EX-99.2 5 c75197exv99w2.txt MANAGEMENT'S DISCUSSION AND ANALYSIS EXHIBIT 99.2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Ameren Corporation is a public utility holding company registered 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., which operates a rate-regulated 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 from The AES Corporation (AES). 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) that 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 from AES 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 us and our 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 financial results of CILCORP have not been included or discussed in this report except with regard to certain forward looking information. All tabular dollar amounts are in millions, unless otherwise indicated. Our results of operations and financial position are impacted by many factors, including both controllable and uncontrollable factors. Weather, economic conditions and the actions of key customers or competitors can significantly impact the demand for our services. Our results are also impacted by seasonal fluctuations caused by winter heating, and summer cooling, demand. With 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. WWW.AMEREN.COM 17 RESULTS OF OPERATIONS Earnings Summary Our net income for 2002, 2001 and 2000, was $382 million ($2.61 per share before dilution), $469 million ($3.41 per share before dilution), and $457 million ($3.33 per share), respectively. Net income in 2002 included voluntary retirement and other restructuring charges (40 cents per share), which consisted of a voluntary retirement program, the retirement of our Venice, Illinois plant, and the temporary suspension of operation of two coal-fired generating units at our Meredosia, Illinois plant. In 2001, net income was reduced by the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (5 cents per share). The following table reconciles our net income to net income excluding voluntary retirement and restructuring charges and SFAS 133 adoption for the years ended December 31, 2002, 2001, and 2000:
2002 2001 2000 -------- -------- -------- Net income $ 382 $ 469 $ 457 Earnings per share - basic $ 2.61 $ 3.41 $ 3.33 Voluntary retirement and other restructuring charges, net of taxes 58 -- -- SFAS 133 adoption, net of taxes -- 7 -- Cents per share $ 0.40 $ 0.05 $ -- -------- -------- -------- Net income excluding restructuring charges and SFAS 133 adoption $ 440 $ 476 $ 457 Earnings per share, excluding restructuring charges and SFAS 133 adoption - basic $ 3.01 $ 3.46 $ 3.33 ======== ======== ========
Excluding the charges discussed above, our net income in 2002 decreased $36 million from 2001, primarily due to the impact of the settlement of our Missouri electric rate case (26 cents per share), increased costs of employee benefits (15 cents per share), higher depreciation (17 cents per share), excluding the effect of the rate case that is included in the 26 cents above, and a decline in industrial sales due to the continued soft economy. Increased average shares outstanding (8.8 million shares) and financing costs also reduced earnings per share in 2002 (29 cents per share). Factors decreasing net income in 2002 were partially offset by favorable weather conditions (24 cents per share), sales of emission credits by EEI (10 cents per share) and organic growth. Excluding the charges discussed above, our net income in 2001 increased $19 million from 2000, primarily due to a reduction in estimated credits to Missouri customers (33 cents per share) and organic growth, partially offset by increased costs of employee benefits (13 cents per share), higher depreciation and interest expense, and a refueling outage at Callaway. There was not a refueling at Callaway in 2000. As a holding company, our net income and cash flows are primarily generated by our principal operating subsidiaries, AmerenUE, AmerenCIPS and Generating Company. These subsidiaries also file quarterly and annual reports with the Securities and Exchange Commission (SEC). The contribution by our principal operating subsidiaries to net income for the years ended December 31, 2002, 2001, and 2000 were as follows:
2002 2001 2000 ------ ------ ------ PRIMARILY RATE-REGULATED OPERATIONS: AmerenUE(a) $ 336 $ 365 $ 344 AmerenCIPS(b) 23 42 75 ------ ------ ------ $ 359 $ 407 $ 419 ------ ------ ------ PRIMARILY NON RATE-REGULATED OPERATIONS: Generating Company(a)(b)(c) 32 76 44 OTHER (9) (14) (6) ------ ------ ------ AMEREN NET INCOME $ 382 $ 469 $ 457 ====== ====== ======
(a) Includes earnings from interchange sales by AmerenEnergy that provided approximately $20 million of AmerenUE's net income and $10 million of Generating Company's net income in 2002. (b) 2000 data represents the period from May 1, 2000 through December 31, 2000, which was Generating Company's initial eight months of operation. Prior to May 1, 2000, AmerenCIPS operated the generating facilities now operated by Generating Company. (c) Includes earnings from contracts to supply power to our rate-regulated AmerenCIPS customers. Recent Developments CILCORP ACQUISITION On January 31, 2003, after receipt of the necessary regulatory agency approvals and clearance from the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act, we completed our acquisition of all of the outstanding common stock of CILCORP Inc. from AES. CILCORP is the parent company of Peoria, Illinois-based Central Illinois Light Company, which operated as CILCO. With the 18 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 became a wholly-owned subsidiary of Resources Company which we renamed AmerenEnergy Medina Valley Cogen (No. 4), LLC. The CILCORP and AmerenEnergy Medina Valley Cogen (No. 4), LLC financial statements will be included in our consolidated financial statements effective with the January and February 2003 acquisition dates. We acquired CILCORP to complement our existing Illinois electric and gas 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. In addition, the purchase includes 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 approximately $900 million, with the balance of the purchase price of approximately $500 million paid with cash on hand. 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 in early 2003 of 6.325 million shares. See Common Stock Offering below. COMMON STOCK OFFERING In early 2003, Ameren issued 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. 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. 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 February 2003, the ratings by Moody's and Standard & Poor's were as follows:
Standard Moody's & 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 AMERENCIPS: Secured debt A1 A- Unsecured debt A2 BBB+ GENERATING COMPANY: Unsecured debt A3/Baa2 A-
Standard & Poor's increased the ratings of CILCORP and CILCO subsequent to the acquisition of these entities by Ameren Corporation. As of February 2003, the unsecured debt ratings of CILCORP were BBB+ and Baa2 from Standard & Poor's and Moody's, respectively. The secured debt ratings of AmerenCILCO were A- and A2 from Standard & Poor's and Moody's, respectively. Standard & Poor's assigned stable outlooks to these ratings. Moody's also assigned a stable outlook to the ratings for CILCORP and AmerenCILCO. Any adverse change in Ameren's 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. WWW.AMEREN.COM 19 Electric Operations The following table represents the favorable (unfavorable) impact on electric margin versus the prior periods for the years ended December 31, 2002 and 2001:
2002 2001 ------ ------ OPERATING REVENUES: Effect of abnormal weather(estimate) $ 82 $ 10 Growth and other (estimate) 22 118 2002 Missouri rate settlement (47) -- Credit to customers (10) 75 Interchange revenues (109) (168) EEI 75 (54) ------ ------ Total variation in electric operating revenues 13 (19) ------ ------ FUEL AND PURCHASED POWER: Fuel: Generation (46) 19 Price 5 (28) Generation efficiencies and other 1 6 Purchased power 174 69 EEI (45) 45 ------ ------ Total variation in fuel and purchased power 89 111 ------ ------ CHANGE IN ELECTRIC MARGIN $ 102 $ 92 ====== ======
Electric margin increased $102 million for the year ended December 31, 2002 compared to 2001. Increases in electric margin in 2002 were primarily attributable to more favorable weather conditions and increased sales of emission credits. Weather sensitive residential electric kilowatthour sales in 2002 increased 7% and commercial electric kilowatthour sales increased 2%. However, industrial sales were approximately 5% lower in 2002 as compared to 2001 due primarily to the impact of the soft economy. Revenues were also reduced by $47 million in 2002 due to the settlement of the Missouri electric rate case. Contribution to electric margin from EEI increased in 2002 principally due to EEI's sale of $38 million in emission credits, which is included in the overall $75 million increase in EEI revenues. The remaining EEI increase was due to increased sales to its principal customer, which also resulted in an increase in fuel and purchased power. Interchange revenues decreased due to lower energy prices and less low-cost generation available for sale, resulting primarily from increased demand for generation from native load customers. Fuel and purchased power were reduced in 2002 due primarily to lower energy prices, partially offset by increased fuel and purchase power costs due to increased kilowatthour sales and unscheduled coal plant outages. We expect that revenues will continue to be negatively affected by the settlement of the Missouri rate case reached in 2002, which requires the phase-in of $30 million of electric rate reductions effective April 1, 2003 and $30 million effective April 1, 2004. In addition, we expect power prices in the energy markets to remain generally soft, which will impact the margins we can generate by marketing our power into the interchange markets. 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. Prior to adopting EITF 02-3 and the rescission of EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," our accounting practice was to present all settled energy purchase or sale contracts within our power risk management program, on a gross basis in Operating Revenues - Electric and in Operating Expenses - Fuel and Purchased Power. This meant that revenues were recorded for the notional amount of the power sale 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. Upon adoption, EITF 02-3 requires that prior periods also be netted to conform to the current year presentation. Adoption of this EITF did not have any impact on operating or net income for any period or stockholders' equity. The operating revenues and costs netted for the year ended December 31, 2002 were $738 million (2001 - $648 million) which reduced interchange revenues and purchased power costs by equal amounts. SFAS 133 was adopted on January 1, 2001 and therefore, no netting was required for the year ended December 31, 2000. Electric margin increased $92 million for the year ended December 31, 2001 compared to 2000, primarily due to a $75 million reduction in the estimated credits to Missouri electric customers. During the year ended December 31, 2001, we reduced the estimated credit previously recorded for the plan year ended June 30, 2001 by $10 million, compared to estimated credits of $65 million recorded in 2000. In addition, industrial sales rose 11% primarily due 20 to a new electric service industrial contract that was effective August 2000. Our residential sales were comparable to the prior year while commercial sales rose 1%. These increases were partially offset by a 31% decrease in interchange sales and reduced EEI sales. The $111 million decrease in fuel and purchased power costs for 2001, compared to 2000, was primarily due to reduced interchange sales. Gas Operations Our gas margin decreased $3 million in 2002 as compared to 2001 with revenues decreasing by $27 million and costs decreasing by $24 million. The decrease in margin was primarily due to the timing of revenue recovery under purchased gas adjustment clauses and warmer winter weather early in 2002, partially offset by increased gas sales due to colder than normal temperatures in late 2002. Gas margin in 2001 increased $6 million, compared to 2000, primarily due to higher gas costs recovered through purchased gas adjustment clauses, partially offset by lower total sales of 9% resulting from unusually warm winter weather. Other Operating Expenses OTHER OPERATIONS AND MAINTENANCE Other operations and maintenance expenses increased $70 