-----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, VYZl2p2rlypgTVRdiXxYA76TPmVD4Ih2Q5TDqftTPAlxCVJN5wkAAsafP/xwte2S n1lDUCJAKq7TezFa6Fhurg== 0001002910-03-000240.txt : 20030514 0001002910-03-000240.hdr.sgml : 20030514 20030514121550 ACCESSION NUMBER: 0001002910-03-000240 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20030331 FILED AS OF DATE: 20030514 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AMEREN CORP CENTRAL INDEX KEY: 0001002910 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 431723446 STATE OF INCORPORATION: MO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-14756 FILM NUMBER: 03697663 BUSINESS ADDRESS: STREET 1: 1901 CHOUTEAU AVE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63166-6149 BUSINESS PHONE: 431723446 MAIL ADDRESS: STREET 1: 1901 CHOUTEAU AVE STREET 2: MC 1370 CITY: ST LOUIS STATE: MO ZIP: 63103 10-Q 1 amc10-q033103.txt AMEREN CORP'S 10-Q 03/31/03 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For Quarterly Period Ended March 31, 2003 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For The Transition Period From to Commission file number 1-14756. AMEREN CORPORATION (Exact name of registrant as specified in its charter) Missouri 43-1723446 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1901 Chouteau Avenue, St. Louis, Missouri 63103 (Address of principal executive offices and Zip Code) Registrant's telephone number, including area code: (314) 621-3222 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (X). No ( ). Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes (X). No ( ). Shares outstanding of each of the registrant's classes of common stock as of May 9, 2003: Common Stock, $.01 par value - 161,218,664.
AMEREN CORPORATION TABLE OF CONTENTS Page ---- PART I. Financial Information ITEM 1. Financial Statements (Unaudited) Consolidated Balance Sheet at March 31, 2003 and December 31, 2002....................................... 2 Consolidated Statement of Income for the three months ended March 31, 2003 and 2002.................... 3 Consolidated Statement of Cash Flows for the three months ended March 31, 2003 and 2002.................. 4 Consolidated Statement of Common Stockholders' Equity for the three months ended March 31, 2003 and 2002................................................................................................. 5 Notes to Consolidated Financial Statements............................................................... 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 17 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk............................................... 29 ITEM 4. Controls and Procedures.................................................................................. 31 PART II. Other Information ITEM 1. Legal Proceedings........................................................................................ 33 ITEM 6. Exhibits and Reports on Form 8-K......................................................................... 33 SIGNATURE.............................................................................................................. 35 CERTIFICATIONS......................................................................................................... 35 This Form 10-Q contains "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Part I, Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations," under the heading "Forward-Looking Statements." Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects," and similar expressions.
PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements. AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (Unaudited, in millions, except per share amounts) March 31, December 31, 2003 2002 ----------- ------------ ASSETS: Property and plant, net $ 10,182 $ 8,840 Investments and other assets: Investments 169 38 Nuclear decommissioning trust fund 172 172 Goodwill and other intangibles, net 621 - Other assets 336 307 ----------- ----------- Total investments and other assets 1,298 517 ----------- ----------- Current assets: Cash and cash equivalents 294 628 Accounts receivable - trade (less allowance for doubtful accounts of $11 and $7, respectively) 360 266 Unbilled revenue 180 176 Miscellaneous accounts and notes receivable 54 44 Materials and supplies, at average cost 354 299 Other current assets 49 39 ----------- ----------- Total current assets 1,291 1,452 ----------- ----------- Regulatory assets 818 690 ----------- ----------- Total Assets $ 13,589 $ 11,499 =========== =========== CAPITAL AND LIABILITIES: Capitalization: Common stock, $.01 par value, 400.0 shares authorized - shares outstanding of 161.1 and 154.1, respectively $ 2 $ 2 Other paid-in capital, principally premium on common stock 2,480 2,203 Retained earnings 1,738 1,739 Accumulated other comprehensive income (96) (93) Other (14) (9) ----------- ------------ Total common stockholders' equity 4,110 3,842 ----------- ------------ Preferred stock not subject to mandatory redemption 235 193 Long-term debt, net 4,499 3,433 ----------- ------------ Total capitalization 8,844 7,468 ----------- ------------ Minority interest in consolidated subsidiaries 16 15 Current liabilities: Current maturities of long-term debt 342 339 Short-term debt 16 271 Accounts and wages payable 295 369 Asset retirement obligation 4 - Accumulated deferred income taxes 5 5 Taxes accrued 144 45 Other current liabilities 251 172 ----------- ------------ Total current liabilities 1,057 1,201 ----------- ------------ Accumulated deferred income taxes 2,000 1,707 Accumulated deferred investment tax credits 159 149 Regulatory liabilities 129 136 Asset retirement obligation 396 174 Accrued pension liabilities 524 377 Other deferred credits and liabilities 464 272 ----------- ------------ Total Capital and Liabilities $ 13,589 $ 11,499 =========== ============ See Notes to Consolidated Financial Statements.
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AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (Unaudited, in millions, except per share amounts) Three Months Ended March 31, ------------------------------ 2003 2002 ------------- ------------- OPERATING REVENUES: Electric $ 856 $ 747 Gas 250 125 Other 2 2 ------------- ------------- Total operating revenues 1,108 874 ------------- ------------- OPERATING EXPENSES: Fuel and purchased power 221 203 Gas 185 85 Other operations and maintenance 299 262 Depreciation and amortization 124 107 Income taxes 52 38 Other taxes 78 68 ------------- ------------- Total operating expenses 959 763 ------------- ------------- OPERATING INCOME 149 111 OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction - 2 Miscellaneous, net - Miscellaneous income 6 3 Miscellaneous expense (3) (4) ------------- ------------- Total other income and (deductions) 3 1 ------------- ------------- INTEREST CHARGES AND PREFERRED DIVIDENDS: Interest 68 52 Allowance for borrowed funds used during construction (2) (2) Preferred dividends of subsidiaries 3 3 ------------- ------------- Net interest charges and preferred dividends 69 53 ------------- ------------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 83 59 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES 18 - ------------- ------------- NET INCOME $ 101 $ 59 ============= ============= EARNINGS PER COMMON SHARE - BASIC AND DILUTED: Income before cumulative effect of change in accounting principle $ 0.52 $ 0.42 Cumulative effect of change in accounting principle, net of income taxes 0.11 - ------------- ------------- Net income $ 0.63 $ 0.42 ============= ============= AVERAGE COMMON SHARES OUTSTANDING 158.9 139.7 See Notes to Consolidated Financial Statements.
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AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions) Three Months Ended March 31, --------------------------- 2003 2002 ----------- ----------- Cash Flows From Operating: Net income $ 101 $ 59 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle (18) - Depreciation and amortization 124 107 Amortization of nuclear fuel 7 7 Amortization of debt issuance costs and premium/discounts 2 2 Allowance for funds used during construction (2) (4) Deferred income taxes, net 3 (3) Deferred investment tax credits, net (3) (2) Other (7) (11) Changes in assets and liabilities, excluding the effects of the acquisitions: Receivables, net 13 26 Materials and supplies 44 37 Accounts and wages payable (186) (218) Taxes accrued 68 69 Assets, other 7 (17) Liabilities, other 73 58 ----------- ----------- Net cash provided by operating activities 226 110 ----------- ----------- Cash Flows From Investing: Construction expenditures (144) (159) Acquisitions, net of cash acquired (488) - Allowance for funds used during construction 2 4 Nuclear fuel expenditures - (5) Other 1 - ----------- ----------- Net cash used in investing activities (629) (160) ----------- ----------- Cash Flows From Financing: Dividends on common stock (102) (91) Capital issuance costs (10) (20) Redemptions: Nuclear fuel lease (2) Short-term debt (255) (536) Long-term debt (31) (4) Issuances: Common stock 285 246 Nuclear fuel lease - 3 Long-term debt 184 445 ----------- ----------- Net cash provided by financing activities 69 43 ----------- ----------- Net change in cash and cash equivalents (334) (7) Cash and cash equivalents at beginning of year 628 67 ----------- ----------- Cash and cash equivalents at end of period $ 294 $ 60 =========== =========== Cash paid during the periods: Interest $ 45 $ 27 Income taxes, net 11 4 See Notes to Consolidated Financial Statements.
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AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY (Unaudited, in millions) Three Months Ended March 31, ------------------------------ 2003 2002 ------------ ------------- Common stock Beginning balance $ 2 $ 1 Shares issued - - ------------ ------------- 2 1 ------------ ------------- Other paid-in capital Beginning balance 2,203 1,614 Shares issued (less issuance costs of $8 and $9, respectively) 277 237 Contracted stock purchase payment obligations - (46) Employee stock awards - (1) ------------ ------------- 2,480 1,804 ------------ ------------- Retained earnings Beginning balance 1,739 1,733 Net income 101 59 Dividends (102) (91) ------------ ------------- 1,738 1,701 ------------ ------------- Accumulated other comprehensive income Beginning balance - derivative financial instruments 9 5 Change in derivative financial instruments in current period (3) (5) ------------ ------------- 6 - ------------ ------------- Beginning balance - minimum pension liability (102) - Change in minimum pension liability in current period - - ------------ ------------- (102) - ------------ ------------- (96) - ------------ ------------- Other Beginning balance (9) (4) Restricted stock compensation awards (5) (7) Compensation amortized and mark-to-market adjustments - 1 ------------ ------------- (14) (10) ------------ ------------- Total common stockholders' equity $ 4,110 $ 3,496 ============ ============= Comprehensive income, net of taxes Net income $ 101 $ 59 Unrealized net gain/(loss) on derivative hedging instruments, net of income taxes of $- and $-, respectively (1) (1) Reclassification adjustments for gains/(losses) included in net income, net of income taxes of $(1) and $(2), respectively (2) (4) ------------ ------------- Total comprehensive income, net of taxes $ 98 $ 54 ============ ============= - ------------------------------------------------------------------------------------------------------------------------- Common stock shares at beginning of period 154.1 138.0 Shares issued 7.0 6.2 ------------ ------------- Common stock shares at end of period 161.1 144.2 ============ ============= See Notes to Consolidated Financial Statements.
