, and o a one-time credit of $40 million to be paid to our Missouri retail electric customers as early as August 2002 for settlement of the final sharing period under the alternative regulation plan that expired June 30, 2001. At June 30, 2002, we had accrued $40 million in Current Liabilities - Other. In total, the stipulation and agreement is estimated to reduce 2002 net earnings by $32 million. Net earnings are expected to be reduced in 2002 due to the rate reduction ($26 million, net of taxes, including $8 million, net of taxes, in the quarter ended June 30, 2002), the expensing in the quarter ended June 30, 2002 of the entire obligation to fund certain programs ($15 million, net of taxes), offset, in part, by the reduction in depreciation expense ($9 million, net of taxes, including $3 million, net of taxes, in the quarter ended June 30, 2002). Net earnings were reduced by $20 million in the quarter ended June 30, 2002 due to the stipulation and agreement. We expect earnings to be reduced by $9 million in the third quarter of 2002 and $3 million in the fourth quarter of 2002. CILCORP Acquisition On April 28, 2002, Ameren entered into an agreement with The AES Corporation to purchase all of the outstanding stock of CILCORP Inc. CILCORP is the parent company of Peoria-based Central Illinois Light Company, which operates as CILCO. Ameren also agreed to acquire AES Medina Valley (No. 4), L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant. The total purchase price is approximately $1.4 billion, subject to adjustment for changes in CILCORP's working capital, and includes the assumption of CILCORP and AES Medina Valley debt at closing, estimated at approximately $900 million, with the balance of the purchase price in cash. Ameren expects to finance a significant portion of the cash component of the purchase price through the issuance of new common equity. The purchase will include CILCORP's regulated natural gas and electric businesses in Illinois serving approximately 205,000 and 200,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. In addition, the purchase includes approximately 1,200 megawatts of largely coal-fired generating capacity, most of which is expected to be non-regulated by closing. Upon completion of the acquisition, expected by March 2003, CILCO will become an Ameren subsidiary, but will remain a separate utility company, operating as AmerenCILCO. The transaction is subject to the approval of the Illinois Commerce Commission, the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the expiration of the waiting period under the Hart-Scott-Rodino Act, the Federal Communications Commission and other customary closing conditions. For the period ended December 31, 2001, CILCORP had revenues of $815 million, operating income of $126 million, and net income from continuing operations of $28 million, and as of December 31, 2001 had total assets of $1.8 billion. 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 Corporation's debt under review for possible downgrade or negative credit watch. Standard & Poor's placed the ratings of AmerenUE and AmerenCIPS debt on negative credit watch and placed the ratings of Generating Company's debt on positive credit watch. However, Standard & Poor's stated they expect the corporate credit ratings of Ameren and its subsidiaries to be in the "A" rating category following completion of the acquisition. Moody's Investor Service stated they envisioned a one notch downgrade of Ameren's issuer, senior unsecured debt and commercial paper ratings. Ameren's corporate credit rating is A+ at Standard & Poor's and its issuer rating is A2 at Moody's, while AmerenUE's corporate credit rating is A+ at Standard & Poor's and its issuer rating is A1 at Moody's. In July, AmerenUE settled its electric earnings complaint case. The rating agencies have not changed the assignment of negative watch, review for possible downgrade or negative outlook to any of the ratings nor have the ratings themselves changed. Any adverse change in the Ameren companies' ratings may reduce our access to capital and/or increase the costs of borrowings resulting in a negative impact on earnings. 15
Electric Operations The following table represents the favorable (unfavorable) variation for the three and six-month periods ended June 30, 2002 from the comparable periods in 2001: - ---------------------------------------------------------------------------------------------------- Three Months Six Months - ---------------------------------------------------------------------------------------------------- Operating Revenues: Effect of abnormal weather (estimate)............ $ 22 $ 10 Growth and other (estimate)...................... 4 22 Rate reductions (13) (13) Credit to customers.............................. (25) (10) Interchange revenues............................. (21) 45 - ---------------------------------------------------------------------------------------------------- (33) 54 Fuel and Purchased Power: Fuel: Generation..................................... $ (14) $ (6) Price.......................................... 12 18 Purchased power ................................. 53 (36) - ---------------------------------------------------------------------------------------------------- 51 (24) - ---------------------------------------------------------------------------------------------------- Change in electric margin $ 18 $ 30 - ----------------------------------------------------------------------------------------------------
