ULNRC-04625, Annual Financial Report for Callaway Plant

Annual Financial Report for Callaway Plant

ML020950128
Person / Time
Site:	Callaway
Issue date:	03/25/2002
From:	Blosser J Union Electric Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
-nr, ULNRC-04625
Download: ML020950128 (60)

Text

Union Electric One Ameren Plaza 1901 Chouteau Avenue PO Box 66149 St. Louis, MO 63166-6149 314.621.3222 March 25, 2002 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Mail Station P 1-137 Washington, DC 20555-0001 Gentlemen: ULNRC-04625 WAmeren DOCKET NUMBER 50-483 UE CALLAWAY PLANT UNION ELECTRIC COMPANY ANNUAL FINANCIAL REPORT Transmitted herewith are twenty-five (25) copies of the Ameren Corporation/Union Electric Company 2000 Annual Report. This information is submitted in accordance with 10 CFR 50.7 1(b).

Very truly yours, John D. Blosser Manager, Regulatory Affairs DJW/jdg Attachments

-6Le a subsidiary of Ameren Corporation

cc: M. H. Fletcher Professional Nuclear Consulting, Inc.

19041 Raines Drive Derwood, MD 20855-2432 Regional Administrator U.S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive Suite 400 Arlington, TX 76011-8064 Senior Resident Inspector Callaway Resident Office U.S. Nuclear Regulatory Commission 8201 NRC Road Steedman, MO 65077 Mr. Jack Donohew (2) - OPEN BY ADDRESSEE ONLY Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission 1 White Flint, North, Mail Stop OWFN 7E1 11555 Rockville Pike Rockville, MD 20852-2738 Manager, Electric Department Missouri Public Service Commission P.O. Box 360 Jefferson City, MO 65102 Nuclear Energy Institute 1776 I Street N.W.

Suite 400 Washington, DC 20006-3708

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BRING IIILI L T OUR OSWNER AMEREN IS FOCUSED ON DEMONSTRATING PERFORMANCE LEADERSHIP THROUGH GROWTH. OUR STRATEGY? TO FOCUS ON OUR CORE ENERGY OPERATIONS. TO GROW OUR PORTFOLIO OF ENERGY BUSINESSES THROUGH MARKET-DRIVEN INVESTMENTS.

FOR NEARLY OO YEARS, WE HAVE BUILT UPON OUR CORE ENERGY BUSINESS TO BRING VALUE TO SHAREHOLDERS, CUSTOMERS AND COMMUNITIES ACROSS MISSOURI AND ILLINOIS - OURS IS A FOCUS ON GREAT CONNECTIONS.

YearEnded Current Ameren Consolidated December 31, 2001 Year Change Earnings per Common Share $3.41 2%

Net Income $468,545,000 3%

Book Value per Common Share $24.26 4%

Property and Plant (net) $8,426,562,000 9%

Total Operating Revenues $4,505,867,000 17%

Native Kilowatthour Sales 53,002,000,000 4%

Total Kilowatthour Sales 85,905,000,000 19%

Dividends Paid per Common Share $2.54

I-B R TO OUR OWNI1II IN LATE AUGUST, THE CORPORATION'S BOARD OF DIRECTORS ELECTED GARY L. RAINWATER, A 22-YEAR COMPANY VETERAN, TO THE POSITION OF PRESIDENT AND CHIEF OPERATING OFFICER. CHARLES W. MUELLER CONTINUES AS CHAIRMAN AND CHIEF EXECUTIVE OFFICER.

Charles W. Mueller, Chairman and Ameren is committed to imple menting a vision to achieve per Chief Executive Officer (left);

formance leadership and growth Gary L. Rainwater, President and in the energy business. Together, the Ameren team will pursue this Chief Operating Officer vision by developing Ameren's core business, continuing to offer and improve on superior customer service and growing the com pany's energy portfolio through market-driven, energy-related investments. Here the two execu tives responded to questions that are frequently asked by our own ers and the financial community:

TOTAL KILOWATTHOUR SALES Q. Do you foresee any significant We will continue to provide changes in the company's excellent customer service. We will strategies due to the recent organization changes? explore and carefully invest in

[CWM] We are taking a fresh opportunities that offer long-term, 98 99 00 01 look at our strategy, but we In Millions remain committed to our core profitable growth. Kilowatthour sales reflect energy energy business. sold to other energy providers, businesses and institutionsand

[GLR] This fresh look won't earnings were $3.46 per share, residential customers - in effect all the kilowatthours sold by change our commitment to creat up two cents per share over 2000 the company ing value for our shareholders and ongoing earnings. Excluding the customers. We will continue to impacts of weather, our ongoing provide excellent customer serv earnings per share rose over five EARNINGS ice. We will focus on remaining a financially strong company. We will explore and carefully invest in opportunities that offer long-term, profitable growth. We will capital percent this year, compared to last year. When you consider that we faced an economic recession, weak prices in the energy markets and wide-ranging issues associated liii PER SHARE ize on opportunities presented with the Sept. 11 1t terrorist attacks 98 99 00 01 by competitive markets. And, as in 2001, I was very encouraged by Ongoing earningsper share (EPS)representreported earn always, we will commit ourselves our financial performance. ings, excluding unusual items.

to values that include commit Ongoing2001 EPS excluded

0. What are your targets for a charge of 5 cents per share, ment, integrity, respect, teamwork associated with the required earnings per share in 2002?

and stewardship. adoption of a new accounting

[CWM] We estimate that earnings standardrelatedto derivative Q. How would you characterize financial instruments.

per share will range between $3.15 the corporation's earnings results and $3.45 per share in 2002. This for 2001? estimate factors in a future form of

[CWM] Once again, we reported incentive regulation, which could solid earnings for 2001. Ongoing include Missouri retail electric rate RMEREN 2001 RNNURL REPORT 1 3

reductions and additional customer used to determine rates in this pro credits. An incentive regulation plan ceeding. In that same order, the will be proposed in our filing with the MPSC stated that we would be Missouri Public Service Commission permitted to propose an incentive (MPSC) in May 2002. We are making regulation plan. In addition, the this filing in connection with the commission order called for any Electric Complaint Case filed in July decision that lowers rates to be 2001 by the MPSC staff. retroactive to April 1, 2002.

Q. Can you provide an update Clearly, we are pleased with the on the status of that case? opportunity to bring incentive regula

[GLR] In early January, the MPSC tion into our discussions with the ordered that more recent data be commission and others connected to this case. We are convinced that incentive regulation results in a win win situation for all. Evidence of this is the fact that the incentive regula tion plan we have operated under for the past six years returned more than $425 million in benefits to our customers.

I would also note that it's been 15 years since the company raised its electric rates in Missouri. Since the early 1990s, we have provided a total of more than $1 billion to customers in the form of rate reduc tions and customer credits. Today Ameren Senior Management Team (from left):

Senior Vice President-Generationand AmerenUE rates are 14 percent Chief Nuclear Officer GarryL. Randolph; below the national average and 10 AmerenEnergy Resources PresidentDaniel F Cole; Senior Vice PresidentDavid A. Whiteley; percent below 1987 levels. At the Senior Vice PresidentPaul A. Agathen; same time, our customer service Senior Vice President-EnergyDelivery Thomas R. Voss; and Senior Vice President-FinanceWarner L. Baxter has been rated among the top five 4 1 WWW.AMEREN.COM

AVERAGE AMERENUE MISSOURI ELECTRIC RETAIL RATES PER KILOWRTTHOUR Customers continue to give Ameren ultimately could negatively affect 7.0ý the reliability of energy service in operating companies high - and the state of Missouri and could 6.o¢ improving - marks for customer service, significantly inhibit our ability to s.s¢ maintain our high quality service.

and outage frequency for AmerenUE

[CWM] In the end, we are hopeful customers has dropped more than that when the MPSC examines the 90 92 94 96 98 00 issues objectively on their merits, This chartreflects blended rates 20 percent over the past two years. for AmerenUE residential,com it will understand the broader energy mercialand industrialcustomers and credits to customers. It also policy implications of this case excludes gross receipts taxes.

and will establish regulatory policies Average AmerenUE electric rates percent in the nation, based on are 14 percentbelow the national recent studies. that balance shareholder and average and have dropped four times since the early 1990s.

All these benefits came as a result customer interests. As the largest of an innovative regulatory frame electric utility in Missouri, we have INCREASE IN COST work established in the past by the a responsibility to pursue the best OF BASIC GOODS company and the MPSC. That frame long-term benefits for both our FOOD work included an incentive plan that shareholders and customers. I SHELTER enabled timely energy infrastructure Q. The energy industry has gone investments and meaningful produc through a rather turbulent period tivity gains in our company, while recently. Has this changed your ALLOTHER ITEMS permitting us to earn reasonable perspective on the company's IMERENUE MISSOURI returns for our shareholders. strategies going forward? RESIDENTIAL ELECTRIC RATE

-25 0 25 50 75 100 Looking ahead, we need to make [CWM] Absolutely not. Long before Percentage from 1987 to 2000 substantial investments in our these times arrived, the company St. Louis Metro Area Residents energy infrastructure to continue adopted a business strategy that From 1987 to 2000, the price of everything from food to shelter to to provide reliable service to our was focused on superior core energy transportationincreased,but the cost of power has actually gone customers. Proposals similar to the operations, customer service and down. However not at the MPSC staff's July 2001 recommen effective financial management. expense of quality service and reliability.Customers continue to dation represent a major departure Today, that strategy continues to give Ameren operatingcompanies high - andimproving - marks from the reasonable regulatory reap rewards for all of our stakehold for customer service, and outage framework embraced by the ers as we have delivered solid earn frequency for AmerenUE cus tomers has dropped more than MPSC in the past. Such proposals ings growth, an attractive dividend 20 percentover the past two years.