5 AMEREN CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) March 31, 2003 NOTE 1 - Summary of Significant Accounting Policies General Ameren Corporation is a public utility holding company registered with the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) and is headquartered in St. Louis, Missouri. Our 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. Our primary subsidiaries are as follows: o Union Electric Company, which operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois as AmerenUE. o Central Illinois Public Service Company, which operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP), which operates a rate-regulated electric transmission and distribution business, an electric generation business, and a rate-regulated natural gas distribution business in Illinois as AmerenCILCO. We completed our acquisition of CILCORP on January 31, 2003. See Note 2 - Acquisitions for further information. o AmerenEnergy Resources Company (Resources Company), which consists of non rate-regulated operations. Subsidiaries include AmerenEnergy Generating Company (Generating Company) which operates our non rate-regulated electric generation in Missouri and Illinois, AmerenEnergy Marketing Company (Marketing Company), which markets power for periods over one year, AmerenEnergy Fuels and Services Company, which procures fuel and manages the related risks for our affiliated companies and AmerenEnergy Medina Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric generation plant. On February 4, 2003, we completed our acquisition of AES Medina Valley Cogen (No. 4), LLC and renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Note 2 - Acquisitions for further information. o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and risk management agent for our affiliated companies for transactions of primarily less than one year. o Electric Energy, Inc. (EEI), which operates electric generation and transmission facilities in Illinois. We have a 60% ownership interest in EEI and consolidate it for financial reporting purposes. o Ameren Services Company, which provides shared support services to Ameren Corporation and its subsidiaries. When we refer to Ameren, our, we or us, we are referring to Ameren Corporation and its subsidiaries on a consolidated basis. In certain circumstances, our subsidiaries are specifically referenced in order to distinguish among their different business activities. The consolidated financial statements include the accounts of Ameren Corporation and its majority-owned subsidiaries. Results of CILCORP and AmerenCILCO include the period from the acquisition date of January 31, 2003 through March 31, 2003 and certain pro-forma financial information. See Note 2 - Acquisitions for further information. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated. The accounting policies of Ameren conform to generally accepted accounting principles in the United States (GAAP). Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our interim results. These statements should be read in conjunction with the financial statements and the notes thereto included in Ameren's and CILCORP and AmerenCILCO's 2002 Annual Reports on Form 10-K. 6 The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates. Certain reclassifications have been made to prior years' financial statements to conform to 2003 reporting. Earnings Per Share There was no difference between the basic and diluted earnings per share amounts for the three-month periods ended March 31, 2003 and 2002. The reconciling item in each of the periods was comprised of assumed stock option conversions, which increased the number of shares outstanding in the diluted earnings per share calculation by 239,883 shares for the three months ended March 31, 2003 compared to 351,794 shares for the three months ended March 31, 2002. Accounting Changes and Other Matters Statement of Financial Accounting Standards (SFAS) No. 143 - "Accounting for Asset Retirement Obligations" We adopted the provisions of SFAS 143 on January 1, 2003. SFAS 143 provides the accounting requirements for asset retirement obligations associated with tangible, long-lived assets. SFAS 143 requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value, and the corresponding increases in asset book values are depreciated over the useful life of the related asset. Uncertainties as to the probability, timing or cash flows associated with an asset retirement obligation affect our estimate of fair value. Upon adoption of this standard on January 1, 2003, we recognized additional asset retirement obligations of approximately $216 million and a net increase in net property and plant of approximately $110 million related primarily to the Callaway nuclear decommissioning costs and retirement costs for a river structure and a power plant ash pond. The difference between the net asset and the liability recorded upon adoption of SFAS 143 related to rate-regulated assets was recorded as an additional regulatory asset of approximately $136 million because we expect to continue to recover in electric rates the cost of Callaway nuclear decommissioning and other costs of removal. These asset retirement obligations and associated assets are in addition to assets and liabilities of $174 million we previously recorded related to our future obligations and funds accumulated to decommission the Callaway nuclear plant. In addition, we recognized a net after-tax gain upon adoption of $18 million resulting from a gain upon elimination of non-legal obligation costs of removal for non rate-regulated assets from accumulated depreciation ($20 million) and a loss for the difference between the net asset and liability for retirement obligations to be recorded upon adoption related to non rate-regulated assets ($2 million). During the first quarter of fiscal year 2003, our asset retirement obligations also increased as we assumed CILCORP's asset retirement obligations of approximately $6 million related to ash ponds in connection with our acquisition of CILCORP on January 31, 2003. Asset retirement obligations also increased due to accretion of $4 million recorded during the quarter ended March 31, 2003. In addition to those obligations that were identified and valued, we determined that certain other asset retirement obligations exist. However, we are unable to estimate the fair value of those obligations because the probability, timing or cash flows associated with the obligations are indeterminable. We do not believe that these obligations, when incurred, will have a material adverse impact on our financial position, results of operations or liquidity. 7 SFAS 143 required a change in the depreciation methodology we historically utilized for our non-regulated operations. Historically, we included an estimated cost of dismantling and removing plant from service upon retirement in the basis upon which our depreciation rates were determined. SFAS 143 required us to exclude costs of dismantling and removal upon retirement from the depreciation rates applied to non rate-regulated plant balances. Further, we were required to remove accumulated provisions for dismantling and removal costs from accumulated depreciation, where they were embedded, and reflect such adjustment as a gain upon adoption of this standard, to the extent such dismantling and removal activities are not considered legal asset retirement obligations as defined by SFAS 143. The elimination of cost of removal from accumulated depreciation resulted in a gain, as noted above, of $20 million, net of taxes, for a change in accounting principle. Beginning in January 2003, depreciation rates for non rate-regulated assets were reduced to reflect the discontinuation of the accrual of dismantling and removal costs. In addition, non rate-regulated asset removal costs will prospectively be expensed as incurred. As a result, the impact of this change in accounting will result in a decrease in depreciation expense and an increase in operations and maintenance expense, the net impact of which is indeterminable, but not expected to be material. Like our non rate-regulated operations, the depreciation methodology historically utilized by our rate-regulated operations has included an estimated cost of dismantling and removing plant from service upon retirement. Because these estimated costs of removal have been included in the cost of service upon which our present utility rates are based, and with the expectation that this practice will continue in the jurisdictions in which we operate, adoption of SFAS 143 did not result in any change in the depreciation accounting practices of our rate regulated operations. We have estimated future removal costs embedded in accumulated depreciation related to rate-regulated plant assets were approximately $660 million at March 31, 2003. Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10 In the quarters ended September 30, 2002 and December 31, 2002, we adopted the provisions of EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," that requires revenues and costs associated with certain energy contracts to be shown on a net basis in the income statement. Prior to adopting EITF 02-3 and the rescission of EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," our accounting practice was to present all settled energy purchase or sale contracts within our power risk management program on a gross basis in Operating Revenues - - Electric and Other and in Operating Expenses - Fuel and Purchased Power and Other Operations and Maintenance. This meant that revenues were recorded for the notional amount of the power sales contracts with a corresponding charge to income for the costs of the energy that was generated, or for the notional amount of a purchased power contract. In October 2002, the EITF reached a consensus to rescind EITF 98-10. The effective date for the full rescission of EITF 98-10 was for fiscal periods beginning after December 15, 2002, with early adoption permitted. In addition, the EITF reached a consensus in October 2002 that all SFAS No. 133 ("Accounting for Derivative Instruments and Hedging Activities") trading derivatives (subsequent to the rescission of EITF 98-10) should be shown net in the income statement, whether or not physically settled. This consensus applies to all energy and non-energy related trading derivatives that meet the definition of a derivative pursuant to SFAS 133. We have adopted and applied this guidance to 2002 and 2001, which had no impact on previously reported earnings or stockholders' equity. The operating revenues and costs netted for the three months ended March 31, 2002 were $241 million, which reduced interchange and other revenues and purchased power and other costs by equal amounts. The adoption of EITF 02-3, the rescission of EITF 98-10 and the related transition guidance resulted in netting of energy contracts and lowered our reported revenues and costs with no impact on earnings. SFAS No. 148 - "Accounting for Stock-Based Compensation - Transition and Disclosure" In December 2002, the FASB issued SFAS 148. SFAS 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for an entity that voluntarily 8 changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions to require disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation. Prior to 2003, we accounted for our stock options granted under long-term incentive plan under the recognition and measurement provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees." No stock-based employee compensation cost was reflected for options in 2002, 2001, and 2000 as all options granted under our plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The pretax effect of weighted-average grant-date fair value of options granted would have been approximately $2 million in each of the years ended 2002, 2001, and 2000 had the fair value method under SFAS 123 been used for options. Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS 123 by using the prospective method of adoption under SFAS 148. Because no stock options have been granted since January 1, 2003, SFAS 148 did not have any effect on our financial position, results of operations or liquidity in the first quarter of 2003. FASB Interpretation No. (FIN) 45 - "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" FIN 45 was issued in November 2002 and requires that upon issuance of certain guarantees, a guarantor must recognize a liability for the fair value of the obligation assumed under the guarantee. These recognition provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. FIN 45 also requires additional disclosures by a guarantor in its interim and annual financial statements for periods ending after December 15, 2002. Because we do not have such obligations, the recognition provisions of FIN 45 did not have any effect on our financial position, results of operations or liquidity in the first quarter of 2003. SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" In April 2003, SFAS 149 was issued. SFAS 149 clarifies under what circumstances a contract with initial net investment meets the characteristic of a derivative as discussed in SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 149 is effective for hedging relationships designated and contracts entered into or modified after June 30, 2003. At this time, we are assessing the impact of SFAS 149 on our financial position, results of operations and liquidity upon adoption. Revenue We accrue an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period. Interchange revenues included in Operating Revenues - Electric were $114 million for the three months ended March 31, 2003 (2002 - $81 million). Purchased Power Purchased power included in Operating Expenses - Fuel and Purchased Power was $45 million for the three months ended March 31, 2003 (2002 - $52 million). Excise Taxes Excise taxes on Missouri electric and gas, and Illinois gas customer bills are imposed on us and are recorded gross in Operating Revenues and Other Taxes. Excise taxes recorded in Operating Revenues and Other Taxes for the three months ended March 31, 2003 were $31 million (2002- $26 million). Excise taxes applicable to Illinois electric customer bills are imposed on the consumer and are recorded as tax collections payable and included in Taxes Accrued on the Consolidated Balance Sheet. 