million in 2002 compared to 2001, primarily due to higher employee benefit costs ($35 million), related to increasing healthcare costs and the investment performance of employee benefit plans' assets, higher wages and higher plant maintenance expenses. See also Equity Price Risk below for a discussion of our expectations and plans regarding trends in employee benefit costs. Other operations and maintenance expenses increased $58 million in 2001 compared to 2000, primarily due to higher employee benefit costs in 2001 ($29 million), resulting from increasing healthcare costs and the investment performance of employee benefit plans' assets, a refueling outage at Callaway in 2001 versus no refueling in 2000, and increased costs of professional services. In 2000, we recorded a $25 million charge to earnings related to our withdrawal from the Midwest Independent System Operator (Midwest ISO). The charge reduced earnings $15 million, net of taxes, or 11 cents per share. See Regulatory Matters. RESTRUCTURING CHARGES Voluntary retirement and other restructuring charges of $92 million in 2002 consisted primarily of a voluntary retirement program charge of $75 million based on voluntary retirements of approximately 550 employees. These costs consisted primarily of special termination benefits associated with our pension and post-retirement benefit plans. Most of the employees who voluntarily retired will leave Ameren by March 2003. In addition, in December 2002, we announced our plans to retire 343 megawatts of rate-regulated capacity at AmerenUE's Venice, Illinois plant and temporarily suspend operations of two coal-fired generating units (126 megawatts) at Generating Company's Meredosia, Illinois plant, which resulted in a total charge of approximately $17 million. DEPRECIATION AND AMORTIZATION Depreciation and amortization expenses increased $25 million in 2002 and $23 million in 2001 compared to the prior years. These net increases were primarily due to our investment in combustion turbine electric generating plants and coal-fired power plants. The increase in 2002 was partially offset by a reduction of depreciation rates ($15 million) 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. INCOME TAXES Income tax expense decreased $50 million in 2002, compared to 2001, primarily due to lower pretax income. Income tax expense for 2001 was comparable to 2000. OTHER TAXES Other taxes expense in 2002 was comparable to 2001. Other tax expense decreased $4 million in 2001, compared to 2000, primarily due to a decrease in gross receipts taxes related to our Illinois jurisdiction. Other Income and Deductions Other income and deductions (excluding income taxes) decreased $48 million in 2002, compared to the prior year. The decrease was primarily due to the cost of economic development and energy assistance programs included in the settlement of the Missouri electric rate case ($26 million) and an increase in the deduction for minority interest earnings principally related to EEI's sale of emission credits ($10 million). Other income and deductions (excluding income taxes) increased $21 million in 2001, compared to 2000, primarily due to contributions in aid of construction ($7 million), decreased charitable contributions, and life insurance proceeds. See Note 10 - Miscellaneous, Net to our Consolidated Financial Statements for further information. WWW.AMEREN.COM 21 Interest Interest expense increased $20 million in 2002, compared to 2001 primarily due to 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. Proceeds from these offerings were used to repay lower cost short-term borrowings and for general corporate purposes. Interest expense increased $19 million in 2001, compared to 2000, primarily due to increased debt related to the construction and purchase of combustion turbine generating facilities, partially offset by lower interest rates. LIQUIDITY AND CAPITAL RESOURCES Operating Our cash flows provided by operating activities totaled $833 million for 2002, compared to $738 million for 2001, and $864 million for 2000. Cash provided from operations increased in 2002, primarily as a result of higher cash earnings resulting from favorable weather and the sale of emission credits. These increases were partially offset by payments of customer sharing credits under AmerenUE's now-expired electric alternative regulation plan ($40 million), discretionary pension plan contributions ($31 million) and the timing of payments on accounts payable and accrued taxes. Cash flow from operations decreased in 2001, principally due to the timing of credits provided to AmerenUE's Missouri electric customers and changes in working capital requirements, partially offset by increased earnings. 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. PENSION FUNDING We made cash contributions totaling $31 million to our defined benefit retirement plan during 2002. At December 31, 2002, we also recorded a minimum pension liability of $102 million, net of taxes, which resulted in a charge to Accumulated Other Comprehensive Income (OCI) and a reduction to stockholders' equity. Based on the performance of plan assets through December 31, 2002, we expect to be required under the Employee Retirement Income Security Act of 1974 to fund approximately $150 million to $175 million annually, including CILCORP, in 2005, 2006 and 2007 in order to maintain minimum funding levels for our pension plans. In addition, we estimate the pension funding for CILCORP to be less than $1 million in 2003 and approximately $5 million in 2004. These amounts are estimates and may change based on actual stock market performance, changes in interest rates, and any pertinent changes in government regulations. See Benefit Plan Accounting under Accounting Matters - Critical Accounting Policies below. Investing Our net cash used in investing activities was $803 million in 2002 compared to $1.1 billion in 2001 and $911 million in 2000. In 2002, construction expenditures in our rate-regulated operations were $603 million (2001 - $671 million; 2000 - $369 million), primarily related to various upgrades at our coal power plants and further construction of combustion turbine generating units. Construction expenditures in our non rate-regulated operations were $184 million in 2002 (2001 - $431 million; 2000 -$560 