(Source:2000 Consumer Price Index)

AMEREN 2001 ANNUAL REPORT 1 5

COMPETITIVE We will remain a leading the best in people and gives them RATES a sense of their own value. We energy provider in the region.

remain committed to assuring Our customers enjoy some business success and the pursuit of excellence, to managing our of the best service and lowest business with honesty and a high N1 energy costs in the nation. level of ethical behavior and to performing in a way that earns the trust and respect of investors, TOTAL RETAIL and superior customer service. And regulators, customers and employ at the same time, we have remained eess We are pledged to "steward O¢ 2c 4( 6d 8¢ a financially strong company. ship" to building and improving Ameren Operating Looking ahead, we will not deviate on the business and the environ Companies Average m National Average from this successful strategy. ment entrusted to us. We are (For the 12 months ended committed to enhancing our June 30, 2001 Q. What does the future hold Edison Electric Instfitute) stockholders' investment as we for Ameren?

Ameren operating corpanies' continue to provide low cost,

[GLR] We will remain a leading annual avO'"ge revenue per kilowaIthourat June 30, 2001, energy provider in the region. high quality service. Finally, we is consistently below he remain dedicated to returning national average revenue Our customers enjoy some of the per kilo wathourover the value to the economy of our best service and lowest energy same period, This chart region and to maintaining high includes customer credis, costs in the nation. We are confi allocated for customer classes performance standards dent that we will successfully and distributedto AmerenUE Missouri ctstot"es meet regulatory, economic and legislative challenges We will continue to invest in Chairman and customer service technologies Chief Executive Officer and capitalize on strategic oppor tunities to develop our core busi nesses, while keeping costs low.

We will continue to work to build President and an organization that brings out Chief Operating Officer 6' fMERENCON

IBING VALU* TO O R C OMERS F- 1 WE OFFER OUR CUSTOMERS RELIABLE, LOW-COST ENERGY AND A RANGE OF ADVISORY SERVICES AND SUPPORT TO HELP THEM COMPETE EFFECTIVELY, PROVIDE CRITICAL SERVICES AND CONTROL ENERGY COSTS.

1 On the following pages are profiles of customers who represent the many relationships we are building.

By reliably delivering energy.

By providing excellent service.

By connecting.

AMEREN 2001 ANNUAL REPORT 7

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IBR N V LUE TO HE*L Z* WORLD RENOWNED INSTITUTIONS MAKE ST. LOUIS A CENTER FOR SUPERIOR MEDICAL CARE AND RESEARCH.

I Critical to sustaining life are As the flagship pediatric institution within BJC HealthCare - one of the nation's largest nonprofit reliable power and highly skilled healthcare organizations - St. Louis Children's professionals, like those in Hospital is ranked as one of the best children's hospitals in the nation. It is also a model of energy St. Louis Children's Hospital's efficiency. The 235-bed hospital has employed cardiac catheterization lab (left) variable speed drives to improve its ability to manage air flow. St. Louis Children's Hospital has also or in the Neonatal Intensive installed Ameren's wireless energy management Care Unit (above). tool -Ameren AbacusT" allowing the facility to closely monitor energy use. The institution doubled the size of its emergency unit in 2000; yet, its energy use has been trending downward.

AMEREN 2001 ANNURL REPORT1 9

IBRIN G V L TO EA w7 PRESTIGIOUS EDUCATIONAL INSTITUTIONS CREATE AN EDUCATED WORKFORCE, CULTURAL ENRICHMENT, AND EMPLOYMENT OPPORTUNITIES.

Power is vital to campus life, Only a short drive from Shawnee National Forest, deep in southern Illinois, is Southern Illinois University Carbondale whether for conducting

- with more than 22,000 students, one of the largest sophisticated and demanding universities in our service territory. Founded in 1869, SlUC offers more than 100 academic programs leading to laboratory research or leading bachelor's, graduate and post-graduate degrees. Over the the Southern Illinois past six years, the university's facilities and educational offerings have grown significantly - prompting campus University Carbondale power demand to rise by more than 10 percent.

team to victory. AmerenCIPS has responded by providing technical support for the institution's distribution systems and a range of energy management advisory services to help the university control costs, while ensuring reliability.

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IBNRT A CENTRAL LOCATION ATTRACTED REFINERIES TO OUR AREA -

NOW THEY ARE INVESTING MILLIONS IN FACILITY UPGRADES.

Premcor workers at the boiler One of the most transformed of our refinery customers is The Premcor Refining Group Inc. - among the largest controls (above) or out in the independent refiners of petroleum products in the U.S.

plant keep the refinery operating A Fortune 500 company based in St. Louis, Premcor markets high-quality gasoline, diesel fuel and other efficiently at Premcor's petroleum products with a daily capacity of nearly a Hartford, Ill., facility. half million barrels. Premcor plans to grow by expand ing its existing refineries through profit-enhancing projects. The company is committed to increasing the efficiency of its operations at its Hartford, Ill., facility over the next several years. Premcor's plans will require support from AmerenUE as the refinery increases its demand for the energy we supply.

AMEREN 2001 ANNUAL REPORT 13

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• RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Ameren Corporation is responsible for the information and representations contained in the consolidated financial statements and in other sections of this Annual Report. The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America.

Other information included in this report is consistent, where applicable, with the consolidated financial statements.

The Company maintains a system of internal accounting controls designed to provide reasonable assurance as to the integrity of the financial records and the protection of assets. Qualified personnel are selected and an organization structure is maintained that provides for appropriate functional responsibility.

Written policies and procedures have been developed and are revised as necessary. The Company maintains and supports an extensive program of internal audits with appropriate management follow up.

The Board of Directors, through its Auditing Committee comprised of outside directors, is responsible for ensuring that both management and the independent accountants fulfill their respective responsibilities relative to the financial statements. Moreover, the independent accountants have full and free access to meet with the Auditing Committee, with or without management present, to discuss auditing or financial reporting matters.

Charles W Mueller Warner L. Baxter Chairman and Chief Executive Officer Senior Vice President, Finance February 1, 2002 February 1,2002 REPORT OF INDEPENDENT ACCOUNTANTS TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF RMEREN CORPORATION:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2001, and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for our opinion.

4.LP PricewaterhouseCoopersLLP February 1, 2002 14 1 WWW.RMEREN.COM

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I B R1 N. G SMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW RESULTS OF OPERATIONS Ameren Corporation (Ameren or the Company) Earnings is a holding company registered under the Public Earnings for 2001, 2000 and 1999, were $469 million Utility Holding Company Act of 1935 (PUHCA). ($3.41 per share before dilution), $457 million ($3.33 In December 1997, Union Electric Company per share) and $385 million ($2.81 per share), respec (AmerenUE) and CIPSCO Incorporated (CIPSCO) tively. Earnings and earnings per share increased combined to form Ameren, with AmerenUE and over the three-year period primarily due to: the rate of CIPSCO's subsidiaries, Central Illinois Public Service sales growth, weather variations, credits to electric Company (AmerenCIPS) and CIPSCO Investment customers, electric rate reductions, gas rate changes, Company (CIC), becoming subsidiaries of Ameren competitive market forces, fluctuating operating costs (the Merger). As a result of the Merger, Ameren (including Callaway Nuclear Plant refueling outages),

has a 60% ownership interest in Electric Energy, Inc. expenses relating to the withdrawal from the electric (EEl), which is consolidated for financial reporting transmission related Midwest Independent System purposes. Since the Merger, Ameren has formed Operator (Midwest ISO), charges for coal contract several new subsidiaries, including AmerenEnergy, terminations, adoption of a new accounting standard, Inc. (AmerenEnergy), Ameren Development changes in interest expense, and changes in income Company, AmerenEnergy Resources Company and property taxes.

(Resources Company), and Ameren Services In 2001, the Company recorded an after-tax, unusual Company. AmerenEnergy, an energy trading and charge of $7 million, or 5 cents per share, representing marketing subsidiary, primarily serves as a power the impact of the required adoption of a new account marketing agent for AmerenUE and AmerenEnergy ing standard related to derivative financial instruments Generating Company (Generating Company), the (see Note 3 - Risk Management and Derivative Financial nonregulated electric generating subsidiary of Instruments under Notes to Consolidated Financial Resources Company, and provides a range of Statements for further information). In 2000, the energy and risk management services to targeted Company recorded a $25 million unusual charge to customers. Ameren Development Company is a earnings in connection with its withdrawal from the nonregulated subsidiary encompassing various Midwest ISO. The charge reduced earnings $15 million, nonregulated energy products and services. net of income taxes, or 11 cents per share (see discus Resources Company holds Ameren's nonregulated sion below under "Electric Industry Restructuring" generating operations. Ameren Services Company and Note 2 - Regulatory Matters under Notes to provides shared support services to Ameren and Consolidated Financial Statements for further informa all of its subsidiaries. tion). In 1999, the Company recorded a $52 million References to the Company are to Ameren nonrecurring charge to earnings in connection with on a consolidated basis. In certain circumstances, coal contract terminations with two coal suppliers.

the subsidiaries are separately referred to in The charge reduced earnings $31 million, net of income order to distinguish among their different taxes, or 23 cents per share (see discussion below business activities. under "Electric Operations" and Note 11 - Commitments AMEREN 2001 ANNUAL REPORT 15

and Contingencies under Notes to Consolidated Financial and 8%, respectively, while industrial and wholesale Statements for further information). sales rose 3% and 41%, respectively. These increases The Company estimates that ongoing earnings per were offset in part by an increase in the credits to share for the year ending December 31, 2002, will Missouri electric customers (see Note 2 - Regulatory range between $3.15 and $3.45 per share. This esti Matters under Notes to Consolidated Financial mate incorporates significant assumptions, including Statements for further information).

resolution of the regulatory issues associated with the Electric revenues for 1999 increased $196 million, Company's Missouri retail electric operations (see compared to 1998, primarily due to a 9% increase in discussion below under "Rate Matters" and Note 2 total kilowatthour sales. This increase was primarily Regulatory Matters under Notes to Consolidated driven by a 53% increase in interchange sales, due to Financial Statements for further information). This esti strong marketing efforts at AmerenEnergy and a 12%

mate assumes a future form of incentive regulation increase in EEl sales. Also contributing to the revenue relative to the Company's Missouri electric operations, increase was a decrease in the credit to Missouri electric which could include electric rate reductions and addi customers, partially offset by the credit to Illinois electric tional customer credits. This estimate is also subject customers (see Note 2 - Regulatory Matters under Notes to, among other things, changing energy markets, and to Consolidated Financial Statements for further informa economic and weather conditions. Actual results could tion). Partially offsetting these increases, weather-sensi differ materially from the assumptions used in the tive residential and commercial sales decreased 2% and Company's 2002 earnings per share estimate. 1%, respectively, while industrial sales remained flat.