Electric margin increased $18 million for the three months and $30 million for the six months ended June 30, 2002, compared to the prior year periods. Favorable weather conditions resulted in an increase in weather-sensitive residential and commercial kilowatt-hour sales of 9% for the three-month period over the year-ago quarter. Revenues were reduced by $13 million in the three and six months ended June 30, 2002 due to the settlement of the Missouri electric rate case. Revenues in 2001 were increased by $25 million in the second quarter, and $10 million in the first six months, due to a reduction in the accrual for expected customer sharing credits under the Missouri experimental alternative regulation plan that expired in June 2001. During the first six months of 2002, we also experienced growth in electric revenues due to the expansion of our weather-normalized native load and sales of sulfur dioxide allowances. Although interchange sales decreased in the quarter, the effect on margin was more than offset by a resulting decrease in purchased power. Purchased power was also reduced in the second quarter of 2002 due to the lack of a Callaway nuclear plant refueling. Another refueling outage at Callaway is scheduled this Fall which is estimated to reduce net earnings by $14 million through an increase in purchased power and maintenance expenses. For the six-month period, the impact on margin of the favorable second quarter weather was somewhat offset by the milder weather conditions experienced in the first quarter. Total electric kilowatt-hour sales increased for the six months of 2002, compared to the year-ago period, primarily due to an increase in interchange sales. Fuel and purchased power increased to accommodate the larger interchange sales volume. We realized lower margins on interchange sales compared to the prior year, due to lower wholesale electricity prices. The above interchange revenues and fuel and purchased power amounts include transactions with our affiliates. See Note 3 - "Related Party Transactions" to our financial statements for further details. Gas Operations Our gas revenues and gas margins in second quarter of 2002 were comparable to the year-ago quarter. Gas margins decreased $4 million for the first six months of 2002 as compared to the year-ago period as gas revenues decreased $19 million, primarily due to reduced sales of 6% caused by milder winter weather at the beginning of the year. Reduced gas purchases partially offset the effect of the reduced sales. Other Operating Expenses Other operations related to operating expenses increased $6 million in the second quarter of 2002 and $5 million in the first six months of 2002, compared to the year-ago periods, primarily due to higher employee benefit costs related to the investment performance of pension plan assets and increasing healthcare costs. 16 Ameren Services and AmerenEnergy provided services to us including wages, employee benefits, and professional services that were included in Other Operating Expenses (see Note 3 - "Related Party Transactions" to our financial statements). Maintenance expenses decreased $33 million in the second quarter of 2002 and $36 million in the first six months of 2002, compared to the same prior year periods, primarily due to the lack of a Callaway nuclear plant refueling outage to date in the current year, along with decreased maintenance at our coal-fired power plants. Depreciation and amortization expenses increased $2 in the first six months of 2002, compared to the year-ago periods, primarily due to an increase in depreciable property related to investment in our coal power plants, partially offset by a reduction of depreciation rates based on an updated analysis of asset values, service lives and accumulated depreciation levels and agreed to in the stipulation and agreement associated with the Missouri electric rate case. Income tax expense increased $5 million in the second quarter of 2002 and $2 million in the first six months of 2002, compared to the same prior year periods, primarily due to higher pre-tax income. Other tax expense increased $2 million in the second quarter of 2002 and $4 million in the first six months of 2002, compared to the year-ago periods, primarily due to higher gross receipts taxes resulting from increased electric sales. Other Income and Deductions Other income and deductions decreased $17 million in the second quarter of 2002 and $21 million in the first six months of 2002, compared to the same periods last year, primarily due to the commitment to fund certain programs as part of the settlement of the Missouri electric rate case ($26 million) and lower intercompany interest earned in the first quarter of 2002 on funds loaned to the regulated money pool, resulting from lower average intercompany notes receivable balances. These increases were partially offset by an increase in earnings from our ownership interest in EEI (second quarter - $10 million; year-to-date - $11 million) along with increased gains on asset disposals. See Note 5 - "Miscellaneous, Net" to our financial statements. Interest Interest expense decreased $4 million in the second quarter of 2002 and $7 million in the first six months of 2002, compared to the year-ago periods, primarily due to lower interest rates on our variable rate environmental bonds and lower interest expense associated with a decreased balance under our nuclear fuel lease, partially offset by increased short-term intercompany interest as a result of our borrowings from the money pool in the current year. Amortization of debt issuance costs and premium/discounts for the three and six months ending June 30, 2002 of $1 million (2001 - $1 million) and $2 million (2001 - $2 million) were included in interest expense in the income statement. LIQUIDITY AND CAPITAL RESOURCES Operating Our cash flows provided by operating activities increased $18 million to $243 million in the first six months of 2002, compared to the year-ago period. Cash flow from operations increased primarily due to increased earnings ($38 million), a decrease in the prior period's liability for electric customer credits ($45 million), and decreased coal inventories and stored gas ($25 million). Materials and supplies were higher than normal at December 31, 2001, due to the warm winter and anticipation of a potential coal supply disruption that ultimately did not occur. The primary use of cash was a reduction of accounts and wages payable ($90 million). Our tariff-based gross margins continue to be our principal source of cash from operating