million), primarily related to the construction of combustion turbine generating units. In 2002, we placed into service 240 megawatts (approximately $135 million) of combustion turbine electric generation capacity in our rate-regulated operations and approximately 470 megawatts (approximately $215 million) in our non rate-regulated operations. In 2001 and 2000, we added approximately 850 megawatts (approximately $530 million) and approximately 690 megawatts (approximately $320 million), respectively, of non rate-regulated combustion turbine generating capacity. For the five-year period 2003 through 2007, construction expenditures are estimated to approximate $3 billion - $3.3 billion, of which approximately $675 million is expected in 2003. This estimate includes capital expenditures related to CILCORP's operations, the purchase of new combustion turbine generating facilities at AmerenUE and the replacement of steam generators at AmerenUE's Callaway nuclear plant. In addition, this estimate includes capital expenditures for transmission, distribution and other generation-related activities, as well as for compliance with new NO(x) (nitrogen oxide) control regulations, as discussed in Environmental below. 22 As a part of the settlement of the Missouri electric rate case in 2002 (see Regulatory Matters below), AmerenUE committed to making $2.25 billion to $2.75 billion in infrastructure investments from January 1, 2002 through June 30, 2006. These investments include, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at AmerenUE's Callaway nuclear plant. The requirements for 700 megawatts of new generation are expected to be satisfied by 240 megawatts added in 2002, as discussed above, and the proposed transfer at net book value to AmerenUE of approximately 550 megawatts of generation assets from Generating Company, which is subject to receipt of necessary regulatory approvals. We intend to add 117 megawatts of capacity by 2005 and at least 330 megawatts of capacity by 2006 at AmerenUE. Total costs expected to be incurred for these units approximate $175 million of which approximately $100 million was committed as of December 31, 2002. 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. ENVIRONMENTAL We are subject to various environmental regulations by federal, state, and local authorities. From the beginning phases of siting and development, to the ongoing operation of existing or new electric generating, transmission, and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, special, protected, and cultural resources (such as wetlands, endangered species, and archeological/ historical resources), chemical and waste handling, and noise impacts. Our activities require complex and often lengthy processes to obtain approvals, permits, or licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operations, as required. The U.S. Environmental Protection Agency (EPA) issued a rule in October 1998 requiring 22 Eastern states and the District of Columbia to reduce emissions of NO(x) in order to reduce ozone in the Eastern United States. Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NO(x) emission budget for each state, including Illinois where most of Generating Company's facilities are located. The EPA rule requires states to implement controls sufficient to meet their NO(x) budget by May 31, 2004. As a result of these state requirements, Generating Company estimates spending an additional $40 million for pollution control capital expenditures and NO(x) credits by 2006. A total of $90 million was spent in 2002 and 2001. In February 2002, the EPA proposed similar rules for Missouri where the majority of AmerenUE's facilities are located. Assuming the Missouri rules are ultimately finalized, AmerenUE estimates spending approximately $170 million to comply with these rules for NO(x) control on the AmerenUE generating system by 2006. In summary, we currently estimate our future capital expenditures to comply with the final NO(x) regulations could range from $200 million to $250 million. This estimate includes the assumption that the regulations will require the installation of Selective Catalytic Reduction technology on some of our units, as well as additional controls. See Note 14 - Commitments and Contingencies to our Consolidated Financial Statements for further discussion of environmental matters and Note 15 - Callaway Nuclear Plant to our Consolidated Financial Statements for a discussion of Callaway Nuclear Plant decommissioning costs. Financing Our cash flows provided by financing activities totaled $531 million in 2002 and $307 million in 2001, compared to cash flows used in financing activities of $22 million for 2000. Our principal financing activities for the three year period included the issuance of long-term debt, adjustable conversion-rate equity security units and common stock, partially offset by redemptions of short-term debt, long-term debt and preferred stock, as well as payments of dividends. WWW.AMEREN.COM 23 Ameren Corporation, AmerenUE and AmerenCIPS are authorized by the SEC under PUHCA to have up to an aggregate of $1.5 billion, $1 billion and $250 million, respectively, of short-term unsecured debt instruments outstanding at any time. In addition, 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 December 31, 2002, Ameren had committed credit facilities, expiring at various dates between 2003 and 2005, totaling $695 million, excluding EEI of $45 million and nuclear fuel lease facilities of $120 million. All of these amounts were available for use by 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. These committed credit facilities are used to support our commercial paper programs under which $250 million was outstanding at December 31, 2002. At December 31, 2002, $445 million was unused and available under these committed credit facilities. In July 2002, Ameren Corporation entered into new committed credit agreements for $400 million in revolving credit facilities to be used for general corporate purposes, including support of our commercial paper programs. The $400 million in new facilities includes a $270 million 364-day revolving credit facility and a $130 million 3-year revolving credit facility. The 3-year facility has a $50 million sub-limit for the issuance of letters of credit. These new