In addition, revenues were lower due to rate decreases Electric Operations in both Missouri and Illinois (see Note 2 - Regulatory Electric Revenues Variations from Prior Year Matters under Notes to Consolidated Financial In Millions 2001 2000 1999 Statements for further information).

Rate variations $ - $ - $(17) Fuel and PurchasedPower Credit to customers 75 (27) 5 Effect of abnormal weather 10 (4) (53) Variations from Prior Year Growth and other 117 136 78 In Millions 2001 2000 1999 Interchange sales 480 135 159 Fuel:

EEl sales (53) (13) 24 Generation $ (19) $49 $10

$629 $227 $196 Price 28 (33) (15)

Generation efficiencies and other (6) (13) (8)

Electric revenues for 2001 increased $629 million, Coal contract termination compared to the prior year period, primarily driven by payments (52) 52 a 19% increase in total kilowatthour sales. Interchange Purchased power 579 92 117 sales increased 85%; however, lower electric margins EEl (45) 9 37 were realized on these sales due to lower energy prices $537 $52 $193 in the wholesale markets. Residential sales were compa rable to the prior year while commercial sales rose 1%. The $537 million increase in fuel and purchased Industrial sales rose 11% primarily due to a new electric power costs for 2001, compared to 2000, was primarily service industrial contract effective August 2000. due to increased purchased power, resulting from Revenues were also favorably impacted by a reduction higher interchange sales and the spring 2001 refueling in the estimated credits to Missouri electric customers outage at the Company's Callaway Nuclear Plant, in (see Note 2 - Regulatory Matters under Notes to addition to higher blended fuel costs.

Consolidated Financial Statements for further informa The $52 million increase in fuel and purchased power tion). These increases were partially offset by reduced costs for 2000, compared to 1999, was primarily due EEl sales. to increased generation and purchased power, resulting Electric revenues for 2000 increased $227 million, from higher sales volume, partially offset by lower fuel compared to the prior year period, primarily due to an costs, due to the termination of certain coal contracts 8% increase in total kilowatthour sales. This increase in the fourth quarter of 1999.

was primarily driven by a 35% increase in interchange The $193 million increase in fuel and purchased sales reflecting the marketing efforts of AmerenEnergy. power costs for 1999, compared to 1998, was primarily In addition, residential and commercial sales rose 6% due to increased generation and purchased power, 161 WWW.AMEREN.COM

resulting from higher sales volume, increased fuel and and investment performance of employee benefit plans' purchased power costs at EEl and coal contract termi assets and increased professional services. Other nation payments discussed below, partially offset by operating expenses, excluding the Midwest ISO lower fuel costs. related unusual charge, increased $10 million in 2000, In the fourth quarter of 1999, AmerenCIPS and two compared to 1999. This increase was primarily due to of its coal suppliers executed agreements to terminate increases in injuries and damages expense, and higher their existing coal supply contracts effective December labor expenses, offset in part by lower employee benefit 31, 1999. Under these agreements, AmerenCIPS made costs in 2000, resulting from changes in actuarial termination payments to the suppliers totaling approxi assumptions. Other operating expenses decreased mately $52 million. These termination payments were $18 million in 1999, compared to 1998. This decrease recorded as an unusual charge in the fourth quarter of was primarily due to the 1998 charge for a targeted 1999. See Note 11 - Commitments and Contingencies employee separation plan and related reduced work under Notes to Consolidated Financial Statements for force and the capitalization of certain costs (including further information. computer software costs) that had previously been expensed for the Company's Missouri electric opera Gas Operations tions. The capitalization was a result of the MoPSC Gas revenues in 2001 increased $18 million, Order received in December 1999 (see Note 2 compared to 2000, primarily due to higher gas costs Regulatory Matters under Notes to Consolidated recovered through the Company's purchased gas Financial Statements for further information). These adjustment clauses, partially offset by lower total sales decreases were partially offset by 1999 expenses of 9% resulting from unusually warm winter weather. associated with electric industry deregulation in Illinois.

Gas revenues in 2000 increased $96 million, compared In November 2000, the Company announced that to 1999, primarily due to increases in retail sales, due it was withdrawing from the Midwest ISO to become to unusually cold weather, and an annualized $4 million a member of the Alliance Regional Transmission Missouri gas rate increase, which became effective in Organization (Alliance RTO). In the fourth quarter of 2000, November 2000. Gas revenues in 1999 increased $12 the Company recorded a pretax unusual charge to earn million, compared to 1998, primarily due to an annual ings of $25 million ($15 million after income taxes, or ized $9 million Illinois gas rate increase, which became 11 cents per share) as a result of the Company's decision effective in February 1999 (see Note 2- Regulatory to withdraw from the Midwest ISO. This charge related Matters under Notes to Consolidated Financial to Ameren's estimated obligation under the Midwest Statements for further information) and higher gas ISO agreement for costs incurred by the Midwest ISO, costs recovered through the Company's purchased plus estimated exit costs. See discussion below under gas adjustment clauses. "Electric Industry Restructuring" and Note 2 - Regulatory Gas costs in 2001 increased $12 million, compared to Matters under Notes to Consolidated Financial 2000, primarily due to higher gas prices, partially offset Statements for further information.

by lower total sales. Gas costs in 2000 increased $78 Maintenance expenses increased $14 million in 2001, million, compared to 1999, primarily due to higher sales compared to 2000, primarily due to a refueling outage and higher gas prices. Gas costs in 1999 increased $13 at the Callaway Nuclear Plant in 2001. The spring 2001 million, compared to 1998, primarily due to higher gas refueling was completed in 45 days. There was not a prices, partially offset by lower total sales. refueling in 2000. The next refueling is scheduled for Other Operating Expenses the fall of 2002. Maintenance expenses decreased Other operating expense variations in 1999 through $3 million in 2000, compared to 1999. This decrease 2001 reflected recurring factors, such as growth, infla was primarily the result of no Callaway Nuclear Plant tion, labor and benefit variations, the capitalization of refueling outage in 2000, partially offset by increased certain costs as a result of a Missouri Public Service scheduled fossil power plant maintenance and tree Commission (MoPSC) Order and charges for estimated trimming activity. Maintenance expenses increased costs relating to withdrawal from the Midwest ISO as $59 million in 1999, compared to 1998. This increase discussed below. was primarily due to increased fossil power plant main Other operating expenses increased $44 million tenance and tree-trimming activity.

in 2001, compared to 2000, primarily due to higher Depreciation and amortization expense increased employee benefit costs in 2001, resulting from increas $23 million and $20 million in 2001 and 2000, respec ing healthcare costs, changes in actuarial assumptions tively, compared to prior year periods, due to increased AMEREN 2001 RNNUAL REPORT 117

depreciable property, primarily resulting from the working capital requirements, partially offset by addition of combustion turbine generating facilities increased earnings.

(see discussion below under "Liquidity and Capital Cash flows used in investing activities totaled Resources" and "Electric Industry Restructuring" for $1.1 billion, $910 million and $558 million, for the years further information). Depreciation and amortization ended December 31, 2001, 2000 and 1999, respec expense in 1999 was comparable to 1998. tively. Expenditures in 2001 for constructing new or improving existing facilities, net of allowance for funds Taxes used during construction, were $1.1 billion, $915 Income tax expense for 2001 was comparable to million for 2000, and $557 million for 1999. Included 2000. Income tax expense increased $42 million in in these amounts were approximately $424 million for 2000, compared to 1999, due to higher pretax income.

the purchase of new combustion turbine generating Income tax expense decreased $9 million in 1999, facilities in 2001 and $350 million in 2000. The compared to 1998, due to lower pretax income.