activities. Our diversified retail customer mix of residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. We plan to utilize short-term debt to support normal operations and other temporary capital requirements. AmerenUE is authorized by the SEC under PUHCA to have up to $1 billion of short-term unsecured debt instruments outstanding at 17 any one time. Short-term borrowings typically consist of commercial paper with maturities generally within 1 to 45 days. As of June 30, 2002, we had several bank credit agreements expiring in 2002 that supported our $430 million commercial paper program, all of which were unused and available. We also had the ability to borrow up to approximately $425 million from Ameren or from AmerenCIPS, through a regulated money pool agreement (see Note 3 - "Related Party Transactions" to our financial statements). In July 2002, Ameren entered into new credit agreements for $400 million in revolving credit facilities to be used for general corporate purposes, including support of commercial paper programs. The $400 million in new facilities includes a $270 million 364-day revolving credit facility and a $130 million 3-year revolving credit facility. The 3-year facility has a $50 million sub-limit for the issuance of letters of credit. These new credit facilities replaced our existing $300 million revolving credit facility that was in place as of June 30, 2002 with a maturity of August 15, 2002. There were no amounts outstanding under this facility at June 30, 2002. In July 2002, we also did not renew a $25 million committed line of credit. As a result of these changes, at July 31, 2002, we had the ability to borrow up to $500 million, all of which was unused and available, from Ameren through our regulated money pool agreement. We also have a lease agreement that provides for the financing of nuclear fuel. At June 30, 2002, the maximum amount that could be financed under the agreement was $120 million, of which $70 million was utilized. Our financial agreements include customary default provisions that could impact the continued availability of credit or result in the acceleration of repayment. These events include bankruptcy, defaults in payment of other indebtedness, certain judgments that are not paid or insured, or failure to meet or maintain covenants. At June 30, 2002, we were in compliance with these provisions. Investing Our net cash used in investing activities was $174 million in the first six months of 2002 compared to $179 million in the first six months of 2001. Construction expenditures were incurred primarily for upgrades at our coal power plants and further construction of combustion turbine generating units. Our capital expenditures are expected to approximate $500 million in 2002. As a part of the settlement of the Missouri electric earnings complaint case (see Note 2 - "Rate and Regulatory Matters" to our financial statements), we committed to making $2.25 billion to $2.75 billion in infrastructure investments from January 1, 2002 through June 30, 2006. These investments include, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at our Callaway nuclear power plant. The 700 megawatts of new generation includes 240 megawatts already added this year and may include the transfer at book value to us of generation assets from our other non-regulated subsidiaries. The amount of energy infrastructure investments through June 2006 described in the stipulation and agreement is consistent with our previously-disclosed estimate of the construction expenditures we expect to make over the same time period. Due to expected increased demand and the need to maintain appropriate power reserve margins, we believe we will need additional generating capacity in the future. We have an equipment supply agreement in place for the addition of two combustion turbine generating units with a total installed capacity of 330 megawatts. These units will replace the existing Venice steam plant generating units which are expected to be retired in 2003. Noncancellable reservation commitment fees paid of $22 million will be applied to our total cost of these megawatts pursuant to the agreement. 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 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 losses being incurred, which could be material. 18 Financing Our cash flows used in financing activities were $76 million in the first six months of 2002 compared to $61 million in the year-ago period. Our principal financing activities for the current period included the redemption of short-term debt and the payment of dividends, partially offset by the issuance of intercompany notes payable. In May 2002, we filed a shelf registration statement with the SEC on Form S-3 that allows for 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, as well as for general corporate purposes, including the repayment of short-term debt incurred to finance construction expenditures and other working capital needs. In the ordinary course of business, we evaluate several strategies to enhance our financial position, earnings, and liquidity. These strategies may include potential acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives in order to increase shareholder value. We are unable to predict which, if any, of these initiatives will be executed, as well as the impact these initiatives may have on our future financial position, results of operations or liquidity. Electric Industry Restructuring Illinois See Note 2 - "Rate and Regulatory Matters" to our financial statements. Federal - Regional Transmission Organizations See Note 2 - "Rate and Regulatory Matters" to our financial statements. ACCOUNTING MATTERS Critical Accounting Policies Preparation of the financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. Our application of these policies involves judgments regarding many factors, which, in and of themselves, could materially impact the financial statements and disclosures. A future change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results. In the table below, we have outlined those accounting policies that we believe are most difficult, subjective or complex: Accounting Policy Uncertainties Affecting Application - ----------------- ----------------------------------- Regulatory Mechanisms & Cost Recovery We defer costs as regulatory assets in o Regulatory environment, external regulatory accordance with SFAS 71 and make investments decisions and requirements that we assume we will be able to collect in o Anticipated future regulatory decisions and 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. 19 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 plant will have a useful life of 40 decommissioning years and estimated costs to dismantle the o Useful lives of nuclear power plants plant are accurate. See Note 12 to our financial statements for the year ended December 31, 2001.