9 Goodwill Goodwill is the excess of the purchase price of an acquisition over the fair value of the net assets acquired. We do not amortize goodwill under the provisions of SFAS 142, "Goodwill and Other Intangible Assets." SFAS 142 requires the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired. NOTE 2 - Acquisitions On January 31, 2003, we completed our acquisition of all of the outstanding common stock of CILCORP from The AES Corporation. CILCORP is the parent company of Peoria, Illinois-based Central Illinois Light Company, which operated as CILCO. With the acquisition, CILCO became an Ameren subsidiary, but remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, we also completed our acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) which indirectly owns a 40 megawatt, gas-fired electric generation plant. With the acquisition, Medina Valley, which we renamed as AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned subsidiary of Resources Company. The results of operations for CILCORP and AmerenEnergy Medina Valley Cogen (No. 4), LLC were included in our consolidated financial statements effective with the January and February 2003 acquisition dates. We acquired CILCORP to complement our existing Illinois gas and electric operations. The purchase included CILCO's rate-regulated electric and natural gas businesses in Illinois serving approximately 200,000 and 205,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. CILCO's service territory is contiguous to our service territory. CILCO also has a non rate-regulated electric and gas marketing business principally focused in the Chicago, Illinois region. Finally, the purchase included approximately 1,200 megawatts of largely coal-fired generating capacity, most of which is expected to become non rate-regulated in 2003. The total purchase price was approximately $1.4 billion and included the assumption of CILCORP and Medina Valley debt and preferred stock at closing of $895 million and consideration of $488 million in cash including related acquisition costs, net of cash acquired. The purchase price is subject to certain adjustments for working capital and other changes pending the finalization of CILCORP's closing balance sheet. The cash component of the purchase price came from Ameren's issuances in September 2002 of 8.05 million common shares and its issuance in early 2003 of an additional 6.325 million common shares which together generated aggregate net proceeds of $575 million. The following unaudited pro forma financial information presents a summary of our combined results of operations assuming the acquisitions of CILCORP and Medina Valley had been completed at the beginning of fiscal year 2002 including pro forma adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase price to the acquired net assets. We are in the process of completing a third party valuation of acquired property and plant and intangible assets. Therefore, the allocation of the purchase price is subject to refinement. The excess of the purchase price over tangible net assets acquired has been allocated preliminarily to goodwill in the amount of $591 million. ================================================================================ Pro Forma Three Months - -------------------------------------------------------------------------------- 2003 2002 Operating revenues $ 1,208 $ 1,071 Income before cumulative effect of change in accounting principle 87 62 Cumulative effect of change in accounting principle net of taxes 22 - - -------------------------------------------------------------------------------- Net income $ 109 $ 62 Earnings per share -basic $ 0.67 $ 0.40 -diluted 0.67 0.40 - -------------------------------------------------------------------------------- 10 This pro forma information is not necessarily indicative of the results of operations as they would have been had the transactions been effected on the assumed date, nor is it an indication of trends in future results. NOTE 3 - Rate and Regulatory Matters Intercompany Transfer of Electric Generating Facilities As a part of the settlement of the Missouri electric rate case in 2002, AmerenUE committed to making certain infrastructure investments from January 1, 2002 through June 30, 2006. The requirements are expected to be satisfied in part by the proposed transfer at net book value to AmerenUE of approximately 550 megawatts (approximately $260 million) of combustion turbine generating units at Pinckneyville and Kinmundy, Illinois from Generating Company, which is subject to receipt of necessary regulatory approvals. Approval by the Missouri Public Service Commission (MoPSC) is not required in order for this transfer to occur. However, the MoPSC has jurisdiction over AmerenUE's ability to recover the cost of the transferred generating facilities from its electric customers in its rates. As a part of the settlement of the Missouri electric rate case in 2002, AmerenUE is subject to a rate moratorium providing for no changes in electric rates before June 30, 2006, subject to certain statutory and other exceptions. In February 2003, we sought approval from the Federal Energy Regulatory Commission (FERC) and the Illinois Commerce Commission (ICC) to transfer the 550 megawatts of generating assets from Generating Company to AmerenUE. Several independent power producers have objected to Ameren's request to the FERC based on a claim that the transfer may harm competition for the sale of electricity at wholesale. In April 2003, NRG Energy Inc. (NRG) and some of its affiliates, filed testimony contending that NRG's 640 megawatt generating facility at Vandalia, Missouri, known as the Audrain Facility, was a better resource for AmerenUE to acquire as compared to the Kinmundy and Pinckneyville combustion turbine generating units. In addition, in April 2003, in the ICC proceeding, the ICC Staff filed testimony which expressed concerns about the transfer as to whether it is the least cost resource for AmerenUE and recommended that the ICC deny approval of the transfer. AmerenUE will have an opportunity to file testimony responding to the recommendations of the ICC Staff and NRG. On May 5, 2003, the FERC issued an order which set for hearing the effect of the proposed transfer on competition in wholesale electric markets. We will have an opportunity to file testimony addressing this issue at the hearing to be scheduled. We can not predict the ultimate outcome of these proceedings or the timing of the decisions of the FERC and the ICC. Affiliate Rules On April 22, 2003, the Missouri Supreme Court issued an opinion upholding the adoption of affiliate rules by the MoPSC for Missouri's gas and electric utilities. AmerenUE had objected to the Missouri asymmetric pricing provisions contained in the rules. These provisions require that the utility pay the lower of cost or market when it is receiving services from an affiliate, and charge the higher of cost or market when it is providing services to an affiliate. In general, the rules are intended to prevent regulated utilities from subsidizing their affiliates' non rate-regulated operations. As a registered holding company under the PUHCA, Ameren and its affiliates are already subject to extensive regulation designed to prevent cross-subsidization. The asymmetric pricing provisions of the MoPSC affiliate rules are expected to impose additional administrative burdens on AmerenUE. In May 2003, AmerenUE filed with the Missouri Supreme Court a motion for reconsideration of its April 22, 2003 opinion. We do not expect that the rules would have a material adverse impact on our future financial position, cash flows or results of operations in the event that AmerenUE's motion is denied. 11 Regional Transmission Organization Since April 2002, AmerenCIPS and AmerenUE and subsidiaries of FirstEnergy Corporation and NiSource Inc. (collectively the GridAmerica Companies) have participated in a number of filings at the FERC in an effort to form GridAmerica LLC as an independent transmission company (ITC). On December 19, 2002, the FERC issued an order conditionally approving the formation and operation of GridAmerica as an ITC within the Midwest Independent System Operator (Midwest ISO), subject to further compliance filings. In response to the December 19, 2002 order, the GridAmerica Companies made three additional filings at the FERC. On January 31, 2003 the GridAmerica Companies filed a request for authorization to transfer functional control of certain transmission assets to GridAmerica. On February 18, 2003, the GridAmerica Companies filed revised agreements codifying the formation and operation of GridAmerica to reflect changes requested by the FERC in the December 19, 2002 order. On February 28, 2003, the GridAmerica Companies together with the Midwest ISO filed revisions to the Midwest ISO Open Access Transmission Tariff (OATT) to provide rates for service over the transmission facilities to be transferred to GridAmerica by the GridAmerica Companies. On April 30 2003, the FERC issued orders in response to the January 31, 2003 and February 28, 2003 filings. In its order regarding the GridAmerica Companies' request to transfer functional control of their transmission assets to GridAmerica, the FERC authorized the transfer. In response to the February 28, 2003 filing, the FERC accepted the amendments to the Midwest ISO OATT effective upon the commencement of service over the GridAmerica transmission facilities under the Midwest ISO OATT, suspended the proposed rates for a nominal period, subject to refund, and established hearing and settlement judge procedures to determine the justness and reasonableness of the proposed rate amendments to the Midwest ISO OATT. An order in response to the February 18, 2003 filing is still pending. Until the tariffs and other material terms of AmerenCIPS' and AmerenUE's participation in GridAmerica, and GridAmerica's participation in the Midwest ISO, are finalized and approved by the FERC, we are unable to predict the impact that on-going regional transmission organization developments will have on our financial position, results of operations or liquidity. AmerenUE's participation in GridAmerica is subject to MoPSC approval. An order from the MoPSC is expected during 2003. Standard Market Design Notice of Proposed Rulemaking (NOPR) On July 31, 2002, the FERC issued a Standard Market Design NOPR. The NOPR proposes a number of changes to the way the current wholesale transmission service and energy markets are operated. Specifically, the NOPR calls for all jurisdictional transmission facilities to be placed under the control of an independent transmission provider (similar to an RTO), proposes a new transmission service tariff that provides a single form of transmission service for all users of the transmission system including bundled retail load, and proposes a new energy market and congestion management system that uses locational marginal pricing as its basis. On November 15, 2002, Ameren filed its initial comments on the NOPR with the FERC expressing concern with the potential impact of the proposed rules in their current form on the cost and reliability of service to retail customers. We also proposed that certain modifications be made to the proposed rules in order to protect transmission owners from the possibility of trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies. We filed additional comments on the remaining sections of the NOPR during the first quarter of 2003. On April 28, 2003 the FERC issued a "white paper" reflecting comments received in response to the NOPR. More specifically, the white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service and will insure that existing bundled retail customers retain their existing transmission rights and retain rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule's implementation. 12 Even though issuance of the final rule and its implementation schedule are still unknown, the Midwest ISO is already in the process of implementing a market design similar to the proposed market design in the NOPR. The Midwest ISO has targeted March 2004 as the start date for implementation. We are in the process of reviewing the FERC's white paper. Until the FERC issues a final rule, we are unable to predict the ultimate impact on our future financial position, results of operations or liquidity. Illinois Gas In November 2002, AmerenCIPS, AmerenUE, and CILCO filed requests with the ICC to increase annual rates for natural gas service by approximately $16 million, $4 million and $14 million, respectively. The ICC has until October 2003 to render a decision in the AmerenCIPS, AmerenUE and CILCORP gas cases; however, the ICC Staff has recommended the annual increase to be $8 million, $2 million and $9 million, respectively. Missouri Gas In May 2003, AmerenUE expects to file a request with the MoPSC to increase annual rates for natural gas service. NOTE 4 - Derivative Financial Instruments As of March 31, 2003, we recorded the fair value of derivative financial instrument assets of $11 million in Other Assets and the fair value of derivative financial instrument liabilities of $11 million in Other Deferred Credits and Liabilities. Cash Flow Hedges The pretax net gain or loss on power forward derivative instruments, which represented the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, as well as the reversal of amounts previously recorded in Accumulated Other Comprehensive Income (OCI) due to transactions going to delivery or settlement, was approximately a $1 million loss for the three months ended March 31, 2003 (2002 - $1 million gain). As of March 31, 2003, we had hedged a portion of the electricity price exposure for the upcoming twelve-month period. The mark-to-market value accumulated in OCI for the effective portion of hedges of electricity price exposure was a net gain of approximately $2 million ($1 million, net of taxes). As of March 31, 2003, a gain of approximately $6 million ($4 million, net of taxes) associated with interest rate swaps was included in OCI. The swaps were a partial hedge of the interest rate on debt that was issued in June 2002. The swaps cover the first ten years of debt that has a 30-year maturity and the gain in OCI is amortized over a ten-year period that began in June 2002. We also hold two call options for coal with two suppliers. These options to purchase coal expire October 2003 and July 2005. As of March 31, 2003, a mark-to-market gain of approximately $6 million ($4 million, net of taxes) associated with these options was included in OCI. The final value of the options will be recognized as a reduction in fuel costs as the hedged coal is burned. As of March 31, 2003, EEI, CILCORP and Medina Valley had losses of approximately $1 million each included in OCI (less than $1 million each, net of taxes). 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 13 net change in the market value of sulfur dioxide options is recorded as Operating Revenues - Electric, while the net change in the market value of coal, heating oil and electricity options is recorded as Operating Expenses - Fuel and Purchased Power in the income statement. The net change in the market values ofsulfur dioxide, coal, heating oil and electricity options was a gain of $1 million (less than $1 million, net of taxes) for the three months ended March 31, 2003 (2002 - gain of $2 million). NOTE 5 - Property and Plant, Net Property and plant, net at March 31, 2003 and December 31, 2002 consisted of the following: ====================================================================================================== - ------------------------------------------------------------------------------------------------------ March 31, December 31, 2003 2002 ====================================================================================================== Property and plant, at original cost: Electric $ 15,665 $ 14,495 Gas 719 557 Other 189 145 - ------------------------------------------------------------------------------------------------------ 16,573 15,197 Less accumulated depreciation and amortization 6,974 6,831 - ------------------------------------------------------------------------------------------------------ 9,599 8,366 Construction work in progress: Nuclear fuel in process 82 81 Other 501 393 - ------------------------------------------------------------------------------------------------------ Property and plant, net $ 10,182 $ 8,840 ======================================================================================================