Company added 820 megawatts and 692 megawatts Other tax expense decreased $4 million in 2001, of combustion turbine generating capacity during compared to 2000, primarily due to a decrease in gross 2001 and 2000, respectively. In addition, the Company receipts taxes related to the Company's Illinois jurisdic spent $24 million in 2001 and $22 million in both 2000 tion. Other tax expense increased $18 million in 2000, and 1999, to acquire nuclear fuel.

compared to 1999, primarily due to a change in the Capital expenditures are expected to approximate property tax assessment in the state of Illinois. Other

$800 million in 2002. For the five-year period 2002 tax expense decreased $26 million in 1999, compared through 2006, construction expenditures are estimated to 1998, primarily due to a decrease in gross receipts to approximate $3.5 billion. This estimate includes taxes related to the Company's Illinois jurisdiction.

capital expenditures related to the purchase of new Other Income and Deductions combustion turbine generating facilities (see Note 11 Miscellaneous, net decreased $5 million in 2001, Commitments and Contingencies under Notes to compared to 2000, primarily due to decreased charita Consolidated Financial Statements for further informa ble contributions. Miscellaneous, net decreased $6 tion), and the replacement of four steam generators million in 2000, compared to 1999, due to the prior at its Callaway Nuclear Plant. In addition, this estimate period write-off of certain nonregulated investments, includes capital expenditures for transmission, distribu partially offset by increased charitable contributions tion and other generation-related activities, as well as in 2000. Miscellaneous, net increased $8 million in for compliance with new NOx control regulations, 1999, compared to 1998, due to the write-off of as discussed below. The Company plans to add certain nonregulated investments in 1999 and gains on 710 megawatts (approximately 470 megawatts at the sale of property realized in 1998 but not in 1999. Resources Company and 240 megawatts at AmerenUE) of combustion turbine generating capacity during Interest 2002. Total costs expected to be incurred for these Interest expense increased $19 million and $11 combustion turbine generating units approximate million in 2001 and 2000, respectively, compared to $340 million. Due to expected increased demand, and prior year periods, primarily due to increased debt levels the need to maintain appropriate reserve margins, the related to the construction and purchase of combustion Company believes it will need additional regulated turbine generating facilities (see discussion below under generating capacity in the future. In 2002, AmerenUE "Liquidity and Capital Resources"), partially offset by expects to purchase up to 500 megawatts of capacity lower interest rates. Interest expense decreased $13 for the summer. Additional future resource options million in 1999, compared to 1998, primarily due to a under consideration by the Company include the lower amount of debt outstanding throughout the year. transfer of AmerenUE's Illinois-based electric and gas business to AmerenCIPS. Other alternatives include LIQUIDITY AND CAPITAL RESOURCES the addition of 650 megawatts of combustion turbine Cash provided by operating activities totaled $738 generating units. These units are estimated to cost million for 2001, compared to $856 million for 2000, $280 million and would be added subsequent to and $918 million for 1999. Cash flow from operations 2004. As of December 31, 2001, the Company had decreased over the three-year period principally due to noncancelable reservation commitments of $22 million the timing of credits provided to the Company's related to the potential purchase of these units. The Missouri electric customers and the changes in Company continually reviews its generation portfolio isI WWW.AMEREN.COM

and expected electrical needs, and as a result, could applied for Early Reduction NOx credits which would modify its plan for generation asset purchases, which allow the companies to manage compliance strategies could include the timing of when certain assets will be by either purchasing NOx control equipment or utilizing added to, or removed from its portfolio, whether the credits. Generating Company and AmerenUE may be generation will be added to the regulated or nonregu eligible for such credits due to the current low NOx lated portfolio, the type of generation asset technology emission rates of some of the companies' boilers that will be employed, or whether capacity may be under current state regulations.

purchased, among other things. Changes to the In July 1997, the EPA issued regulations revising the Company's plans for future generating needs could National Ambient Air Quality Standards for ozone and result in losses being incurred by the Company, which particulate matter. The standards were challenged by could be material. industry and some states, and arguments were eventu In the ordinary course of business, the Company ally heard by the U. S. Supreme Court. On February 27, evaluates several strategies to enhance its financial 2001, the Supreme Court upheld the standards in large position, earnings, and liquidity. These strategies may part, but remanded a number of significant implementa include potential acquisitions, divestitures, opportunities tion issues back to the EPA for resolution. The EPA is to reduce costs or increase revenues, and other strate currently working on a new rulemaking to address the gic initiatives in order to increase shareholder value. issues raised by the Supreme Court. New ambient The Company is unable to predict which, if any of these standards may require significant additional reductions initiatives will be executed, as well as the impact these in sulfur dioxide (SO 2 ) and NOx emissions from the initiatives may have on the Company's future financial Company's power plants by 2008. At this time, the position, results of operations or liquidity. Company is unable to predict the ultimate impact of these revised air quality standards on its future financial Environmental condition, results of operations or liquidity.

The State of Illinois has developed a NOx control In December 1999, the EPA issued a decision to regulation for utility boilers in the State consistent with regulate mercury emissions from coal-fired power a United States Environmental Protection Agency (EPA) plants by 2008. The EPA is scheduled to propose regu program aimed at reducing ozone levels in the Eastern lations by 2004. These regulations have the potential United States. As a result of these state requirements, to add significant capital and/or operating costs to the Generating Company anticipates a 75% reduction Ameren generating system after 2005. On July 20, from current levels of NOx emissions from its power 2001, the EPA issued proposed Best Available Retrofit plant boilers in Illinois by the year 2004. Generating Technology (BART) guidelines to address visibility Company estimates spending approximately $210 mil impairment (so called "Regional Haze") across the lion for capital expenditures to comply with these United States from sources of air pollution, including rules, of which approximately $50 million was spent in coal-fired power plants. The guidelines are to be used 2001. On February 13, 2002, the EPA proposed similar by States to mandate pollution control measures for rules for Missouri which require an approximate SO 2 and NOx emissions. These rules could also add 64% reduction from current levels of NOx emissions. significant pollution control costs to the Ameren gener AmerenUE estimates approximately $140 million will ating systems between 2008 and 2012.

be required to be spent to comply with these rules for In addition, the United States Congress has been NOx control on the AmerenUE generating system by working on legislation to consolidate the numerous air 2005. The Company is still evaluating the impact of pollution regulations facing the utility industry. This "multi-pollutant" legislation is expected to be deliber the EPAs regulations as applied to its Missouri opera tions and may challenge certain aspects of those ated in Congress in 2002. While the cost to comply rules. In summary, the Company currently estimates with such legislation, if enacted, could be significant, that its capital expenditures to comply with the final it is anticipated that the costs would be less than the NOx regulations could range from $300 million to $350 combined impact of the new National Ambient Air million. This estimate includes the assumption that Quality Standards, mercury and Regional Haze regula the regulations will require the installation of Selective tions, discussed above. Pollution control costs under Catalytic Reduction (SCR) technology on some of the such legislation are expected to be incurred in phases Company's units, as well as additional controls. from 2007 through 2015. At this time, the Company Under both Illinois and Missouri regulatory pro is unable to predict the ultimate impact of the above grams, Generating Company and AmerenUE have expected regulations and this legislation on its future AMEREN 2001 ANNUAL REPORT i 19

-I-financial condition, results of operations, or liquidity; was converted to long-term fixed rates. Terms of the however, the impact could be material. indebtedness ranged from 5% to 5.95% with maturities See Note 11 - Commitments and Contingencies through 2026.

under Notes to Consolidated Financial Statements In April 2001, AmerenCIPS filed with the Securities for further discussion of environmental matters and and Exchange Commission (SEC) a shelf registration Note 12 - Callaway Nuclear Plant under Notes to statement on Form S-3 authorizing the offering from Consolidated Financial Statements for a discussion time to time of senior notes in one or more series with of Callaway Nuclear Plant decommissioning costs. an offering price not to exceed $250 million. The SEC declared the registration statement effective in May Financing Activities 2001. In June 2001, AmerenCIPS issued $150 million Cash flows provided by financing activities were of the senior notes with an interest rate of 6.625% due

$308 million for 2001, compared to cash flows used June 2011. Until the release date as described in the in financing activities of $14 million for 2000 and $241 registration statement, the senior notes will be secured million for 1999. The Company's principal financing by a related series of AmerenCIPS' first mortgage activities during 2001 included the issuance of $300 bonds. The proceeds of these senior notes were used million of long-term debt and $438 million of short to repay short-term debt and first mortgage bonds term debt, offset by the redemption of $64 million maturing in June 2001.

of long-term debt and the payment of dividends on In November 2000, Generating Company issued common stock. The Company's principal financing $225 million principal amount 7.75% Senior Notes, activities during 2000 and 1999 included the Series A due 2005 (Series A Notes) and $200 million issuances of $703 million and $152 million of long principal amount 8.35% Senior Notes, Series B due term debt, the redemptions of $421 million and 2010 (Series B Notes) (collectively, the Senior Notes).

$174 million of long-term debt and the payment Generating Company filed an S-4 registration state of dividends on common stock, respectively. ment with the SEC in 2001 to register the Senior In December 2001, Ameren Corporation issued Notes under the Securities Act of 1933, as amended, Floating Rate Notes (FRNs) totaling $150 million. to permit an exchange offer of the Senior Notes. In Interest accrues on the FRNs at three month LIBOR 2001, all holders completed their exchange of the (reset quarterly) plus 0.95% and is payable quarterly Senior Notes for new Series C and D Notes which are commencing in March 2002. Principal of the FRNs identical in all material respects to the Series A Notes is payable in December 2003. With the proceeds and Series B Notes, respectively, except that the new of the FRNs, Ameren Corporation reduced its short series of notes do not contain transfer restrictions term borrowings. See Note 7 - Long-Term Debt and are registered. With the proceeds of the Senior under Notes to Consolidated Financial Statements Notes, Generating Company reduced its short-term for further discussion. borrowings incurred in conjunction with the construc In September 2001, the Company began issuing tion of completed combustion turbine generating new shares of common stock to satisfy requirements facilities, paid for the construction of certain combus under the Ameren dividend reinvestment and stock tion turbine facilities, and funded working capital and purchase plan (DRPlus) and in December 2001, it began other capital expenditure needs. See Note 7 - Long issuing new shares of common stock in connection Term Debt under Notes to Consolidated Financial with its 401(k) plans. Previously, these requirements Statements for further discussion.

were met by purchasing outstanding shares. Under In 2002, Generating Company expects to issue these plans, the Company issued 830,177 new shares additional debt to permanently finance generating of common stock in 2001. capacity additions. This additional debt issuance In January 2002, Ameren Corporation issued 5.70% could be up to $250 million and is expected to be Notes totaling $100 million. Interest is payable semi issued in early 2002.