credit facilities replaced AmerenUE's $300 million revolving credit facility. These amounts are included in the total committed credit facilities of $695 million mentioned above. Ameren Corporation had a $200 million committed credit facility which matured in December 2002. We expect to replace this bank credit agreement with two new credit facilities at AmerenUE, and we expect to extend or replace our other committed credit facilities upon their respective maturities. These credit facilities make borrowings available at various interest rates based on LIBOR, agreed rates and other options. We also have two bank credit agreements totaling $45 million that expire in 2003 at EEI. At December 31, 2002, $27 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 December 31, 2002, the maximum amount that could be financed under the agreement was $120 million. At December 31, 2002, $113 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 December 31, 2002, we had $628 million of cash. In early 2003, we paid a total of approximately $500 million of cash on hand 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. The following table summarizes available borrowing capacity under our committed lines of credit and credit agreements as of December 31, 2002:
Amount of Commitment Expiration Per Period ------------------------------------------ Less After Total Than 1 1 - 3 4 - 5 5 Committed Year Years Years Years --------- ------ ----- ----- ----- LINES OF CREDIT AND CREDIT AGREEMENTS: Ameren Corporation $ 600 $ 470 $ 130 $ -- $ -- AmerenUE (a) 200 80 120 -- -- AmerenCIPS 15 15 -- -- -- EEI 45 45 -- -- -- --------- ------ ----- ----- ----- TOTAL $ 860 $ 610 $ 250 $ -- $ -- ========= ====== ===== ===== =====
(a) Includes $120 million Gateway Fuel Company facility due February 2004 which supports the nuclear fuel lease. 24 The following table summarizes our contractual obligations as of December 31, 2002:
Less After Than 1 1 - 3 4 - 5 5 Total Year Years Years Years ------ ------ ------ ------ ------ Long-term debt and capital lease obligations(a) $3,780 $ 339 $ 656 $ 546 $2,239 Short-term debt 271 271 -- -- -- Operating leases(b) 171 22 35 26 88 Other long-term obligations(c) 2,441 706 981 370 384 ------ ------ ------ ------ ------ TOTAL CASH CONTRACTUAL OBLIGATIONS $6,663 $1,338 $1,672 $ 942 $2,711 ====== ====== ====== ====== ======
(a) Amounts include our contractual obligation for fabricated nuclear fuel for the years 2003 through 2006. (b) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $1 million annual obligation for these items is included in the less than 1 year, 1-3 years and 4-5 years. Amounts for after 5 years are not included in the total amount due to the indefinite periods. (c) Represents purchase contracts for coal, gas, nuclear fuel (including our contractual obligation for fabricated nuclear fuel for the years 2007 through 2012), and electric capacity. 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. Many of 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. Covenants in Ameren Corporation's committed credit facilities require the maintenance of the percentage of total debt to total capital of 60% or less for Ameren, AmerenUE and AmerenCIPS. As of December 31, 2002, this ratio was 50%, 43% and 50% for Ameren Corporation, AmerenUE, and AmerenCIPS, respectively. Ameren Corporation's committed credit facilities also include indebtedness cross default provisions that could trigger a default under these facilities in the event any subsidiary of Ameren Corporation (subject to definition in the underlying credit agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. Most of Ameren's committed credit facilities include provisions related to the funded status of Ameren's pension plan. These provisions either require Ameren to meet minimum ERISA funding requirements or limit the unfunded liability status of the plan. 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 pension plan exceeds $300 million in the aggregate. Based on the most recent valuation report available to Ameren at December 31, 2002, which was based on January 2002 asset and liability valuations, the unfunded liability status (as defined) was $31 million. While an updated valuation report will not be available until the second half of 2003, 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. Generating Company's senior note indenture includes provisions that require it to maintain a senior debt service coverage ratio of at least 1.75 to 1 (for both the prior four fiscal quarters and for the next succeeding four, six-month periods) in order to pay dividends, or to make payments of principal or interest under certain subordinate indebtedness, excluding amounts payable under an intercompany note payable with AmerenCIPS. For the four quarters ended December 31, 2002, this ratio was 4.10 to 1. In addition, the indenture also restricts Generating Company from incurring any additional indebtedness, with the exception of certain permitted indebtedness as defined in the indenture, unless its senior debt service coverage ratio equals at least 2.5 to 1 for the most recently ended four fiscal quarters and its senior debt to total capital ratio would not exceed 60%, both after giving effect to the additional indebtedness on a pro-forma basis. This debt incurrence requirement is disregarded in the event certain rating agencies reaffirm the ratings of Generating Company after considering the additional indebtedness. As of December 31, 2002, Generating Company's senior debt to total capital ratio was 55%. WWW.AMEREN.COM 25 At December 31, 2002, Ameren Corporation and its subsidiaries were in compliance with their indenture and credit agreement provisions and covenants. OFF-BALANCE SHEET ARRANGEMENTS At December 31, 2002, 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. We do not expect to engage in any significant off-balance sheet financing arrangements in the near future. LONG-TERM DEBT AND EQUITY The following table summarizes our issuances of common stock and the issuances and redemptions of long-term debt for the years ended 2002, 2001 and 2000. For additional information related to the terms and uses of these issuances and the sources of funds and terms for redemptions, see Note 8 - Long-Term Debt and Capitalization to our Consolidated Financial Statements.