NOTE 6 - Debt and Equity Financings Ameren Corporation In August 2002, a shelf registration statement filed by Ameren Corporation with the SEC on Form S-3 was declared effective. This statement authorized the offering from time to time of up to $1.473 billion of various forms of securities including long-term debt, and trust preferred and equity securities to finance ongoing construction and maintenance programs, to redeem, repurchase, repay, or retire outstanding debt, to finance strategic investments, including our then pending acquisition of CILCORP, and for general corporate purposes. In the first quarter of 2003, Ameren issued, pursuant to the shelf registration statement, 6.325 million shares of its common stock at $40.50 per share. We received net proceeds after fees of $248 million, which were used to fund the remaining cash portion of the purchase price for our acquisition of CILCORP. See Note 2 - Acquisitions for further information. We may sell all, or a portion of, the remaining securities registered under the shelf registration statement if warranted by market conditions and our capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder. In 2002 and in the first quarter of 2003, $594 million was issued under the shelf registration statement. At April 30, 2003, the amount remaining on the shelf registration statement was approximately $879 million. The purchase of CILCORP on January 31, 2003 and Medina Valley on February 4, 2003 included the assumption of CILCORP and Medina Valley debt and preferred stock at closing of $895 million. The assumed debt primarily consisted of $250 million 9.375% first mortgage bonds due 2029, $225 million 8.7% first mortgage bonds due 2009, $100 million floating rate term loan due 2004, other secured indebtedness totaling $279 million and preferred stock of $41 million. Subsequent to the acquisition date, the other secured indebtedness was reduced by $101 million through maturities and redemptions funded with a combination of available cash and short-term intercompany borrowings. 14 At March 31, 2003, neither Ameren Corporation, nor any of its subsidiaries, had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. At this time, we do not expect to engage in any significant off-balance sheet financing arrangements. Amortization of debt issuance costs and any premium or discounts for the three months ended March 31, 2003 of $2 million (2002 - $2 million) were included in interest expense in the income statement. Amortization related to recording the fair value of debt assumed upon the acquisition of CILCORP was less than $1 million for the two months ended March 31, 2003. The amortization was included in interest expense in the income statement. At March 31, 2003, Ameren and its subsidiaries were in compliance with their indenture and credit agreement provisions and covenants. AmerenUE In August 2002, a shelf registration statement filed by AmerenUE with the SEC on Form S-3 was declared effective. This statement authorized the offering from time to time of up to $750 million of various forms of long-term debt and trust preferred securities to refinance existing debt and preferred stock, and for general corporate purposes, including the repayment of short-term debt incurred to finance construction expenditures and other working capital needs. In March 2003, AmerenUE issued, pursuant to the shelf registration, $184 million of 5.50% Senior Secured Notes due March 15, 2034. AmerenUE received net proceeds after fees of $180 million, which, along with other funds, were used to redeem $104 million principal amount of outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption price of 103.61% of par, plus accrued interest, in April 2003, prior to maturity, and to repay short-term debt incurred to pay at maturity $75 million principal amount of 8.33% first mortgage bonds that were due in December 2002. In April 2003, AmerenUE issued, pursuant to the shelf registration, $114 million of 4.75% Senior Secured Notes due April 1, 2015. AmerenUE received net proceeds after fees of $113 million, which, along with other funds were used to redeem $85 million principal amount of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce short-term money pool debt. AmerenUE may sell all, or a portion of, the remaining securities registered under the AmerenUE shelf registration statement if warranted by market conditions and our capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder. At April 30, 2003, the amount remaining on the shelf registration statement was approximately $279 million. On April 1, 2003, AmerenUE entered into an additional 364-day committed credit facility totaling $75 million to be used for general corporate purposes, including support of commercial paper programs. This facility makes borrowings available at various interest rates based on LIBOR, agreed rates and other options. Ameren and AmerenCIPS can access this facility through the utility money pool. AmerenCIPS On April 7, 2003, AmerenCIPS redeemed, with cash, prior to maturity and at par our $50 million first mortgage bonds 7.5% Series X due July 1, 2007. 15 NOTE 7 - Miscellaneous, Net Miscellaneous, net for the three months ended March 31, 2003 and 2002 consisted of the following: ======================================================================================================= Three Months - ------------------------------------------------------------------------------------------------------- 2003 2002 Miscellaneous income: Interest and dividend income $ 1 $ - Other 5 3 - ------------------------------------------------------------------------------------------------------- Total miscellaneous income $ 6 $ 3 ======================================================================================================= Miscellaneous expense: Minority interest in EEI $ (1) $ (1) Donations - (1) Other (2) (2) - ------------------------------------------------------------------------------------------------------- Total miscellaneous expense $ (3) $ (4) =======================================================================================================
NOTE 8 - Segment Information Ameren's principal business segment is comprised of the utility operating companies that provide electric and gas service in portions of Missouri and Illinois. The other reportable segment includes our nonutility subsidiaries, as well as our 60% interest in EEI. The accounting policies of the segments are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge allocating costs of administrative support services to each of the operating companies. These costs are accumulated in a separate subsidiary, Ameren Services Company, which provides a variety of support services to Ameren and its subsidiaries. We evaluate the performance of our segments and allocate resources to them, based on revenues, operating income and net income. Segment information for the three months ended March 31, 2003 and 2002 was as follows: ======================================================================================================= Utility Intercompany Operations Other Revenues Total - ------------------------------------------------------------------------------------------------------- Three months ended March 31, 2003: Revenues $ 1,247 $ 47 $ (186) $ 1,108 Net income 102 (1) - 101 - ------------------------------------------------------------------------------------------------------- Three months ended March 31, 2002: Revenues $ 995 $ 69 $ (190) $ 874 Net income 58 1 - 59 - -------------------------------------------------------------------------------------------------------
Ameren Services Company, which provides shared support services to us and our subsidiaries, allocates administrative support services to each segment based on various factors, such as headcount, number of customers, and total assets. 16 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations OVERVIEW Ameren Corporation is a public utility holding company registered with the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) and is headquartered in St. Louis, Missouri. Our 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. Our primary subsidiaries are as follows: o Union Electric Company, which operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois as AmerenUE. o Central Illinois Public Service Company, which operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP), which operates a rate-regulated electric transmission and distribution business, an electric generation business, and a rate-regulated natural gas distribution business in Illinois as AmerenCILCO. We completed our acquisition of CILCORP on January 31, 2003. See Recent Developments for further information. o AmerenEnergy Resources Company (Resources Company), which consists of non rate-regulated operations. Subsidiaries include AmerenEnergy Generating Company (Generating Company) which operates non rate-regulated electric generation in Missouri and Illinois, AmerenEnergy Marketing Company (Marketing Company), which markets power for periods over one year, AmerenEnergy Fuels and Services Company, which procures fuel and manages the related risks for our affiliated companies and AmerenEnergy Medina Valley Cogen (No. 4), LLC which indirectly owns a 40 megawatt, gas-fired electric generation plant. On February 4, 2003, we completed our acquisition of AES Medina Valley Cogen (No. 4), LLC and renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Recent Developments for further information. o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and risk management agent for our affiliated companies for transactions of primarily less than one year. o Electric Energy, Inc. (EEI), which operates electric generation and transmission facilities in Illinois. We have a 60% ownership interest in EEI and consolidate it for financial reporting purposes. o Ameren Services Company, which provides shared support services to Ameren Corporation and its subsidiaries. You should read the following discussion and analysis in conjunction with: o The financial statements and related notes included in this Quarterly Report on Form 10-Q. o Management's Discussion and Analysis of Financial Condition and Results of Operations that is incorporated by reference from our 2002 Annual Report to Shareholders into our Annual Report on Form 10-K for the period ended December 31, 2002. o The audited financial statements and related notes that are incorporated by reference from our 2002 Annual Report to Shareholders into our Annual Report on Form 10-K for the period ended December 31, 2002. o Management's Discussion and Analysis of Financial Condition and Results of Operations in CILCORP and AmerenCILCO's Annual Report on Form 10-K for the period ended December 31, 2002. o The audited financial statements and related notes in CILCORP and AmerenCILCO's Annual Report on Form 10-K for the period ended December 31, 2002. When we refer to Ameren, our, we or us, we are referring to Ameren Corporation and its subsidiaries on a consolidated basis. In certain circumstances, our subsidiaries are specifically referenced in order to distinguish among their different business activities. All tabular dollar amounts are in millions, unless otherwise indicated. Results of CILCORP and AmerenCILCO include the period from the acquisition date of January 31, 2003 through March 31, 2003. 17 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 approximately 85% of our revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. We principally utilize coal, nuclear fuel, natural gas and oil in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, production levels and many other factors. We do not have fuel cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas utility businesses. In addition, our electric rates in Missouri and Illinois are largely set through 2006. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants, and transmission and distribution systems, and the level of operating and administrative costs, and capital investment are key factors that we seek to control in order to optimize our results of operations, cash flows and financial position. RESULTS OF OPERATIONS Earnings Summary Our net income increased to $101 million or 63 cents per share in the first quarter of 2003 from $59 million or 42 cents per share in the first quarter of 2002. Net income in the first quarter of 2003 included a net cumulative effect gain of $18 million, or 11 cents per share, associated with the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." The net gain resulted principally from the elimination of non-legal obligation costs of removal for non rate-regulated assets from accumulated depreciation. Excluding the cumulative effect of change in accounting principle related to SFAS 143, net income increased $24 million or 10 cents per share in the first quarter of 2003 compared to the prior year period. The increase was primarily due to favorable weather conditions in our pre-CILCORP acquisition service territory (10 cents per share), increased electric margins due to greater use of low-cost generating units to serve native customers (4 cents per share) and increased earnings from interchange sales (16 cents per share) due to approximately 90% higher power prices in the energy markets than the prior period. In Ameren's pre-CILCORP acquisition service territory, weather-sensitive residential electric kilowatthour sales increased by 14%, commercial electric kilowatthour sales increased by 5% and gas sales increased 6% in the first quarter of 2003 compared to the first quarter of 2002. Partially offsetting the benefit on net income of weather, interchange margins and generation availability in the first quarter of 2003 was increased dilution and financing costs outside of those incurred in connection with the CILCORP acquisition (5 cents per share), higher employee benefit costs (5 cents per share) related to plan performance and increasing healthcare costs and no sales of emission credits in 2003 (5 cents per share). In addition, the impact of the acquisition of CILCORP and related financings, resulted in a reduction to earnings per share in the first quarter of 2003 of approximately 2 cents. We continue to believe CILCORP will be accretive to earnings in year one as we realize the synergies associated with this acquisition and a full year of operations. As a holding company, our net income and cash flows are primarily generated by our principal operating subsidiaries, AmerenUE, AmerenCILCO, AmerenCIPS and Generating Company. These subsidiaries also file quarterly and annual reports with the SEC. The contribution by our principal operating subsidiaries to net income for the three months ended March 31, 2003 and 2002 was as follows: 18 ======================================================================================================= Three Months 2003 2002 Primarily rate-regulated operations AmerenUE (a) $ 67 $ 49 CILCORP (b) 3 - AmerenCIPS 1 1 - ------------------------------------------------------------------------------------------------------- $ 71 $ 50 - ------------------------------------------------------------------------------------------------------- Primarily non rate-regulated operations Generating Company (a)(c) 39 13 Other (9) (4) - ------------------------------------------------------------------------------------------------------- Ameren net income $ 101 $ 59 =======================================================================================================
(a) Includes earnings from interchange sales by AmerenEnergy that provided approximately $22 million (2002 - $5 million) of AmerenUE's net income and $12 million (2002 - $3 million) of Generating Company's net income in the first quarter of 2003. (b) Most of CILCORP's electric generation business is expected to become non rate-regulated in 2003 with the transfer of substantially all of its generating assets to a non rate-regulated subsidiary. (c) Includes earnings from contracts to supply power to our rate-regulated AmerenCIPS customers. Recent Developments Acquisitions On January 31, 2003, we completed our acquisition of all of the outstanding common stock of CILCORP from The AES Corporation. CILCORP is the parent company of Peoria, Illinois-based Central Illinois Light Company, which operated as CILCO. With the acquisition, CILCO became an Ameren subsidiary, but remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, we also completed our acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) which indirectly owns a 40 megawatt, gas-fired electric generation plant. With the acquisition, Medina Valley, which we renamed as AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned subsidiary of Resources Company. The results of operations for CILCORP and AmerenEnergy Medina Valley Cogen (No. 4), LLC were included in our consolidated financial statements effective with the January and February 2003 acquisition dates. We acquired CILCORP to complement our existing Illinois gas and electric operations. The purchase included CILCO's rate-regulated electric and natural gas businesses in Illinois serving approximately 200,000 and 205,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. CILCO's service territory is contiguous to our service territory. CILCO also has a non rate-regulated electric and gas marketing business principally focused in the Chicago, Illinois region. Finally, the purchase included approximately 1,200 megawatts of largely coal-fired generating capacity, most of which is expected to become non rate-regulated in 2003. The total purchase price was approximately $1.4 billion and included the assumption of CILCORP and Medina Valley debt and preferred stock at closing of $895 million and consideration of $488 million in cash including related acquisition costs, net of cash acquired. The purchase price is subject to certain adjustments for working capital and other changes pending the finalization of CILCORP's closing balance sheet. The cash component of the purchase price came from Ameren's issuances in September 2002 of 8.05 million common shares and its issuance in early 2003 of an additional 6.325 million common shares which together generated aggregate net proceeds of $575 million. 19 Common Stock Offering In the first quarter of 2003, Ameren sold 6.325 million shares of common stock at $40.50 per share. We received net proceeds after fees of $248 million, which were used to fund a portion of the purchase price for our acquisition of CILCORP and for general corporate purposes. Debt Issuances In March 2003, AmerenUE issued $184 million of 5.50% Senior Secured Notes due March 15, 2034. AmerenUE received net proceeds after fees of $180 million, which, along with other funds, were used to redeem $104 million principal amount of outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption price of 103.61% of par, plus accrued interest, in April 2003, prior to maturity, and to repay short-term debt incurred to pay at maturity $75 million principal amount of 8.33% first mortgage bonds due in December 2002. In April 2003, AmerenUE issued $114 million of 4.75% Senior Secured Notes due April 1, 2015. AmerenUE received net proceeds after fees of $113 million, which, along with other funds were used to redeem $85 million principal amount of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce short-term money pool debt. Credit Ratings In April 2002, as a result of AmerenUE's then pending Missouri electric earnings complaint case and the CILCORP transaction and related assumption of debt, credit rating agencies placed Ameren Corporation's and its subsidiaries' debt under review. Following the completion of the acquisition of CILCORP in January 2003, Standard & Poor's lowered the ratings of Ameren Corporation, AmerenUE and AmerenCIPS and increased the ratings of Generating Company, CILCORP and AmerenCILCO. At the same time, Standard & Poor's changed the outlook assigned to all of Ameren's ratings to stable. Moody's also lowered Ameren Corporation's and AmerenUE's ratings subsequent to the acquisition and changed the outlook on these ratings to stable. These actions were consistent with the actions the rating agencies disclosed they were considering following the announcement of the CILCORP acquisition. As of April 30, 2003, selected ratings by Moody's and Standard & Poor's were as follows: ======================================================================================================= Moody's Standard & Poor's - ------------------------------------------------------------------------------------------------------- Ameren Corporation: Issuer/Corporate credit rating A3 A- Unsecured debt A3 BBB+ Commercial paper P-2 A-2 AmerenUE: Secured debt A1 A- Unsecured debt A2 BBB+ Commercial paper P-1 A-2 CILCORP: Unsecured debt Baa2 BBB+ AmerenCILCO: Secured debt A2 A- AmerenCIPS: Secured debt A1 A- Unsecured debt A2 BBB+ Generating Company: Unsecured debt A3/Baa2 A- =======================================================================================================
20 Any adverse change in our credit ratings may reduce our access to capital and/or increase the costs of borrowings resulting in a negative impact on earnings. A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. Electric Operations The following table represents the favorable (unfavorable) variation on electric margin for the three months ended March 31, 2003 from the comparable period in 2002: ================================================================================ Three Months - -------------------------------------------------------------------------------- Electric Revenues: CILCORP $ 80 Interchange revenues 36 Effect of weather (estimate) 28 Rate reductions (11) Growth and other (estimate) (12) EEI (12) - -------------------------------------------------------------------------------- Total variation in electric operating revenues 109 Fuel and Purchased Power: Fuel: Generation $(13) Price (1) Generation efficiencies and other 1 Purchased power 23 CILCORP (35) EEI 7 - -------------------------------------------------------------------------------- Total variation in fuel and purchased power (18) ================================================================================ Change in electric margin $ 91 ================================================================================ Electric margin increased $91 million for the three months ended March 31, 2003 compared to the same period in 2002. Increases in electric margin in the first quarter of 2003 were primarily attributable to the acquisition of CILCORP, increased interchange margins and higher native load customer demand resulting from colder winter weather. CILCORP's electric margin for the two month period ended March 31, 2003 was approximately $45 million. Residential kilowatthour sales increased 22% and commercial kilowatthour sales increased 14% in the first quarter of 2003. Industrial sales were also up approximately 24% in the quarter compared to the same period in 2002 due primarily to the addition of CILCORP. Excluding CILCORP, industrial sales decreased in the first quarter of 2003 by 4% due to the continued soft economy. Interchange margins increased due to improved power prices in the energy markets and solid low-cost generation availability. Average power prices increased from approximately $22 per megawatthour in the first quarter of 2002 to approximately $42 per megawatthour in the first quarter of 2003. EEI sales decreased compared to the prior period due to decreased sales to its principal customer, which also resulted in a decrease in fuel and purchased power. No sales of emission credits at AmerenUE in 2003 (2002 - $13 million) and rate reductions in Missouri relating to a 2002 rate settlement ($11 million) negatively impacted electric revenues in the first quarter of 2003. Revenues will continue to be negatively affected by the settlement of the Missouri electric rate case, which requires the phase-in of $30 million of electric rate reductions effective April 1, 2003 and $30 million effective April 1, 2004. Fuel and purchased power increased in the first quarter of 2003 compared to the prior period due to increased kilowatthour sales related primarily to the addition of CILCORP to our results. Excluding the addition of CILCORP, fuel and purchased power costs decreased approximately $17 million in the first quarter of 2003 due to greater availability of low-cost generation. During 2002, we adopted the provisions of Emerging Issues Task Force (EITF) Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," that required revenues and costs associated with certain energy contracts to be shown on a net basis in the income statement. The operating revenues and costs 21 netted for the three months ended March 31, 2002 were $241 million, which reduced interchange and other revenues and purchased power and other costs by equal amounts. See Note 1 - Summary of Significant Accounting Policies to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. Gas Operations Our gas margin increased $25 million in the first quarter of 2003, compared to the first quarter of 2002, with revenues increasing by $125 million and costs increasing by $100 million. The increase in margin was primarily due to the acquisition of CILCORP ($20 million) and increased customer demand resulting from colder winter weather. Other Operating Expenses Other Operations and Maintenance Other operations and maintenance expenses increased $37 million in the first quarter of 2003, compared to the first quarter of 2002, primarily due to the addition of CILCORP's other operations and maintenance expenses (approximately $29 million) and higher employee benefit costs ($12 million) related to increasing healthcare costs and the investment performance of employee benefit plans' assets. Depreciation and Amortization Depreciation and amortization expenses increased $17 million in the first quarter of 2003 compared to the prior period. The increase was primarily due to the addition of CILCORP's depreciation and amortization ($14 million), the completion of four combustion turbine generating units in the third and fourth quarter 2002 at Generating Company and the completion of four combustion turbine generating units at AmerenUE in May 2002. These increases were partially offset by a reduction of depreciation rates based on an updated analysis of asset values, service lives and accumulated depreciation levels that was included in our 2002 Missouri electric rate case settlement ($5 million). Income Taxes Income tax expense increased $14 million in the first quarter of 2003, compared to the 2002 period, primarily due to higher pretax income. Other Taxes Other taxes expense increased $10 million in the first quarter of 2003, compared to the 2002 period, primarily due to an increase in gross receipts taxes related to increased native sales ($5 million), as well as the acquisition of CILCORP. Other Income and Deductions Other income and deductions (excluding income taxes) for the three months ended March 31, 2003 were comparable to the 2002 period. See Note 7 - Miscellaneous, Net to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. Interest Interest expense increased $16 million in the first quarter of 2003, compared to the 2002 period, primarily due to the assumption of CILCORP debt ($9 million), the interest expense component associated with the $345 million of adjustable conversion rate equity security units we issued in March 2002, and Generating Company's issuance of $275 million of 7.95% notes in June 2002, partially offset by lower interest rates. 