annually on February 1 and August 1 of each year, The Company anticipates securing additional financ beginning August 1, 2002, and on the date of maturity, ing in 2002. In January 2002, Ameren Corporation filed February 1, 2007. The net proceeds were used to a shelf registration statement with the SEC on Form reduce short-term borrowings. S-3 which, upon its effectiveness, will allow the In December 2001, the interest rate mode on offering from time to time of various forms of debt AmerenCIPS' three series of variable rate tax-exempt and equity securities, up to an aggregate offering price pollution control indebtedness totaling $104 million of $1 billion. The proceeds from any sale of such 201 WWW.AM EREN.COM

securities may be used to finance the Company's Amount of Commitment subsidiaries' ongoing construction and maintenance Expiration per Period programs, to redeem, repurchase, repay or retire Total Less Amounts than 1 1-3 4-5 outstanding indebtedness, including indebtedness of In Millions Committed Year Years Years the Company's subsidiaries, to finance strategic invest ments in or future acquisitions of other entities or other Lines of credit and assets and for other general corporate purposes. At credit agreements (a) $856 $656 $200 -

this time, the Company is unable to determine the (a) See Note 6 - Short-Term Borrowings under Notes to Consolidated amount of the additional financing, as well as the addi FinancialStatements for further discussion.

tional financing's impact on the Company's financial position, results of operations or liquidity. The following table summarizes the Company's The Company plans to continue utilizing short-term contractual obligations as of December 31, 2001:

debt to support normal operations and other temporary Less requirements. The Company and its subsidiaries are than 1 1-3 4-5 authorized by the SEC under PUHCA to have up to an In Millions Year Years Years aggregate $2.8 billion of short-term unsecured debt instruments outstanding at any one time. Short-term Long-term debt and capital borrowings consist of commercial paper (maturities lease obligations (a) $139 $ 684 $279 Operating leases 13 27 19 generally within 1 to 45 days) and bank loans. At December 31, 2001, the Company had committed bank Other long-term obligations (b) 739 1,339 654 lines of credit aggregating $156 million, all of which Total cash contractual obligations $891 $2,050 $952 were unused and available at such date. These lines (a)See Note 7 - Long-Term Debt and Note 4 - NuclearFuel make available interim financing at various rates of Lease under Notes to ConsolidatedFinancialStatements interest based on LIBOR, the bank certificate of deposit for further discussion.

rate or other options. The lines of credit are renewable (b) Represents purchase contracts for coal, gas, nuclear fuel, annually at various dates throughout the year. The and electric capacity.

Company has bank credit agreements, expiring at various dates between 2002 and 2003, that support During 2001, as a result of the uncertainty commercial paper programs totaling $700 million, of created from the excess earnings complaint filed which $400 million is for the Company's own use and against AmerenUE (see discussion below under for the use of its subsidiaries. The remaining $300 "Rate Matters"), as well as other factors, Moody's, million is for the use of the Company's regulated Standard F Poor's and Fitch rating agencies subsidiaries. At December 31, 2001, all of the bank changed their outlooks for Ameren Corporation's credit agreements were unused; however, due to long-term unsecured debt ratings from stable to commercial paper borrowings and other commitments, negative. As of December 31, 2001, the ratings

$126 million of such borrowing capacity was available. of Ameren Corporation by these rating agencies The Company had $641 million of short-term borrow were as follows:

ings outstanding at December 31, 2001. See Note 6 Standard Short-Term Borrowings under Notes to Consolidated Moody's F Poor's Fitch Financial Statements for further information. Unsecured debt A2 A A+

AmerenUE also has a lease agreement that Commercial paper P-1 A-1 F1 provides for the financing of nuclear fuel. At December 31, 2001, the maximum amount that could If the ratings of AmerenUE's first mortgage bonds, be financed under the agreement was $120 million. currently rated as Aa3, A+, and AA, for Moody's, Cash used in financing for 2001 included $64 million Standard a Poor's, and Fitch, respectively, fall below of redemptions under the lease for nuclear fuel, offset investment grade, lenders on AmerenUE's $300 by $13 million of issuances. At December 31, 2001, million revolving credit facility may elect not to make

$63 million was financed under the lease. See Note 4 advances and/or declare outstanding borrowings Nuclear Fuel Lease under Notes to Consolidated due and payable. In addition, a decrease in the Financial Statements for further information. Company's ratings may reduce its access to capital The following table summarizes the Company's and/or increase the costs of borrowings resulting in committed credit availability as of December 31, 2001: a negative impact on earnings.

AMEREN 2001 ANNUAL REPORT 21

DIVIDENDS Counsel filing rebuttal testimony on May 10, 2002.

Common stock dividends paid in 2001, 2000, Evidentiary hearings on the MoPSC staff's recom and 1999 resulted in payout rates of 74%, 76% and mendation are scheduled to be conducted before the 90%, respectively, of the Company's net income. MoPSC beginning in July 2002. In the event that the Dividends paid to common stockholders in relation MoPSC ultimately determines that a rate decrease is to net cash provided by operating activities for the warranted in this case, that rate reduction would be same periods were 47%, 41% and 38%. retroactive to April 1, 2002, regardless of when the The Board of Directors does not set specific MoPSC issues its decision. A final decision on this targets or payout parameters when declaring matter may not occur until the fourth quarter of 2002.

common stock dividends; however, the Board consid Depending on the outcome of the MoPSC's decision, ers various issues, including the Company's historic further appeals in the courts may be warranted.

earnings and cash flow; projected earnings; cash In the interim, the Company expects to continue flow and potential cash flow requirements; dividend negotiations with all pertinent parties with the intent payout rates at other utilities; return on investments to continue with an incentive regulation plan. The with similar risk characteristics; and overall business Company cannot predict the outcome of these nego considerations. On February 8, 2002, the Ameren tiations and their impact on the Company's financial Board of Directors declared a quarterly common position, results of operations or liquidity; however, stock dividend of 63.5 cents per share, to holders of the impact could be material.

record on March 11, 2002, payable March 29, 2002. See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further discus RRTE MRTTERS sion of Rate Matters.

On June 30, 2001, AmerenUE's experimental alternative regulation plan (the Plan) for its Missouri ELECTRIC INDUSTRY RESTRUCTURING retail electric customers expired (see Note 2 Federal Regulatory Matters under Notes to Consolidated Steps taken and being considered at the federal Financial Statements for further information about and state levels continue to change the structure of the Plan). On July 2, 2001, the MoPSC staff filed with the electric industry and utility regulation. At the the MoPSC an excess earnings complaint against federal level, the Energy Policy Act of 1992 reduced AmerenUE that proposed to reduce its annual electric various restrictions on the operation and ownership revenues ranging from $213 million to $250 million. of independent power producers and gave the Factors contributing to the MoPSC staff's recommen Federal Energy Regulatory Commission (FERC) the dation included return on equity (ROE), revenues and authority to order electric utilities to provide transmis customer growth, depreciation rates and other cost sion access to third parties.

of service expenses. The ROE incorporated into Order 888 and Order 889, issued by the FERC, the MoPSC staff's recommendation ranged from are intended to promote competition in the whole 9.04% to 10.04%. The MoPSC is not bound by the sale electric market. The FERC requires transmis MoPSC staff's recommendation. In January 2002, sion-owning public utilities, such as AmerenUE and the MoPSC issued an order that established the test AmerenCIPS, to provide transmission access and year to be used to determine rates as July 1, 2000 service to others in a manner similar and comparable through June 30, 2001, with updates to that test year to that which the utilities have by virtue of ownership.

permitted through September 30, 2001. The MoPSC Order 888 requires that a single tariff be used by the staff had utilized a test year of July 1, 1999 through utility in providing transmission service. Order 888 June 30, 2000 in its original complaint. In addition, also provides for the recovery of stranded costs, under the MoPSC order stated that AmerenUE would be certain conditions, related to the wholesale business.

permitted to propose an incentive regulation plan in Order 889 established the standards of conduct this proceeding. and information requirements that transmission The MoPSC order also included a revised proce owners must adhere to in doing business under the dural schedule to allow all parties additional time to open access rule. Under Order 889, utilities must review data and file testimony, due to the utilization obtain transmission service for their own use in the of a more current test year. Under the new schedule, same manner their customers will obtain service, the MoPSC staff will file direct testimony on March 1, thus mitigating market power through control of 2002, with AmerenUE and the Office of Public transmission facilities. In addition, under Order 889, 22j WWW.AMEREN.COM

utilities must separate their merchant function FERC's latest ruling will have on its future financial (buying and selling wholesale power) from their condition, results of operations or liquidity.

transmission and reliability functions.

In 1998, AmerenUE and AmerenCIPS joined a Illinois group of companies that originally supported the In December 1997, the Governor of Illinois signed formation of the Midwest ISO. An ISO operates, but the Electric Service Customer Choice and Rate Relief does not own, electric transmission systems and Law of 1997 (the Illinois Law) providing for electric maintains system reliability and security, while facili utility restructuring in Illinois. This legislation intro tating wholesale and retail competition through the duces competition into the supply of electric energy elimination of "pancaked" transmission rates. The at retail in Illinois.