Month Issued/ Redeemed 2002 2001 2000 ------------- ----- ----- ----- ISSUANCES - LONG-TERM DEBT: Ameren Corporation: 5.70% Notes, due 2007 Jan $ 100 $ -- $ -- Senior notes, due 2007(a) Mar 345 -- -- Floating rate notes, due 2003 Dec -- 150 -- AmerenUE: 5.25% Senior secured notes, due 2012 Aug 173 -- -- Environ. improvement revenue bonds Mar -- -- 187 Generating Company: 7.95% Senior notes, due 2032 June 275 -- -- 7.75% Senior notes, due 2005 Nov -- -- 225 8.35% Senior notes, due 2010 Nov -- -- 200 AmerenCIPS: 6.625%Senior secured notes, due 2011 Jun -- 150 -- Pollution control revenue bonds Mar -- -- 51 Electric Energy Inc.: Bank term loan, due 2004 Jun -- -- 40 ----- ----- ----- TOTAL LONG-TERM DEBT ISSUANCES $ 893 $ 300 $ 703 ===== ===== ===== EQUITY: 5,000,000 Shares at $39.50 Mar $ 198 $ -- $ -- 750,000 Shares at $38.865 Mar 29 -- -- 8,050,000 Shares at $42.00 Sep 338 -- -- DRPlus and employee benefit plans(b) Various 93 33 -- ----- ----- ----- TOTAL COMMON STOCK ISSUANCES $ 658 $ 33 $ -- ===== ===== ===== REDEMPTIONS - LONG-TERM DEBT: AmerenUE: 8.33% First mortgage bonds Dec $ 75 $ -- $ -- 8.75% First mortgage bonds Sep 125 -- -- Environ. improvement bonds, 7.40% series May -- -- 60 Environ. improvement bonds, 1985 series Apr -- -- 127 Commercial paper, net Various -- 18 132 AmerenCIPS: First mortgage bonds Various 32 30 35 Environ. improvement bonds, 1990 A series Apr -- -- 20 Environ. improvement bonds, 1990 B series Apr -- -- 32 Electric Energy Inc.: 1991 8.60% Senior MTNs, amortization Dec 7 7 7 1994 6.61% Senior MTNs, amortization Dec 8 8 8 ----- ----- ----- TOTAL LONG-TERM DEBT REDEMPTIONS $ 247 $ 63 $ 421 ===== ===== =====
(a) A component of the adjustable conversion-rate equity security units. See Note 8 - Long-Term Debt and Capitalization for further discussion. (b) Includes issuances of common stock of 2.3 million shares in 2002 and 0.8 million shares in 2001 under our dividend reinvestment and stock purchase plan (DRPlus) and in connection with our 401(k) plans. 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 2002 and in 26 early 2003, $594 million was issued under the shelf registration statement. At February 13, 2003, the amount remaining on the shelf registration statement was approximately $879 million. See discussion of the 2003 common stock offering under Recent Developments above. We may sell all, or a portion of, the remaining registered securities under the Ameren Corporation 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 September 2001, we began issuing new shares of common stock under our DRPlus, and in December 2001 we began issuing new shares of common stock in connection with our 401(k) plans. Previously, these requirements were met by purchasing outstanding common shares on the open market. We plan to continue to issue new shares of common stock under our DRPlus and 401(k) plans in 2003. Ameren expects to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing. 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 2002, AmerenUE issued $173 million under the shelf registration statement. At February 13, 2003, the amount remaining under the shelf registration statement was $577 million. AMERENCIPS In May 2001, a shelf registration statement filed by AmerenCIPS with the SEC on Form S-3 was declared effective. This statement authorized the offering from time to time of senior notes in one or more series with an offering price not to exceed $250 million. In June 2001, AmerenCIPS issued $150 million of senior notes under the shelf registration statement. At February 13, 2003, the amount remaining on the shelf registration statement was $100 million. DIVIDENDS Common stock dividends paid in 2002 resulted in a payout rate of 98% of our net income (85% of net income excluding voluntary retirement and other restructuring charges) (75% - 2001; 76% - 2000). Dividends paid to common stockholders in relation to net cash provided by operating activities for the same periods were 45%, 47% and 40%. The 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 February 14, 2003, our Board of Directors declared a quarterly common stock dividend of 63.5 cents per share to be paid on March 31, 2003 to shareholders of record on March 12, 2003. 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 Generally soft power prices in the Midwest are expected to limit the amount of revenues Ameren can generate by marketing its excess power into the interchange markets, o Our revenues will be reduced by a rate settlement approved in 2002 by the Missouri Public Service Commission (MoPSC) that requires the phase-in of $110 million of electric rate reductions from 2002 through 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. WWW.AMEREN.COM 27 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 gas rate increases of approximately $34 million in Illinois and are considering a gas rate increase request 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 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 Missouri From July 1, 1995 through June 30, 2001, our subsidiary, AmerenUE, operated under experimental alternative regulation plans in Missouri that provided for the sharing of earnings with customers if our regulatory return on equity exceeded defined threshold levels. After AmerenUE's experimental alternative regulation plan for its Missouri retail electric customers expired, the MoPSC Staff and others sought to reduce our annual Missouri electric revenues by over $300 million. The MoPSC Staff's recommendation was based on a return to traditional cost of service ratemaking, a lowered return on equity, a reduction in AmerenUE's depreciation rates and other cost of service adjustments. In August 2002, a stipulation and agreement resolving this case became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement includes the following principal features: o The phase-in of $110 million of electric rate reductions through April 2004, $50 million of which was retroactively effective as of April 1, 2002, $30 million of which will become effective on April 1, 2003, and $30 million of which will become effective on April 1, 2004. o A rate moratorium providing for no changes in rates before June 30, 2006, subject to certain statutory and other exceptions. o A commitment to contribute $14 million to programs for low income energy assistance and weatherization, promotion of energy efficiency and economic development in AmerenUE's service territory in 2002, with additional payments of $3 million made annually on June 30, 2003 through June 30, 2006. This entire obligation was expensed in 2002. o A commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at AmerenUE's Callaway nuclear plant. The 700 megawatts of new generation is expected to be satisfied by 240 megawatts that were added by AmerenUE in 2002 and the proposed transfer at net book value to AmerenUE of approximately 550 megawatts of generation assets from Generating Company, which is subject to receipt of necessary regulatory approvals. o An annual reduction in AmerenUE's depreciation rates by $20 million, retroactive to April 1, 2002, based on an updated analysis of asset values, service lives and accumulated depreciation levels. o A one-time credit of $40 million which was accrued during the plan period. The entire amount was paid to AmerenUE's Missouri retail electric customers in 2002 for the settlement of the final sharing period under the alternative regulation plan that expired June 30, 2001. See Note 2 - Rate and Regulatory Matters to our Consolidated Financial Statements. Illinois See Note 2 - Rate and Regulatory Matters to our Consolidated Financial Statements. Federal - Electric Transmission See Note 2 - Rate and Regulatory Matters to our Consolidated Financial Statements. 