22 LIQUIDITY AND CAPITAL RESOURCES Operating Our cash flows provided by operating activities totaled $215 million for the first quarter of 2003, compared to $110 million for the same period in 2002. Cash provided from operations increased in 2003, primarily as a result of higher cash earnings resulting from higher electric and gas margins and the timing of payments on accounts payable. The tariff-based gross margins of our rate-regulated utility operating companies continue to be our principal source of cash from operating activities. Our diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. In addition, we plan to utilize short-term debt to support normal operations and other temporary capital requirements. Investing Our net cash used in investing activities was $618 million in the first quarter of 2003 compared to $160 million for the same period in 2002. The increase over the prior year period was primarily related to the cash paid of $488 million for the acquisition of CILCORP on January 31, 2003 and Medina Valley on February 4, 2003. In addition, in the first quarter of 2003, construction expenditures in our rate-regulated operations were $133 million (2002 - $122 million), primarily related to various upgrades at our power plants. Construction expenditures in our non rate-regulated operations of $11 million in the first quarter of 2003 (2002 - $37 million) decreased from the first quarter of 2002 due to reduced construction of combustion turbine generating units. Capital expenditures relating to our rate-regulated and non rate-regulated operations are expected to approximate $640 million and $35 million, respectively, in 2003. We continually review our generation portfolio and expected electrical needs, and as a result, we could modify our plan for generation asset purchases, which could include the timing of when certain assets will 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 Ameren may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material. Financing Our cash flows provided by financing activities totaled $69 million in the first quarter of 2003 and $43 million for the comparable period in 2002. Our principal financing activities for the first quarter of 2003 included the issuances of long-term debt and common stock, partially offset by redemptions of short-term and long-term debt, as well as payments of dividends. In addition to the activities above, the first quarter of 2002 also included issuances of adjustable conversion-rate equity security units. Ameren Corporation and AmerenUE are authorized by the SEC under the PUHCA to have up to an aggregate of $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. In addition, AmerenCIPS, AmerenCILCO and CILCORP have the PUHCA authority to have up to an aggregate of $250 million each of short-term unsecured debt instruments outstanding at any time. Generating Company is authorized by the Federal Energy Regulatory Commission (FERC) to have up to $300 million of short-term debt outstanding at any time. Short-Term Debt and Liquidity Short-term debt consists of commercial paper and bank loans (maturities generally within 1 to 45 days). At March 31, 2003, Ameren had committed credit facilities, expiring at various dates between 2003 and 2005, totaling $694 million, excluding AmerenCILCO of $60 million, EEI of $45 million and nuclear 23 fuel lease facilities of $120 million. All of these amounts were available for use by two of our rate-regulated subsidiaries, (AmerenUE and AmerenCIPS), and Ameren Services Company, and $600 million of this amount was available for use by Ameren Corporation and most of our non rate-regulated subsidiaries including, but not limited to, Resources Company, Generating Company, Marketing Company, AmerenEnergy Fuels and Services Company and AmerenEnergy. AmerenCILCO may also access $600 million of these facilities through direct borrowings from Ameren Corporation. These committed credit facilities are used to support our commercial paper programs under which no amounts were outstanding at March 31, 2003. At March 31, 2003, $694 million was unused and available under these committed credit facilities. Subject to the receipt of regulatory approval, which is being pursued, AmerenCILCO will participate in Ameren's utility money pool arrangement. Under this arrangement, AmerenCILCO will have access to up to $694 million of additional committed liquidity, subject to reduction based on the use by other utility money pool participants, but increased to the extent other pool participants have surplus cash balances, which may be used to fund pool needs. CILCORP participates in Ameren's non-utility money pool arrangement, which provides it access to up to $600 million of committed liquidity, subject to reduction based on use by other pool participants, which may also be supplemented by available cash balances among pool participants. On April 1, 2003, AmerenUE entered into an additional 364-day committed credit facility totaling $75 million to be used for general corporate purposes, including support of commercial paper programs. This facility makes borrowings available at various interest rates based on LIBOR, agreed rates and other options. Ameren and AmerenCIPS can access this facility through the utility money pool. We also have two bank credit agreements totaling $45 million that expire in 2003 at EEI. At March 31, 2003, $32 million was unused and available under these committed credit facilities. AmerenUE also has a lease agreement that provides for the financing of nuclear fuel. At March 31, 2003, the maximum amount that could be financed under the agreement was $120 million. At March 31, 2003, $111 million was financed under the lease. In addition to committed credit facilities, a further source of liquidity for Ameren is available cash and cash equivalents. At March 31, 2003, we had $294 million of cash. In the first quarter of 2003, we paid a total of $488 million of cash on hand, including related acquisition costs, net of cash acquired to acquire CILCORP and Medina Valley. We rely on access to short-term and long-term capital markets as a significant source of funding for capital requirements not satisfied by our operating cash flows. The inability by us to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets such that our cost of capital would increase or our ability to access the capital markets would be adversely affected. Indenture and Credit Agreement Provisions and Covenants Our financial agreements include customary default or cross default provisions that could impact the continued availability of credit or result in the acceleration of repayment. Ameren's committed credit facilities require the borrower to represent, in connection with any borrowing under the facility that no material adverse change has occurred since certain dates. Ameren's financing arrangements do not contain credit rating triggers, except for three funded bank term loans at AmerenCILCO totaling $105 million at March 31, 2003. Ameren's committed credit facilities include provisions related to the funded status of Ameren's pension plan. These provisions either require Ameren to meet the minimum Employee Retirement Income Security Act of 1974 (ERISA) funding requirements or limit the unfunded liability status of the plan. 24 Under the most restrictive of these provisions impacting facilities totaling $400 million, an event of default will result if the unfunded liability status (as defined in the underlying credit agreements) of Ameren's pensionplan exceeds $300 million in the aggregate. Based on the most recent valuation report available to Ameren at December 31, 2002, which was based on January 2002 asset and liability valuations, the unfunded liability status (as defined) was $31 million. While an updated valuation report will not be available until the second half of 2003, we believe that the unfunded liability status of our pension plans (as defined) could exceed $300 million based on the investment performance of the pension plan assets and interest rate changes since January 1, 2002. As a result, we may need to renegotiate the facility provisions, terminate or replace the affected facilities, or fund any unfunded liability shortfall. Should we elect to terminate these facilities, we believe we would otherwise have sufficient liquidity to manage our short-term funding requirements. At March 31, 2003, Ameren and its subsidiaries were in compliance with their indenture and credit agreement provisions and covenants. Debt and Equity Financings See Note 6 - Debt and Equity Financings to our Consolidated Financial Statements under Item 1 of Part I of this report for further information about financings during the first quarter of 2003. Dividends Our Board of Directors does not set specific targets or payout parameters when declaring common stock dividends. However, the Board considers various issues, including our historic earnings and cash flow; projected earnings; cash flow and potential cash flow requirements; dividend payout rates at other utilities; return on investments with similar risk characteristics; and overall business considerations. On April 22, 2003, our Board of Directors declared a quarterly common stock dividend of 63.5 cents per share that will be paid on June 30, 2003 to shareholders of record on June 11, 2003. Off-Balance Sheet Arrangements At March 31, 2003, neither Ameren Corporation, nor any of its subsidiaries, had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. At this time, we do not expect to engage in any significant off-balance sheet financing arrangements. OUTLOOK We believe there will be challenges to earnings in 2003 and beyond due to industry-wide trends and company-specific issues. The following are expected to put pressure on earnings in 2003 and beyond: o Weak economic conditions, which impacts native load demand; o Power prices in the Midwest will impact the amount of revenues we can generate by marketing any excess power into the interchange markets. Long-term power prices continue to be generally soft in the Midwest, despite the fact that short-term power prices have strengthened significantly from the prior year in the first quarter of 2003 due primarily to higher prices for natural gas; o A rate settlement approved in 2002 by the Missouri Public Service Commission (MoPSC) that required electric rate reductions of $50 million on April 1, 2002 and $30 million on April 1, 2003 with an additional $30 million reduction required for April 1, 2004; o The adverse effects of rising employee benefit costs, higher insurance costs and increased security costs associated with additional measures we have taken, or may have to take, at our Callaway nuclear plant related to world events; o The incremental dilution from equity issued in both 2002 and 2003; and o An assumed return to more normal weather patterns relative to 2002. 25 In late 2002, we announced the following actions to mitigate the effect of these challenges: o A voluntary retirement program that was accepted by approximately 550 employees; o Modifications to retiree employee benefit plans to increase co-payments and limit our overall cost; o A wage freeze in 2003 for all management employees; o Suspension of operations at two 1940's-era generating plants to reduce operating costs; and o Reductions of 2003 expected capital expenditures. We are pursuing annual gas rate increases of approximately $34 million in Illinois and we expect to file an annual gas rate increase in Missouri. We are also considering additional actions, including modifications to active employee benefits, further staffing reductions, accelerating synergy opportunities related to the CILCORP acquisition and other initiatives. In early May 2003, our service territory experienced several severe storms that damaged parts of our transmission and distribution system. As a result, we expect to incur increased costs in the quarter ending June 30, 2003 for repairs required to our system. We are currently unable to estimate the impact on our future financial position, results of operations or cash flows. In the ordinary course of business, we evaluate strategies to enhance our financial position, results of operations and liquidity. These strategies may include potential acquisitions, divestitures, and opportunities to reduce costs or increase revenues, and other strategic initiatives in order to increase shareholder value. We are unable to predict which, if any, of these initiatives will be executed, as well as the impact these initiatives may have on our future financial position, results of operations or liquidity. REGULATORY MATTERS See Note 3 - Rate and Regulatory Matters to our Consolidated Financial Statements under Item 1 of Part I of this report for information. ACCOUNTING MATTERS Critical Accounting Policies Preparation of the financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. Our application of these policies involves judgments regarding many factors, which, in and of themselves, could materially impact the financial statements and disclosures. A future change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results. In the table below, we have outlined those accounting policies that we believe are most difficult, subjective or complex: Accounting Policy Uncertainties Affecting Application - ----------------- ----------------------------------- Regulatory Mechanisms and Cost Recovery We defer costs as regulatory assets in o Regulatory environment, external regulatory accordance with SFAS 71 and make 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. 26 Accounting Policy (Continued) Uncertainties Affecting Application (Continued) - ----------------------------- ----------------------------------------------- Nuclear Plant Decommissioning Costs In our rates and earnings we assume the Department of Energy will develop a permanent o Estimates of future decommissioning costs storage site for spent nuclear fuel, the o Availability of facilities for waste disposal Callaway nuclear plant will have a useful life o Approved methods for waste disposal and of 40 years and estimated costs of decommissioning approximately $515 million to dismantle the o Useful lives of nuclear plants plant are accurate. See Note 15 - Callaway Nuclear Plant to our Consolidated Financial Statements in our 2002 Annual Report to Shareholders which is incorporated by reference into our 2002 Annual Report on Form 10-K.