Midwest ISO is regulated by the FERC. The FERC Major provisions of the Illinois Law include the conditionally approved the formation of the Midwest phasing-in through 2002 of retail direct access, which ISO in September 1998. allows customers to choose their electric generation In December 1999, the FERC issued Order 2000 supplier. The phase-in of retail direct access began relating to Regional Transmission Organizations on October 1, 1999, with large commercial and indus (RTOs) that would meet certain characteristics such trial customers principally comprising the initial as size and independence. RTOs, including ISOs, group. The remaining commercial and industrial are entities that ensure comparable and non-discrimi customers in Illinois were offered choice on natory access to regional electric transmission December 31, 2000. Commercial and industrial systems. Order 2000 calls on all transmission customers in Illinois represented approximately 16%

owners to join RTOs. of the Company's total sales during 2001. As of In the fourth quarter of 2000, the Company December 31, 2001, the impact of Illinois retail direct announced its intention to withdraw from the access on the Company's financial condition, results Midwest ISO and to join the Alliance RTO, and of operations or liquidity was immaterial. Retail recorded a pretax charge to earnings of $25 million direct access will be offered to Illinois residential

($15 million after taxes, or 11 cents per share), which customers on May 1, 2002.

related to the Company's estimated obligation under Under the Illinois Law, the Company is subject to a the Midwest ISO agreement for costs incurred by residential electric rate decrease of up to 5% in 2002, the Midwest ISO, plus estimated exit costs. In 2001, to the extent its rates exceed the Midwest utility the Company announced that it had signed an agree average at that time. In 2001, the Company's Illinois ment to join the Alliance RTO. In a proceeding electric rates were below the Midwest utility average.

before the FERC, the Alliance RTO and the Midwest The Illinois Law also contains a provision allowing ISO reached an agreement that would enable for the potential recovery of a portion of stranded Ameren to withdraw from the Midwest ISO and to costs, which represent costs that would not be join the Alliance RTO. This settlement agreement recoverable in a restructured environment, through was approved by the FERC. The Company's with a transition charge collected from customers who drawal from the Midwest ISO remains subject to choose an alternate electric supplier. In addition, MoPSC approval. In July 2001, the FERC condition the Illinois Law contains a provision requiring a ally approved the formation, including the rate struc portion of excess earnings (as defined under the ture, of the Alliance RTO. However, on December Illinois Law) for the years 1998 through 2004 to be 20, 2001, the FERC issued an order that reversed its refunded to customers. See Note 2 - Regulatory position and rejected the formation of the Alliance Matters under Notes to Consolidated Financial RTO. Instead, the FERC granted RTO status to Statements for further information.

the Midwest ISO and ordered the Alliance RTO In conjunction with another provision of the Illinois Companies and the Midwest ISO to discuss how Law, on May 1, 2000, following the receipt of all the Alliance RTO business model could be accom required state and federal regulatory approvals, modated within the Midwest ISO. The Alliance RTO AmerenCIPS transferred its electric generating members have until February 19, 2002 to respond assets and liabilities, at historical net book value, to to the FERC's December 2001 order. At this time, Generating Company, in exchange for a promissory the Company is evaluating its alternatives, including note from Generating Company in the principal the possible appeal of the FERC's December 2001 amount of approximately $552 million and Generating order, and is unable to determine the impact that the Company common stock (the Transfer). The promis-AMEREN 2001 ANNUAL REPORT 23

sory note bears interest at 7% and has a term of five included the establishment of a nonregulated generat years payable based on a 10-year amortization. The ing subsidiary, the expansion of its generation assets, transferred assets represent a generating capacity which strengthened its trading and marketing opera of approximately 2,900 megawatts. Approximately tions in order to retain its current customers and 45% of AmerenCIPS' employees were transferred to obtain new customers, and the enhancement of its Generating Company as part of the transaction. information systems. Management believes that In conjunction with the Transfer, an electric these actions position the Company well in the power supply agreement was entered into between competitive Illinois marketplace. In Missouri, the Generating Company and its newly created nonregu Company is actively involved in all major deliberations lated affiliate, AmerenEnergy Marketing Company taking place surrounding electric industry restructuring (Marketing Company), also a wholly-owned subsidiary in an effort to ensure that restructuring legislation, of Resources Company. Under this agreement, if any, contains an orderly transition and is equitable Marketing Company is entitled to purchase all of to the Company's shareholders. At this time, the Generating Company's energy and capacity. This Company is unable to predict the ultimate impact of agreement may not be terminated until at least electric industry restructuring on the Company's future December 31, 2004. In addition, Marketing Company financial condition, results of operations or liquidity.

entered into an electric power supply agreement with AmerenCIPS to supply it sufficient energy and capacity CONTINGENCIES to meet its obligations as a public utility. This agree See Note 2 - Regulatory Matters, Note 11 ment expires December 31, 2004. Power will continue Commitments and Contingencies and Note 12 to be jointly dispatched between AmerenUE and Callaway Nuclear Plant under Notes to Consolidated Generating Company. Financial Statements for material issues existing at The creation of the new subsidiaries and the trans December 31, 2001.

fer of AmerenCIPS' generating assets and liabilities had no effect on the consolidated financial statements ACCOUNTING MATTERS of Ameren as of the date of the Transfer.

In January 2001, the Company adopted Statement The provisions of the Illinois Law could also result in of Financial Accounting Standards (SFAS) No. 133, lower revenues, reduced profit margins and increased "Accounting for Derivative Instruments and Hedging costs of capital and operations expense. At this time, Activities." The impact of that adoption resulted in the the Company is uhable to determine the impact of the Company recording a cumulative effect charge of Illinois Law on the Company's future financial condi

$7 million after taxes to the income statement, and tion, results of operations or liquidity.

a cumulative effect adjustment of $11 million after Missouri income taxes to Accumulated Other Comprehensive In Missouri, where approximately 70% of the Income (OCI), which reduced stockholders' equity.

Company's retail electric revenues are derived, restruc (See Note 3 - Risk Management and Derivative turing bills have been introduced but no legislation has Financial Instruments under Notes to Consolidated been passed. Furthermore, no restructuring legislation Financial Statements for further information). In June is expected to be passed by the Missouri state legisla 2001, the Derivatives Implementation Group (DIG),

ture in 2002. a committee of the Financial Accounting Standards Board (FASB) responsible for providing guidance on Summary the implementation of SFAS 133, reached a conclusion In summary, the potential negative consequences regarding the appropriate accounting treatment of associated with electric industry restructuring could be certain types of energy contracts under SFAS 133.

significant and could include the impairment and write Specifically, the DIG concluded that power purchase down of certain assets, including generation-related or sales agreements (both forward contracts and plant and net regulatory assets, lower revenues, option contracts) may meet an exception for normal reduced profit margins and increased costs of capital purchases and sales accounting treatment if certain and operations expenses. Conversely, a deregulated criteria are met. This guidance was effective begin marketplace can provide earnings enhancement oppor ning July 1, 2001, and did not have a material impact tunities. The Company will continue to focus on cost on the Company's financial condition, results of opera control to ensure that it maintains a competitive cost tions or liquidity upon adoption. However, in October structure. Also, in Illinois, the Company's actions and again in December 2001, the DIG revised this 24J WWW.AMEREN.COM

guidance, with the revisions effective April 1, 2002. with Callaway Nuclear Plant decommissioning costs.

The Company does not expect the impact of the DIG's In August 2001, the FASB issued SFAS No. 144, revisions to have a material effect on the Company's "Accounting for the Impairment or Disposal of Long financial condition, results of operations, or liquidity Lived Assets." SFAS 144 addresses the financial upon adoption. accounting and reporting for the impairment or In September 2001, the DIG issued guidance disposal of long-lived assets and supersedes SFAS regarding the accounting treatment for fuel contracts 121, 'Accounting for the Impairment of Long-Lived that combine a forward contract and a purchased Assets and for Long-Lived Assets to be Disposed Of."

option contract. The DIG concluded that contracts SFAS 144 retains the guidance related to calculating containing both a forward contract and a purchased and recording impairment losses, but adds guidance option contract are not eligible to qualify for the on the accounting for discontinued operations, previ normal purchases and sales exception under SFAS ously accounted for under Accounting Principles 133. This guidance is effective as of April 1, 2002. Board Opinion No. 30. SFAS 144 was adopted by the The Company continues to evaluate the impact of this Company on January 1, 2002. SFAS 144 did not have guidance on its future financial condition, results of a material effect on the Company's financial position, operations and liquidity; however, the impact is not results of operations or liquidity upon adoption.

expected to be material.

In July 2001, the FASB issued SFAS No. 141, EFFECTS OF INFLATION "Business Combinations," and SFAS No. 142, AND CHANGING PRICES "Goodwill and Other Intangible Assets." SFAS 141 The Company's rates for retail electric and gas requires business combinations to be accounted for utility service are generally regulated by the MoPSC under the purchase method of accounting, which and the Illinois Commerce Commission (ICC).

requires one party in the transaction to be identified as Non-retail electric rates are regulated by the FERC.

the acquiring enterprise and for that party to allocate The current replacement cost of the Company's the purchase price to the assets and liabilities of the utility plant substantially exceeds its recorded historical acquired enterprise based on fair market value. It cost. Under existing regulatory practice, only the prohibits use of the pooling-of-interests method of historical cost of plant is recoverable from customers.

accounting for business combinations. SFAS 141 is As a result, cash flows designed to provide recovery effective for all business combinations initiated after of historical costs through depreciation might not be June 30, 2001, or transactions completed using the adequate to replace plants in future years. Regulatory purchase method after June 30, 2001. SFAS 142 practice has been modified for the Company's genera requires goodwill recorded in the financial statements tion portion of its business in its Illinois jurisdiction to be tested for impairment at least annually, rather and may be modified in the future for the Company's than amortized over a fixed period, with impairment Missouri jurisdiction (see Note 2 - Regulatory Matters losses recorded in the income statement. SFAS 142 under Notes to Consolidated Financial Statements became effective for the Company on January 1, 2002. for further information). In addition, the impact on SFAS 141 and SFAS 142 did not have a material effect common stockholders is mitigated to the extent on the Company's financial position, results of opera depreciable property is financed with debt that is tions or liquidity upon adoption. repaid with dollars of less purchasing power.