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 regulation 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. 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. o Interest rates used in valuing benefit See Note 10 to our financial statements for obligations the year ended December 31, 2001. o Healthcare cost trend rates
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. 20 Derivative Financial Instruments We record all derivatives at their fair market o Market conditions in the energy industry, especially value in accorandce with SFAS 133. The the effects of price volatility on contractual identification and classification of a commodity commitments derivative, and the fair value of such o Regulatory and political environments and derivative must be determined. See Note 4 requirements to our financial statements for the year o Fair value estimations on longer term contracts ended December 31, 2001 and Note 4 - "Derivative Financial Instruments" to our financial statements.
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 financial statements. ITEM 3. Quantitative and Qualitative Disclosures about Market Risk Market risk represents the risk of changes in value of a physical asset or financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g. interest rates, etc.). The following discussion of Ameren's, including AmerenUE's, risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those projected in the "forward-looking" statements. Ameren manages market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren and our company also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, and operational risk and are not represented in the following analysis. Ameren's risk management objective is to optimize its physical generating assets within prudent risk parameters. Risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers. Interest Rate Risk We are exposed to market risk through changes in interest rates associated with our issuance of both long-term and short-term variable-rate debt, fixed-rate debt and commercial paper. We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates. Utilizing our debt outstanding at June 30, 2002, if interest rates increased by 1%, our annual interest expense would increase by approximately $8 million and net income would decrease by approximately $5 million. The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure. Fuel Price Risk 100% of the required 2002 supply of coal for our coal power plants has been acquired at fixed prices. As such, we have minimal coal price risk for 2002. In addition, approximately 70% of our coal requirements from 2003 through 2006 are covered by contracts. 21 Fair Value of Contracts We utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause: o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory and under firm commitment; and o actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays. The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internally forecast forward prices and modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, these transactions serve to reduce our price risk. See Note 4 - "Derivative Financial Instruments" to our financial statements for more information. The following summarizes changes in the fair value of all contracts marked to market during the three and six months ended June 30, 2002:
- ---------------------------------------------------------------------------------------------------------- Three Six months months - ---------------------------------------------------------------------------------------------------------- Fair value of contracts at beginning of period, net $ (4) $ (2) Contracts which were realized or otherwise settled during the period (5) (5) 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 11 9 - ---------------------------------------------------------------------------------------------------------- Fair value of contracts outstanding at June 30, 2002, net $ 2 $ 2 - ----------------------------------------------------------------------------------------------------------
Maturities of contracts as of June 30, 2002 were as follows: - ---------------------------------------------------------------------------------------------------------- Maturity Maturity in less than Maturity Maturity excess of 5 Total fair Sources of fair value 1 year 1-3 years 4-5 years years value (a) - ---------------------------------------------------------------------------------------------------------- Prices actively quoted - - - - - Prices provided by other external sources (b) - - - - - Prices based on models and other valuation methods (c) (2) 5 (1) - 2 - ---------------------------------------------------------------------------------------------------------- Total (2) 5 (1) - 2 - ---------------------------------------------------------------------------------------------------------- (a) Nearly 100% of contracts were with investment-grade rated counterparties. (b) Principally power forward values based on NYMEX prices for over-the-counter contracts. (c) Principally coal option and sulfur dioxide option values based on a Black-Scholes model that includes information from external sources and our estimates.