Basis for Judgment We determine that decommissioning costs are reasonable, or require adjustment, based on third party decommissioning studies that are completed every three years, the evaluation of our facilities by our engineers and the monitoring of industry trends. Environmental Costs We accrue for all known environmental o Extent of contamination contamination where remediation can be o Responsible party determination reasonably estimated, but some of our o Approved methods for cleanup operations have existed for over 100 years and o Present and future legislation and governmental previous contamination may be unknown to us. regulations and standards o Results of ongoing research and development regarding environmental impacts
Basis for Judgment We determine the proper amounts to accrue for environmental contamination based on internal and third party estimates of clean-up costs in the context of current remediation standards and available technology. Unbilled Revenue At the end of each period, we estimate, based o Projecting customer energy usage on expected usage, the amount of revenue to o Estimating impacts of weather and other record for services that have been provided to usage-affecting factors for the unbilled period 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. 27 Accounting Policy (Continued) Uncertainties Affecting Application (Continued) - ----------------------------- ----------------------------------------------- Benefit Plan Accounting Based on actuarial calculations, we accrue o Future rate of return on pension and other plan costs of providing future employee benefits in assets accordance with SFAS 87, 106 and 112. See o Interest rates used in valuing benefit Note 12 - Retirement Benefits to our obligations Consolidated Financial Statements in our 2002 o Healthcare cost trend rates Annual Report to Shareholders which is o Timing of employee retirements incorporated by reference into our 2002 Annual o Future plan designs Report on Form 10-K.
Basis for Judgment We utilize a third party consultant to assist us in evaluating and recording the proper amount for future employee benefits. Our ultimate selection of the discount rate, healthcare trend rate and expected rate of return on pension assets is based on our review of available current, historical and projected rates, as applicable. Derivative Financial Instruments We record all derivatives at their fair market o Market conditions in the energy industry, value in accordance with SFAS 133. The especially the effects of price volatility on identification and classification of a contractual commodity commitments derivative and the fair value of such o Regulatory and political environments and derivative must be determined. We designate requirements certain derivatives as hedges of future cash o Fair value estimations on longer term contracts flows. See Note 4 - Derivative Financial o Complexity of financial instruments and Instruments to our Consolidated Financial accounting rules Statements under Item 1 of Part I of this o Effectiveness of our derivatives that have been report. designated as hedges
Basis for Judgment We determine whether a transaction is a derivative versus a normal purchase or sale based on historical practice and our intention at the time we enter a transaction. We utilize actively quoted prices, prices provided by external sources, and prices based on internal models, and other valuation methods to determine the fair market value of derivative financial instruments. Leveraged Leases We account for our investment in leveraged leases in accordance with SFAS 13, "Accounting o Market conditions of the industry of the leased for Leases." As required by SFAS 13, we review asset that might affect the residual value at the the estimated residual value as well as all end of the lease terms. This would include: the other important assumptions affecting estimated real estate markets where each of the assets are total net income from the leases. SFAS 13 located; the rail industry; the aerospace industry; requires the rate of return and total income of and energy market where the asset is located. a lease to be recalculated if there is a permanent decline in the estimated residual value below the value currently used to calculate income.
Basis for Judgment We determine whether the residual value has been "permanently impaired" based on an internal review as well as periodic third party review of the residual value. 28 Impact of Future Accounting Pronouncements See Note 1 - "Summary of Significant Accounting Policies" to our Consolidated Financial Statements under Item 1 of Part I of this report for information. ITEM 3. Quantitative and Qualitative Disclosures about Market Risk Market risk represents the risk of changes in value of a physical asset or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g., interest rates, etc.). The following discussion of our 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. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal and operational risks and are not represented in the following discussion. Our risk management objective is to optimize our physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers. Interest Rate Risk We are exposed to market risk through changes in interest rates associated with both long-term and short-term variable-rate debt and fixed-rate debt, commercial paper, auction-rate long-term debt and auction-rate preferred stock. We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates. Utilizing our debt outstanding at March 31, 2003, if interest rates increased by 1%, our annual interest expense would increase by approximately $9 million and net income would decrease by approximately $6 million. The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure. Credit Risk Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties in the transaction. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising our customer base. No customer represents greater than 10% of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. We analyze each counterparty's financial condition prior to entering into sales, forwards, swaps, futures or option contracts and monitor counterparty exposure associated with our leveraged leases. As of March 31, 2003, we had approximately $169 million invested in 7 leveraged leases, primarily at CILCORP. We also establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program which involves daily exposure reporting to senior management, master trading and netting agreements, and credit support management such as letters of credit and parental guarantees. 29 Equity Price Risk Our costs of providing non-contributory defined benefit retirement and post-retirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of our plan assets has been affected by declines in the equity market since 2000 for the pension and post-retirement plans. As a result, at December 31, 2002, we recognized an additional minimum pension liability as prescribed by SFAS No. 87, "Employers' Accounting for Pensions." The liability resulted in a reduction to equity as a result of a charge to Accumulated Other Comprehensive Income (OCI) of $102 million, net of taxes. The amount of the liability was the result of asset returns experienced through 2002, interest rates and our contributions to the plans during 2002. The minimum pension liability did not change at March 31, 2003. In future years, the liability recorded, the costs reflected in net income, or OCI, or cash contributions to the plans could increase materially without a recovery in equity markets in excess of our assumed return on plan assets. If the fair value of the plan assets were to grow and exceed the accumulated benefit obligations in the future, then the recorded liability would be reduced and a corresponding amount of equity would be restored in the Consolidated Balance Sheet. We also maintain trust funds, as required by the Nuclear Regulatory Commission and Missouri and Illinois state laws, to fund certain costs of nuclear decommissioning. By maintaining a portfolio that includes long-term equity investments, we seek to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in our portfolio are exposed to price fluctuations in equity markets and the fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor our portfolio by benchmarking the performance of our investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of our trusts to various investment options. Our exposure to equity price market risk is, in large part, mitigated, due to the fact that we are currently allowed to recover decommissioning costs in our rates. Fair Value of Contracts We utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause: o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory 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, we believe these transactions serve to reduce our price risk. See Note 4 - Derivative Financial Instruments to our Consolidated Financial Statements under Item 1 of Part I of this report for further information. The following table summarizes the favorable (unfavorable) changes in the fair value of all contracts marked-to-market during the first quarter of 2003: - ---------------------------------------------------------------------------------------------------------- Fair value of contracts at beginning of period, net $ 3 Contracts which were realized or otherwise settled during the period (9) Changes in fair values attributable to changes in valuation techniques and assumptions -- Fair value of new contracts entered during the period -- Other changes in fair value 6 - ---------------------------------------------------------------------------------------------------------- Fair value of contracts outstanding at end of period, net $ -- - ----------------------------------------------------------------------------------------------------------
30 Maturities of contracts as of March 31, 2003 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 $ (3) $ (2) $ (1) $ (1) $ (7) Prices provided by other external sources (b) 2 -- -- -- 2 Prices based on models and other valuation methods (c) 4 1 -- -- 5 - ---------------------------------------------------------------------------------------------------------- Total $ 3 $ (1) $ (1) $ (1) $ -- - ----------------------------------------------------------------------------------------------------------