In addition, in July 2001, the FASB issued SFAS In the Company's retail electric utility jurisdictions, No.143, 'Accounting for Asset Retirement Obligations." the cost of fuel for electric generation is reflected in SFAS 143 requires an entity to record a liability and base rates with no provision for changes in such cost corresponding asset representing the present value to be reflected in billings to customers through fuel of legal obligations associated with the retirement of adjustment clauses. Changes in gas costs relating tangible, long-lived assets. SFAS 143 is effective for to retail gas utility services are generally reflected in fiscal years beginning after June 15, 2002. At this time, billings to customers through purchased gas adjust the Company is assessing the impact of SFAS 143 on ment clauses. The Company is impacted by changes its financial position, results of operations and liquidity in market prices for natural gas to the extent it must upon adoption. However, SFAS 143 is expected purchase natural gas to run its combustion turbine to result in significant increases to the Company's generators. The Company has structured various reported assets and liabilities as a result of its ongoing supply agreements to maintain access to multiple collection through rates of and obligations associated gas pools and supply basins to minimize the impact AMEREN 2001 ANNUAL REPORT I 25

_L to the financial statements (see discussion below would exist in such an environment. In the event of a under "Commodity Price Risk" for further information). significant change in interest rates, management would Inflation continues to be a factor affecting operations, likely take actions to further mitigate its exposure to earnings, stockholders' equity and financial performance. 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 QUANTITATIVE AND QUALITATIVE the Company's financial structure.

DISCLOSURES ABOUT MARKET RISK Market risk represents the risk of changes in value Credit Risk of a physical asset or a financial instrument, derivative Credit risk represents the loss that would be recog or non-derivative, caused by fluctuations in market nized if counterparties fail to perform as contracted.

variables (e.g., interest rates, equity prices, commodity New York Mercantile Exchange (NYMEX) traded prices, etc.). The following discussion of the futures contracts are supported by the financial and Company's risk management activities includes credit quality of the clearing members of the NYMEX "forward-looking" statements that involve risks and and have nominal credit risk. On all other transac uncertainties. Actual results could differ materially tions, the Company is exposed to credit risk in the from those projected in the "forward-looking" state event of nonperformance by the counterparties in ments. The Company handles market risks in accor the transaction.

dance with established policies, which may include The Company's physical and financial instruments entering into various derivative transactions. In the are subject to credit risk consisting of trade accounts normal course of business, the Company also faces receivables and executory contracts with market risk risks that are either non-financial or non-quantifiable. exposures. The risk associated with trade receivables Such risks principally include business, legal, and is mitigated by the large number of customers in operational risk and are not represented in the follow a broad range of industry groups comprising the ing analysis. Company's customer base. No customer represents The Company's risk management objective is to greater than 10% of the Company's accounts receiv optimize its physical generating assets within prudent able. The Company's revenues are primarily derived risk parameters. Risk management policies are set from sales of electricity and natural gas to customers by a Risk Management Steering Committee, which in Missouri and Illinois. The Company analyzes each is comprised of senior-level Ameren officers. counterparty's financial condition prior to entering into forwards, swaps, futures or option contracts.

Interest Rate Risk The Company also establishes credit limits for these The Company is exposed to market risk through counterparties and monitors the appropriateness of changes in interest rates associated with its issuance these limits on an ongoing basis through a credit risk of both long-term and short-term variable-rate debt management program which involves daily exposure and fixed-rate debt, commercial paper, auction-rate reporting to senior management, master trading and long-term debt and auction-rate preferred stock.

netting agreements, and credit support management The Company manages its interest rate exposure by (e.g., letters of credit and parental guarantees).

controlling the amount of these instruments it holds within its total capitalization portfolio and by monitor Commodity Price Risk ing the effects of market changes in interest rates. The Company is exposed to changes in market If interest rates increase 1 % in 2002, as compared to prices for natural gas, fuel and electricity. Several 2001, the Company's interest expense would increase techniques are utilized to mitigate the Company's by approximately $13 million and net income would risk, including utilizing derivative financial instruments.

decrease by approximately $8 million. This amount A derivative is a contract whose value is dependent has been determined using the assumptions that the on, or derived from, the value of some underlying Company's outstanding variable-rate debt, commercial asset. The derivative financial instruments that the paper, auction-rate long-term debt, and auction-rate Company uses (primarily forward contracts, futures preferred stock, as of December 31, 2001, continued to contracts and option contracts) are dictated by risk be outstanding throughout 2002, and that the average management policies.

interest rates for these instruments increased 1% over With regard to its natural gas utility business, the 2001. The model does not consider the effects of the Company's exposure to changing market prices is in reduced level of potential overall economic activity that large part mitigated by the fact that the Company has 261 WWW.RMEREN.COM

purchased gas adjustment clauses (PGAs) in place in use of derivatives has involved transactions that both its Missouri and Illinois jurisdictions. The PGA are expected to reduce price risk exposure for allows the Company to pass on to its retail customers the Company.

its prudently incurred costs of natural gas. With regard to the Company's exposure to commod The Company's subsidiary, AmerenEnergy Fuels ity price risk for purchased power and excess electricity and Services Company, a wholly-owned subsidiary of sales, the Company has a subsidiary, AmerenEnergy, Resources Company, which is responsible for provid whose primary responsibility includes managing market ing fuel procurement and gas supply services on risks associated with changing market prices for elec behalf of the Company's operating subsidiaries, and tricity purchased and sold on behalf of AmerenUE and for managing fuel and natural gas price risks. Fixed Generating Company.

price forward contracts, as well as futures and options, are all instruments, which may be used to manage Equity Price Risk these risks. The majority of the Company's fuel supply The Company maintains trust funds, as required contracts are physical forward contracts. Since the by the Nuclear Regulatory Commission and Missouri Company does not have a provision similar to the PGA and Illinois state laws, to fund certain costs of nuclear for its electric operations, the Company has entered decommissioning (see Note 12- Callaway Nuclear into several long-term contracts with various suppliers Plant under Notes to Consolidated Financial to purchase coal and nuclear fuel to manage its expo Statements for further information). As of December sure to fuel prices (see Note 11 - Commitments and 31, 2001, these funds were invested primarily in Contingencies under Notes to Consolidated Financial domestic equity securities, fixed-rate, fixed-income Statements for further information). Over 95% of the securities, and cash and cash equivalents. By main required 2002 supply of coal for the Company's coal taining a portfolio that includes long-term equity invest plants has been acquired at fixed prices for 2002. In ments, the Company is seeking to maximize the addition, approximately 70% of the coal requirements returns to be utilized to fund nuclear decommissioning through 2006 are covered by contracts. With regard to costs. However, the equity securities included in the the Company's nonregulated electric generating opera Company's portfolio are exposed to price fluctuations tions, the Company is exposed to changes in market in equity markets, and the fixed-rate, fixed-income prices for natural gas to the extent it must purchase securities are exposed to changes in interest rates.

natural gas to run its combustion turbine generators. The Company actively monitors its portfolio by bench The Company's natural gas procurement strategy is marking the performance of its investments against designed to ensure reliable and immediate delivery certain indices and by maintaining, and periodically of natural gas to its intermediate and peaking units reviewing, established target allocation percentages by optimizing transportation and storage options and of the assets of its trusts to various investment minimizing cost and price risk by structuring various options. The Company's exposure to equity price supply agreements to maintain access to multiple gas market risk is, in large part, mitigated, due to the fact pools and supply basins and reducing the impact of that the Company is currently allowed to recover its price volatility. decommissioning costs in its rates.

Although the Company cannot completely eliminate the effects of gas price volatility, its strategy is Fair Value of Contracts designed to minimize the effect of market conditions The Company utilizes derivatives principally to on the results of operations. The Company's gas manage the risk of changes in market prices for procurement strategy includes procuring natural gas natural gas, fuel, electricity and emission credits.

under a portfolio of agreements with price structures, Price fluctuations in natural gas, fuel and electricity including fixed price, indexed price and embedded cause (1) an unrealized appreciation or depreciation of price hedges such as caps and collars. The Company's the Company's firm commitments to purchase or sell strategy also utilizes physical assets through storage, when purchase or sales prices under the firm commit operator and balancing agreements to minimize price ment are compared with current commodity prices; volatility. The Company's electric marketing strategy is (2) market values of fuel and natural gas inventories to extract additional value from its generation facilities or purchased power to differ from the cost of those by selling energy in excess of needs for term sales commodities under the firm commitment; and and purchasing energy when the market price is less (3) actual cash outlays for the purchase of these than the cost of generation. The Company's primary commodities to differ from anticipated cash outlays.

RMEREN 2001 RNNUAL REPORT 127

The derivatives that the Company uses to hedge these "forward-looking" and, accordingly, involve risks and risks are dictated by risk management policies and uncertainties that could cause actual results to differ include forward contracts, futures contracts, options materially from those discussed. Although such and swaps. Ameren primarily uses derivatives to "forward-looking" statements have been made in optimize the value of its physical and contractual posi good faith and are based on reasonable assumptions, tions. Ameren continually assesses its supply and there is no assurance that the expected results will be delivery commitment positions against forward market achieved. These statements include (without limitation) prices and internally forecasts forward prices and statements as to future expectations, beliefs, plans, modifies its exposure to market, credit and operational strategies, objectives, events, conditions, and financial risk by entering into various offsetting transactions. In performance. In connection with the "Safe Harbor" general, these transactions serve to reduce price risk provisions of the Private Securities Litigation Reform for the Company. Act of 1995, the Company is providing this cautionary The following summarizes changes in the fair value statement to identify important factors that could cause of all marked to market contracts during 2001: actual results to differ materially from those anticipated.