SAFE HARBOR STATEMENT Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in the Annual Report on Form 10-K for 22 the year ended December 31, 2001, and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: o the effects of the stipulation and agreement relating to our excess earnings complaint case and other regulatory actions, including changes in regulatory policy; o changes in laws and other governmental actions, including monetary and fiscal policies; o the impact on us of current regulations related to the opportunity for customers to choose alternative energy suppliers in Illinois; o the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels; o the effects of participation in a FERC-approved Regional Transmission Organization (RTO), including activities associated with the Midwest Independent System Operator; o availability and future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial and derivative instruments and volatility of changes in market prices; o average rates for electricity in the Midwest; o business and economic conditions; o the impact of the adoption of new accounting standards; o interest rates and the availability of capital; o actions of rating agencies and the effects of such actions; o weather conditions; o generation plant construction, installation and performance; o operation of nuclear power facilities and decommissioning costs; o the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; o future wages and employee benefits costs; o competition from other generating facilities including new facilities that may be developed in the future; o disruptions of the capital markets or other events making AmerenUE's access to necessary capital more difficult or costly; o cost and availability of transmission capacity for the energy generated by our generating facilities or required to satisfy our energy sales; and o legal and administrative proceedings. 23 PART II. OTHER INFORMATION ITEM 1. Legal Proceedings Reference is made to Item 3. Legal Proceedings in Part I of our Form 10-K for the year-ended December 31, 2001 and to Item 1. Legal Proceedings in Part II of our Form 10-Q for the quarterly period ended March 31, 2002 for a discussion of a number of lawsuits that name our affiliate, Central Illinois Public Service Company operating as AmerenCIPS, our parent, Ameren Corporation, and us (which we refer to as the Ameren companies), along with numerous other parties, as defendants that have been filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Since the filing of our Form 10-Q for the quarterly period ended March 31, 2002, thirty-four additional lawsuits have been filed against the Ameren companies. 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 our first quarter Form 10-Q filing, a settlement has been reached in one lawsuit for a monetary amount not material to the Ameren companies and in one case, the Ameren companies have been voluntarily dismissed. To date, a total of seventy-six asbestos-related lawsuits have been filed against the Ameren companies, of which sixty-two are pending, ten have been settled and four 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. ITEM 4. Submission of Matters to a Vote of Security Holders At our annual meeting of stockholders held on April 23, 2002, the following matter was presented to the meeting for a vote and the results of such voting are as follows: Election of Directors. Non-Voted Name For Withheld Brokers - ---- --- -------- --------- Paul A. Agathen................... 102,522,452 86,475 0 Warner L. Baxter.................. 102,522,452 86,475 0 Charles W. Mueller................ 102,522,335 86,592 0 Gary L. Rainwater................. 102,522,452 86,475 0 Thomas R. Voss.................... 102,521,846 87,081 0
ITEM 5. Other Information Any stockholder proposal intended for inclusion in the proxy material for our 2003 annual meeting of stockholders must be received by us by November 30, 2002. In addition, under our By-Laws, stockholders who intend to submit a proposal in person at an annual meeting, or who intend to nominate a director at a meeting, must provide advance written notice along with other prescribed information. In general, such notice must be received by our Secretary not later than 60 nor earlier than 90 days prior to the first anniversary of the preceding year's annual meeting. For our 2003 annual meeting of stockholders, written notice of any in-person stockholder proposal or director nomination must be received no later than February 22, 2003 or earlier than January 23, 2003. 