(a) Contracts of less than $1 million were with non-investment-grade rated counterparties. (b) Principally power forward hedges valued based on NYMEX prices for over-the-counter contracts. (c) Principally coal and sulfur dioxide option values based on a Black-Scholes model that includes information from external sources and our estimates. ITEM 4. Controls and Procedures (a) Evaluation of Disclosure Controls and Procedures Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14 under the Securities Exchange act of 1934, as amended. Based upon that evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to Ameren which is required to be included in our periodic SEC filings. (b) Change in Internal Controls There have been no significant changes in our internal controls or in other factors which could significantly affect internal controls subsequent to the date we carried out our evaluation. FORWARD-LOOKING STATEMENTS Statements made in this report which are not based on historical facts are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in subsequent securities filings and others, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: o the effects of the stipulation and agreement relating to the AmerenUE Missouri electric excess earnings complaint case and other regulatory actions, including changes in regulatory policy; o changes in laws and other governmental actions, including monetary and fiscal policies; o the impact on us of current regulations related to the opportunity for customers to choose alternative energy suppliers in Illinois; o the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels; 31 o the effects of participation in a FERC-approved Regional Transmission Organization, including activities associated with the Midwest Independent System Operator; o availability and future market prices for fuel for the production of electricity, such as coal and natural gas, purchased power, electricity and natural gas for distribution, including the use of financial and derivative instruments, the volatility of changes in market prices and the ability to recover increased costs; o average rates for electricity in the Midwest; o business and economic conditions; o the impact of the adoption of new accounting standards on the application of appropriate technical accounting rules and guidance; o interest rates and the availability of capital; o actions of rating agencies and the effects of such actions; o weather conditions; o generation plant construction, installation and performance; o operation of nuclear power facilities and decommissioning costs; o the effects of strategic initiatives, including acquisitions and divestitures; o the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; o future wages and employee benefit costs, including changes in returns of benefit plan assets; o disruptions of the capital markets or other events making our access to necessary capital more difficult or costly; o competition from other generating facilities, including new facilities that may be developed in the future; o difficulties in integrating CILCO with Ameren's other businesses; o changes in the coal markets, environmental laws or regulations or other factors adversely impacting synergy assumptions in connection with the CILCORP acquisition; o cost and availability of transmission capacity for the energy generated by our generating facilities or required to satisfy energy sales made by Ameren; and o legal and administrative proceedings. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 32 PART II. OTHER INFORMATION ITEM 1. Legal Proceedings Reference is made to Note 14 to the Notes to Consolidated Financial Statements in our 2002 Annual Report to Shareholders which is incorporated by reference into Item 8. "Financial Statements and Supplementary Data" in Part II of our 2002 Annual Report on Form 10-K and to Note 7 under Item 8 "Financial Statements and Supplementary Data" in Part II of the 2002 Annual Report on Form 10-K of our subsidiaries, CILCORP Inc. and Central Illinois Light Company, operating as AmerenCILCO, for a discussion of a number of lawsuits that name our subsidiaries, Central Illinois Public Service Company, operating as AmerenCIPS, Union Electric Company, operating as AmerenUE, AmerenCILCO and us (which we refer to as the Ameren companies), along with numerous other parties, as defendants that have been filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Since the filing of the 2002 Annual Reports on Form 10-K, 25 additional lawsuits have been filed against AmerenCIPS and AmerenUE, but no additional lawsuits have been filed against AmerenCILCO. These lawsuits, like the previous cases, were mostly filed in the Circuit Court of Madison County, Illinois, involve a large number of total defendants and seek unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants. Also since the filing of the 2002 Annual Reports on Form 10-K, the Ameren companies have been voluntarily dismissed in 58 cases and have settled six cases. To date, a total of 152 asbestos-related lawsuits have been filed against the Ameren companies, of which 72 are pending, 16 have been settled and 64 have been dismissed. We believe that the final disposition of these proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. Note 3 - Rate and Regulatory Matters to our Consolidated Financial Statements under Item 1 of Part I of this report contains additional information on legal and administrative proceedings which is incorporated by reference under this item. ITEM 6. Exhibits and Reports on Form 8-K. (a)(i) Exhibits filed herewith. 10.1 - * 2003 Ameren Executive Incentive Plan. 99.1 - Certificate of Chief Executive Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 - Certificate of Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. (a)(ii) Exhibits incorporated by reference. 4.1 - AmerenUE Company Order dated April 9, 2003 establishing the 4.75% Senior Secured Notes due 2015 (AmerenUE Form 8-K dated April 9, 2003, Exhibit 4.2). 4.2 - Supplemental Indenture dated April 1, 2003 to Indenture of Mortgage and Deed of Trust dated June 15, 1937, as amended, from AmerenUE to The Bank of New York, as successor Trustee, relating to First Mortgage Bonds, Senior Notes Series CC, 4.75% due 2015 (AmerenUE Form 8-K dated April 9, 2003 Exhibit 4.4). --------------------------- * Management compensatory plan or arrangement. 33 (b) Reports on Form 8-K. Ameren Corporation filed the following reports on Form 8-K during the quarterly period ended March 31, 2003:
============================================================================================= Items Reported Financial Date of Report Statements Filed --------------------------------------------------------------------------------------------- December 10, 2002 (filed January 15, 2003) 5 None January 22, 2003 5,7 None January 30, 2003 5,7 None January 31, 2003, as amended March 7, 2003 2,5,7 None February 11, 2003 7,9 None March 5, 2003 5,7 (a)
(a) Consolidated financial statements as of December 31, 2002 and 2001, and for each of the three years in the period ended December 31, 2002, and the report thereon of PricewaterhouseCoopers LLP, independent accountants. Note: 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 Union Electric Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-2967. Reports of AmerenEnergy Generating Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 333-56594. Reports of CILCORP Inc. on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 2-95569. Reports of Central Illinois Light Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-2732. 34 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. AMEREN CORPORATION (Registrant) By /s/ Martin J. Lyons ------------------------------ Martin J. Lyons Vice President and Controller (Principal Accounting Officer) Date: May 14, 2003 CERTIFICATIONS I, Charles W. Mueller, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Ameren Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and 35 CERTIFICATIONS (CONTINUED) b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Charles W. Mueller ---------------------------------- Charles W. Mueller Chairman and Chief Executive Officer (Principal Executive Officer) Date: May 14, 2003 I, Warner L. Baxter, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Ameren Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and 36 CERTIFICATIONS (CONTINUED) b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. /s/ Warner L. Baxter ---------------------------------- Warner L. Baxter Senior Vice President, Finance (Principal Financial Officer) Date: May 14, 2003 37 EX-10.1 3 ex10-1eip2003.txt AMC 2003 EXECUTIVE INCENTIVE PLAN Exhibit 10.1 2003 Ameren Executive Incentive Plan (EIP) Ameren Corporation The Ameren Executive Incentive Plan (EIP) is intended to reward contributions to Ameren's shareholder value. PLAN PARTICIPATION All applicable members of the Ameren Leadership Team are eligible to participate in the EIP. PLAN FUNDING Plan funding is the total amount of incentive money available to award. The plan is funded based on the achievement of Ameren Corporation's earnings per share (EPS) for the plan year (achievement levels may be adjusted to reflect refunds and rate changes under regulatory sharing plans or other extraordinary one-time events). Three levels of EPS achievement will be established to reward participants for progress achieved in overall EPS performance. Achievement of EPS falling between the established levels will be interpolated. The three levels are defined as: 1. Threshold: This is the minimum level of corporate financial achievement for incentive awards to be available. Since the payment of incentives reflects a large cost to the organization, Ameren must achieve this level of EPS to justify the payment in respect to our owners, the shareholders. 2. Target: This is Ameren's targeted level of financial achievement. This is the level our shareholders and Wall Street expect Ameren to achieve. 3. Maximum: This level shares higher rewards in years of high financial success. This level will be very difficult to achieve, but in years of outstanding performance, executives will share in Ameren's success. BONUS AWARD OPPORTUNITIES Annual bonus award opportunity percentages are set by the Human Resources Committee of the Board of Directors. PERFORMANCE COMPONENT WEIGHTINGS There are two performance components (or measures) of the plan: EPS and Business Line KPIs/Individual. The performance components are the measures used to determine a bonus award pay-out. Each component is weighted. This weight indicates how much of the available funding will be available for each component. The weightings for the 2003 plan are: EPS 50% Business Line KPIs/Individual 50% EPS: This component is the corporate level of measurement; Ameren's earnings per share achievement. Fifty percent of the available bonus funds will be available for payment to each executive based on corporate success. Business Line/Individual: Each executive will have 50% of their available bonus determined by the success of their individual contributions. The success of their respective business line or function's compensation KPIs will be used as the basis of the assessment. PLAN PAYMENT Awards will be paid by 3/15/2004. The bonus award percentage will be based on each executive's base salary as of 12/31/2003. Payment will be prorated for participants who become eligible after 1/1/2003 or who retire, die or become disabled during 2003. The salary basis for those who retire, die or become disabled will be as of the date of retirement, death or disability. The Human Resources Committee of the Board of Directors will approve the final amount of payment upon recommendation of the CEO of Ameren Corporation. EX-99.1 4 amc906cert-mueller.txt AMC 906 CERTIFICATE-MUELLER Exhibit 99.1 CERTIFICATE furnished under Section 906 of the Sarbanes-Oxley Act of 2002. I, Charles W. Mueller, chief executive officer of Ameren Corporation, hereby certify that to the best of my knowledge, the accompanying Report of Ameren Corporation on Form 10-Q for the quarter ended March 31, 2003 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 Ameren Corporation. /s/ Charles W. Mueller ------------------------------------ Charles W. Mueller Chairman and Chief Executive Officer (Principal Executive Officer) Date: May 14, 2003 A signed original of this written statement required by Section 906 has been provided to Ameren Corporation and will be retained by Ameren Corporation and furnished to the Securities and Exchange Commission or its staff upon request. EX-99.2 5 amc906cert-baxter.txt AMC 906 CERTIFICATE-BAXTER Exhibit 99.2 CERTIFICATE furnished under Section 906 of the Sarbanes-Oxley Act of 2002. I, Warner L. Baxter, chief financial officer of Ameren Corporation, hereby certify that to the best of my knowledge, the accompanying Report of Ameren Corporation on Form 10-Q for the quarter ended March 31, 2003 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 Ameren Corporation. /s/ Warner L. Baxter ------------------------------ Warner L. Baxter Senior Vice President, Finance (Principal Financial Officer) Date: May 14, 2003 A signed original of this written statement required by Section 906 has been provided to Ameren Corporation and will be retained by Ameren Corporation and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----