28 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 decisions accordance with SFAS 71 and make investments and requirements that we assume we will be able to collect in future rates. o Anticipated future regulatory decisions and 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. Nuclear Plant Decommissioning Costs In our rates and earnings we assume the o Estimates of future decommissioning costs Department of Energy will develop a permanent storage site for spent nuclear fuel, the o Availability of facilities for waste disposal Callaway nuclear plant will have a useful life of 40 years and estimated costs of approximately o Approved methods for waste disposal and decommissioning $515 million to dismantle the plant are accurate. See Note 15 - Callaway Nuclear Plant to our o Useful lives of nuclear plants Consolidated Financial Statements. 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.
Table Continued on Page 30 WWW.AMEREN.COM 29 Table Continued from Page 29
Accounting Policy Uncertainties Affecting Application Environmental Costs We accrue for all known environmental o Extent of contamination contamination where remediation can be reasonably estimated, but some of our operations o Responsible party determination have existed for over 100 years and previous contamination may be unknown to us. o Approved methods for cleanup o Present and future legislation and governmental 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 on o Projecting customer energy usage expected usage, the amount of revenue to record for services that have been provided to customers, o Estimating impacts of weather and other usage-affecting but not billed. This period can be up to one month. factors for the unbilled period BASIS FOR JUDGMENT We determine the proper amount of unbilled revenue to accrue each period based on the volume of energy delivered as valued by a model of billing cycles and historical usage rates and growth by customer class for our service area, as adjusted for the modeled impact of seasonal and weather variations based on historical results. Benefit Plan Accounting Based on actuarial calculations, we accrue o Future rate of return on pension and other plan assets costs of providing future employee benefits in accordance with SFAS 87, 106 and 112. o Interest rates used in valuing benefit obligations See Note 12 - Retirement Benefits to our Consolidated Financial Statements. o Healthcare cost trend rates o Timing of employee retirements BASIS FOR JUDGMENT We utilize a third party consultant to assist us in evaluating and recording the proper amount for future employee benefits. Our ultimate selection of the discount rate, healthcare trend rate and expected rate of return on pension assets is based on our review of available current, historical and projected rates, as applicable. Derivative Financial Instruments We record all derivatives at their fair market value in o Market conditions in the energy industry, especially the accordance with SFAS 133. The identification and effects of price volatility on contractual commodity classification of a derivative, and the fair value of commitments such derivative must be determined. We designate certain derivatives as hedges of future cash flows. o Regulatory and political environments and requirements See Note 3 - Derivative Financial Instruments to our Consolidated Financial Statements. o Fair value estimations on longer term contracts o Complexity of financial instruments and accounting rules o Effectiveness of our derivatives that have been 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.
30 Impact of Future Accounting Pronouncements See Note 1 - Summary of Significant Accounting Policies to our Consolidated Financial Statements. EFFECTS OF INFLATION AND CHANGING PRICES Our rates for retail electric and gas utility service are regulated by the MoPSC and the Illinois Commerce Commission (ICC). Non-retail electric rates are regulated by the FERC. Our Missouri electric rates have been set through June 30, 2006, as part of the settlement of our Missouri electric rate case and our Illinois electric rates are legislatively fixed through January 1, 2007. Inflation affects our operations, earnings, stockholders' equity and financial performance. The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace plant in future years. Ameren's generation portion of its business in its Illinois jurisdiction is non rate-regulated and therefore does not have regulated recovery mechanisms. In our retail electric utility jurisdictions, there are no provisions for adjusting rates for changes in the cost of fuel for electric generation. In our retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through purchased gas adjustment clauses. We are impacted by changes in market prices for natural gas to the extent we must purchase natural gas to run our combustion turbine electric generators. We have structured various supply agreements to maintain access to multiple gas pools and supply basins to minimize the impact to the financial statements. See discussion below under Commodity Price Risk for further information. 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 December 31, 2002, if interest rates increased by 1%, our annual interest expense would increase by approximately $11 million and net income would decrease by approximately $7 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 WWW.AMEREN.COM 31 financial condition prior to entering into sales, forwards, swaps, futures or option contracts and monitor counterparty exposure associated with our leveraged leases. As of December 31, 2002, we had approximately $29 million invested in three leveraged leases. 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. Commodity Price Risk We are exposed to changes in market prices for natural gas, fuel and electricity. We utilize several techniques to mitigate risk, including utilizing derivative financial instruments. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. The derivative financial instruments that we use (primarily forward contracts, futures contracts, option contracts and financial swap contracts) are dictated by risk management policies. With regard to our natural gas utility business, our exposure to changing market prices is in large part mitigated by the fact we have gas cost recovery mechanisms in place in both Missouri and Illinois. These gas cost recovery mechanisms allow us to pass on to retail customers our prudently incurred costs of natural gas. AmerenEnergy Fuels and Services Company is responsible for providing fuel procurement and gas supply services on behalf of our operating subsidiaries, and for managing fuel and natural gas price risks. Fixed price forward contracts, as well as futures, options, and financial swaps are all instruments, which may be used to manage these risks. The majority of our fuel supply contracts are physical forward contracts. Since we do not have a provision similar to the purchased gas adjustment clauses for our electric operations, we have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel in order to manage our exposure to fuel prices. See Note 14 - Commitments and Contingencies to our Consolidated Financial Statements for further information. Approximately 98% of the required 2003 and over 80% of the required 2004 supply of coal for our coal-fired power plants has been acquired at fixed prices. As such, we have minimal coal price risk for 2003 and 2004. At December 31, 2002, approximately 30% of our coal requirements for 2005 through 2007 were covered by contracts. We have satisfied 77%, 11% and 2% of our historical needs through coal, nuclear and hydro generation, respectively. With regard to our electric generating operations, we are exposed to changes in market prices for natural gas to the extent we must purchase natural gas to run our combustion turbine generators. At December 31, 2002, approximately 36% of our 2003 natural gas requirements for generation are covered by contracts. Our natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to our intermediate and peaking units by optimizing transportation and storage options and minimizing cost and price risk by structuring various supply agreements to maintain access to multiple gas pools and supply basins and reducing the impact of price volatility. Although we cannot completely eliminate the effects of gas price volatility, our strategy is designed to minimize the effect of market conditions on our results of operations. Our gas procurement strategy includes procuring natural gas under a portfolio of agreements with price structures, including fixed price, indexed price and embedded price hedges such as caps and collars. Our strategy also utilizes physical assets through storage, operator and balancing agreements to minimize price volatility. Ameren's electric marketing strategy is to extract additional value from its generation facilities by selling energy in excess of needs into the long-term and short-term markets for term sales, and purchasing energy when the market price is less than the cost of generation. Our primary use of derivatives has involved transactions that are expected to reduce price risk exposure for us. With regard to our exposure to commodity price risk for purchased power and excess electricity sales, we have a subsidiary, AmerenEnergy, whose primary responsibility includes managing market risks associated with changing market prices for electricity purchased and sold on behalf of AmerenUE and Generating Company. In addition, we have sold nearly all of our available non rate-regulated peak generation capacity for the summer of 2003 at various prices. 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 our pension and post-retirement plans. As a result, at 32 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 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. 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. See Liquidity and Capital Resources - Operating. 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. See Note 15 - Callaway Nuclear Plant to our Consolidated Financial Statements for further information. As of December 31, 2002, these funds were invested primarily in domestic equity securities (62%), debt securities (35%), and cash and cash equivalents (3%) and totaled $172 million at fair value. 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 3 - Derivative Financial Instruments to our Consolidated Financial Statements for further information. The following table summarizes the favorable (unfavorable) changes in the fair value of all contracts marked to market during 2002 and 2001:
2002 2001 ----- ----- FAIR VALUE OF CONTRACTS AT BEGINNING OF PERIOD, NET $ (1) $ (30) Contracts which were realized or otherwise settled during the period (7) 30 Changes in fair values attributable to changes in valuation techniques and assumptions -- -- Fair value of new contracts entered into during the period 1 4 Other changes in fair value 14 (5) ----- ----- FAIR VALUE OF CONTRACTS OUTSTANDING AT END OF PERIOD, NET $ 7 $ (1) ===== =====
Maturities of contracts as of December 31, 2002 were as follows:
Maturity ----------------------------------- Less In Excess Total Than 1 - 3 4 - 5 of 5 Fair 1 year Years Years Years Value(a) ------ ----- ----- --------- -------- SOURCES OF FAIR VALUE: Prices actively quoted $ (1) $ -- $ -- $ -- $ (1) Prices provided by other external sources(b) 3 -- -- -- 3 Prices based on models and other valuation methods(c) 4 1 -- -- 5 ------ ----- ----- --------- -------- TOTAL $ 6 $ 1 $ -- $ -- $ 7 ====== ===== ===== ========= ========
(a) Contracts of approximately 7% of the absolute fair value were with non-investment-grade rated counterparties. WWW.AMEREN.COM 33 (b) Principally power forward values based on NYMEX prices for over-the-counter contracts and natural gas swaps based on Inside FERC prices. (c) Principally coal and sulfur dioxide option values based on a Black-Scholes model that includes information from external sources and our estimates. FORWARD LOOKING STATEMENTS Statements made in this annual 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, 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; o the effects of participation in a FERC-approved Regional Transmission Organization, including activities associated with the Midwest ISO; o availability and future market prices for fuel and purchased power, electricity and natural gas, including the use of financial and derivative instruments and volatility of changes in market prices; o average rates for electricity in the Midwest; o business and economic conditions; o the impact of the adoption of new accounting standards 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. 34