24 The Audit Committee of the Board of Directors of Ameren has approved our independent accountants, PriceWaterhouseCoopers, to perform the following audit and non-audit services: o Audits required by the federal, state or local government rules o Audits of employee pension and benefits plans o Income tax accounting and consulting projects o Comfort letters and consents required to complete SEC filings and issue securities o Consultation on responses to accounting inquiries by regulatory or other bodies o Audit of AmerenEnergy earnings before interest and taxes statement o Review of stock transfer agent and registrar internal controls o Review of risk management internal controls o Consultation on the accounting for corporate events and transactions o Assistance with preparation of testimony for regulatory filings ITEM 6. Exhibits and Reports on Form 8-K (a)(i) Exhibits. 99.1 - Certificate of Chief Executive Officer required by Section 906 of the Sarbanes-Oxley Act of 2002 (not filed as a part of this Report on Form 10-Q). 99.2 - Certificate of Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002 (not filed as a part of this Report on Form 10-Q). (a)(ii) Exhibits Incorporated by Reference. 10.1 - Memorandum of Understanding dated May 24, 2002 between Ameren Services Company, as agent for AmerenUE and AmerenCIPS, and the Midwest Independent Transmission System Operator, Inc. (MISO) (June 30, 2002 Ameren Corporation Form 10-Q, Exhibit 10.1). 10.2 - Participation Agreement dated as of July 3, 2002 by and among MISO, Ameren Services Company as agent for AmerenUE and AmerenCIPS, FirstEnergy Corporation on behalf of American Transmission Systems, Incorporated, Northern Indiana Public Service Company and National Grid (June 30, 2002 Ameren Corporation Form 10-Q, Exhibit 10.2). 99.3 - Stipulation and Agreement dated July 15, 2002 in Missouri Public Service Commission (MoPSC) Case No. EC-2002-1 (earnings complaint case against AmerenUE) (File Nos. 333-87506 and 333-87506-01, Exhibit 99.1). (b) Reports on Form 8-K. AmerenUE filed reports on Form 8-K as follows: (i) dated May 28, 2002 relating to the decision of AmerenCIPS and AmerenUE to rejoin the MISO; (ii) dated July 12, 2002 incorporating a press release stating that an agreement in principle had been reached in the earnings complaint case filed by the MoPSC staff against AmerenUE; (iii) dated July 16, 2002 incorporating a press release outlining the details of the settlement reached in the MoPSC earnings complaint case; and (iv) dated July 25, 2002 incorporating a press release stating that the MoPSC had approved the settlement reached in the earnings complaint case. Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-14756. Reports of Central Illinois Public Service Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-3672. Reports of Ameren Energy Generating Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under the File Number 333-56594. 25 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. UNION ELECTRIC COMPANY (Registrant) By /s/ Martin J. Lyons ---------------------------- Martin J. Lyons Controller (Principal Accounting Officer) Date: August 14, 2002 26 Exhibit 99.1 CERTIFICATE furnished under Section 906 of the Sarbanes-Oxley Act of 2002. I, Charles W. Mueller, chief executive officer of Union Electric Company, hereby certify that to the best of my knowledge, the accompanying Report of Union Electric Company on Form 10-Q for the quarter ended June 30, 2002 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of Union Electric Company. /s/ Charles W. Mueller --------------------------------- Charles W. Mueller Chief Executive Officer Date: August 14, 2002 Exhibit 99.2 CERTIFICATE furnished under Section 906 of the Sarbanes-Oxley Act of 2002. I, Warner L. Baxter, chief financial officer of Union Electric Company, hereby certify that to the best of my knowledge, the accompanying Report of Union Electric Company on Form 10-Q for the quarter ended June 30, 2002 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Report fairly presents, in all material respects, the financial condition and results of operations of Union Electric Company. /s/ Warner L. Baxter ---------------------------------- Warner L. Baxter Chief Financial Officer Date: August 14, 2002 -----END PRIVACY-ENHANCED MESSAGE-----