The following factors, in addition to those discussed In Millions elsewhere in this report and in subsequent securities Fair value of contracts at January 1, 2001 $(30) filings, could cause results to differ materially from Contracts at January 1, 2001 which were management expectations as suggested by such realized or otherwise settled during 2001 30 "forward-looking" statements: the effects of the Changes in fair values attributable to changes pending AmerenUE excess earnings complaint case in valuation techniques and assumptions and other regulatory actions, including changes in regu Fair value of new contracts entered into latory policy; changes in laws and other governmental during 2001 4 actions; the impact on the Company of current regula Other changes in fair value (5) tions related to the phasing-in of the opportunity for Fair value of contracts outstanding at some customers to choose alternative energy suppliers December 31, 2001 $ (1) in Illinois; the effects of increased competition in the Fair value of contracts as of December 31, 2001 future, due to, among other things, deregulation of certain aspects of the Company's business at both the were as follows:

state and federal levels; the effects of participation in Maturity a FERC approved RTO, including activities associated In Excess Total with the Midwest ISO and the Alliance RTO; future Less Than 1-3 4-5 of 5 Fair market prices for fuel and purchased power, electricity, In Millions 1 year Years Years Years Value (a) and natural gas, including the use of financial and deriv Sources of fair value: ative instruments and volatility of changes in market Prices actively quoted $ $(2) $ - $- $02) prices; average rates for electricity in the Midwest; Prices provided by business and economic conditions; the impact of the other external adoption of new accounting standards; interest rates sources (b) 5 5 and the availability of capital; actions of ratings agen Prices based on cies and the effects of such actions; weather condi models and other tions; fuel prices and availability; generation plant valuation methods (c) - (2) (1) (1) (4) construction, installation and performance; the impact Total Fair Value $5 $(4) $(1) $(1) $(1) of current environmental regulations on utilities and generating companies and the expectation that more (a) Contracts valued at ($1 million) were with noninvestment-grade stringent requirements will be introduced over time, rated counterparties.

(b)Principallypower forward hedges valued basedon NYMEX which could potentially have a negative financial prices for over-the-counter contracts. effect; monetary and fiscal policies; future wages (c) Principallycoal and SO2 options valued based on a Black-Scholes and employee benefits costs; competition from other model that includes information from external sources and generating facilities including new facilities that may Company estimates.

be developed in the future; cost and availability of transmission capacity for the energy generated by the SAFE HARBOR STATEMENT Company's generating facilities or required to satisfy Statements made in this annual report to stock energy sales made by the Company; and legal and holders which are not based on historical facts, are administrative proceedings.

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SCONSOLIDATED STATEMENT OF INCOME Year Ended December 31, 2001 2000 1999 Thousands of Dollars, Except Share and Per Share Amounts Operating Revenues:

Electric $ 4,155,240 $ 3,526,578 $ 3,300,022 342,168 323,886 228,298 Gas 8,459 6,366 7,743 Other 4,505,867 3,856,830 3,536,063 Total Operating Revenues Operating Expenses:

Operations:

1,562,164 1,025,221 973,277 Fuel and purchased power 221,842 209,467 131,449 Gas 708,096 664,544 629,482 Other 2,492,102 1,899,232 1,734,208 382,105 367,921 370,873 Maintenance 405,804 383,110 362,971 Depreciation and amortization 300,052 301,192 258,870 Income taxes 260,817 265,065 246,592 Other taxes 3,840,880 3,216,520 2,973,514 Total Operating Expenses 664,987 640,310 562,549 Operating Income Other Income and (Deductions):

12,893 5,298 7,161 Allowance for equity funds used during construction 674 (4,400) (10,813)

Miscellaneous, net 13,567 898 (3,652)

Total Other Income and (Deductions) 678,554 641,208 558,897 Income Before Interest Charges and Preferred Dividends Interest Charges and Preferred Dividends:

198,648 179,706 168,275 Interest (7,925) (8,292) (7,123)

Allowance for borrowed funds used during construction 12,445 12,700 12,650 Preferred dividends of subsidiaries 203,168 184,114 173,802 Net Interest Charges and Preferred Dividends 475,386 457,094 385,095 Income Before Cumulative Effect of Change in Accounting Principle (6,841) -

Cumulative Effect of Change in Accounting Principle, Net of Income Taxes

$ 468,545 $ 457,094 $ 385,095 Net Income Earnings per Common Share - Basic:

$3.46 $3.33 $2.81 Income before cumulative effect of change in accounting principle

(.05) -

Cumulative effect of change in accounting principle, net of income taxes

$3.41 $3.33 $2.81 Earnings per Common Share - Basic Earnings per Common Share - Diluted:

$3.45 $3.33 $2.81 Income before cumulative effect of change in accounting principle

(.05)

Cumulative effect of change in accounting principle, net of income taxes

$3.40 $3.33 $2.81 Earnings per Common Share - Diluted 137,320,692 137,215,462 137,215,462 Weighted Average Common Shares Outstanding (Note 1)

See Notes to ConsolidatedFinancialStatements.

RMEREN 2001 ANNUAL REPORT 129

• CONSOLIDATED BALANCE SHEET Thousands of Dollars December 31, 2001 2000 20.2000 Assets Property and Plant, at Original Cost:

Electric $13,664,168 $12,684,366 Gas 532,346 509,746 Other 104,790 97,214 14,301,304 13,291,326 Less accumulated depreciation and amortization 6,535,693 6,204,367 7,765,611 7,086,959 Construction work in progress:

Nuclear fuel in process 96,676 117,789 Other 564,275 500,924 Total Property and Plant, Net 8,426,562 7,705,672 Investments and Other Assets:

Investments 39,432 40,235 Nuclear decommissioning trust fund 186,937 190,625 Other 113,493 97,630 Total Investments and Other Assets 339,862 328,490 Current Assets:

Cash and cash equivalents 67,092 125,968 Accounts receivable - trade (less allowance for doubtful accounts of $8,783 and $8,028, respectively) 389,127 474,425 Other accounts and notes receivable 71,234 56,529 Materials and supplies, at average cost:

Fossil fuel 158,800 107,572 Other 136,322 119,478 Other 40,939 37,210 Total Current Assets 863,514 921,182 Regulatory Assets:

Deferred income taxes 604,092 600,100 Other 166,545 158,986 Total Regulatory Assets 770,637 759,086 Total Assets $10,400,575 $ 9,714,430 See Notes to ConsolidatedFinancialStatements.

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Thousands of Dollars, Except Share and Per Share Amounts December 31, 2001 2000 Thousands of Dollars, Except Share and Per Share Amounts December 31. 2001 2000 Capital and Liabilities Capitalization:

Common stock, $.01 par value, 400,000,000 shares authorized shares outstanding of 138,045,639 and 137,215,462, respectively (Note 5) $ 1,380 $ 1,372 Other paid-in capital, principally premium on common stock 1,614,206 1,581,339 Retained earnings 1,733,558 1,613,960 Accumulated other comprehensive income 4,417 Other (4,801)

Total Common Stockholders' Equity 3,348,760 3,196,671 Preferred stock of subsidiaries not subject to mandatory redemption (Note 5) 235,197 235,197 Long-term debt (Note 7) 2,835,378 2,745,068 Total Capitalization 6,419,335 6,176,936 Minority Interest in Consolidated Subsidiaries 3,534 3,940 Current Liabilities:

Current maturity of long-term debt (Note 7) 138,961 44,444 Short-term debt 641,336 203,260 Accounts and wages payable 392,169 462,924 Accumulated deferred income taxes 57,787 49,829 Taxes accrued 132,246 124,706 Other 218,525 300,798 Total Current Liabilities 1,581,024 1,185,961 Commitments and contingencies (Notes 2, 11 and 12)

Accumulated deferred income taxes 1,562,916 1,540,536 Accumulated deferred investment tax credits 157,936 164,120 Regulatory liability 172,290 183,541 Other deferred credits and liabilities 503,540 459,396 Total Capital and Liabilities $10,400,575 $9,714,430 See Notes to ConsolidatedFinancialStatements.

AMEREN 2001 ANNURL REPORT I U

SCONSOLIDATED STATEMENT OF CASH FLOWS Thousands of Dollars Year Ended December 31, 2001 2000 1999 1999 Cash Flows From Operating:

Net income $468,545 $457,094 $385,095 Adjustments to reconcile net income to net cash provided by operating activities:

Cumulative effect of change in accounting principle 6,841 Depreciation and amortization 393,088 370,776 352,761 Amortization of nuclear fuel 29,370 37,101 36,068 Allowance for funds used during construction (20,818) (13,590) (14,284)

Deferred income taxes, net 28,018 1,699 (22,578)

Deferred investment tax credits, net (6,184) (6,714) (7,998)

Changes in assets and liabilities:

Receivables, net 70,593 (139,845) 34,484 Materials and supplies (68,072) 26,174 (7,432)

Accounts and wages payable (70,755) 121,650 56,456 Taxes accrued 7,540 (30,690) 41,290 Other, net (100,124) 31,927 63,713 Net Cash Provided by Operating Activities 738,042 855,582 917,575 Cash Flows From Investing:

Construction expenditures (1,102,586) (928,727) (570,807)

Allowance for funds used during construction 20,818 13,590 14,284 Nuclear fuel expenditures (24,359) (21,527) (21,901)

Other 803 26,241 20,218 Net Cash Used in Investing Activities (1,105,324) (910,423) (558,206)

Cash Flows From Financing:

Dividends on common stock (348,819) (348,527) (348,527)

Redemptions:

Nuclear fuel lease (64,122) (11,356) (15,138)

Long-term debt (63,544) (420,994) (174,444)

Issuances:

Common stock 33,397 -

Nuclear fuel lease 13,418 9,109 64,972 Short-term debt 438,076 55,095 79,637 Long-term debt 300,000 702,600 152,150 Net Cash Provided by (Used in) Financing Activities 308,406 (14,073) (241,350)

Net Change in Cash and Cash Equivalents (58,876) (68,914) 118,019 Cash and Cash Equivalents at Beginning of Year 125,968 194,882 76,863 Cash and Cash Equivalents at End of Year $ 67,092 $125,968 $194,882 Cash paid during the periods:

Interest (net of amount capitalized) $187,121 $168,650 $162,705 Income taxes 266,352 311,848 247,428 See Notes to ConsolidatedFinancialStatements.

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SCONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY Thousands of Dollars Year Ended December 31, 2001 2000 1999 Common Stock:

Beginning balance $ 1,372 $ 1,372 $ 1,372 Shares issued 8 1,380 1,372 1,372 Other Paid-in Capital:

Beginning balance 1,581,339 1,582,501 1,582,548 Shares issued 33,389 -

Employee stock awards (522) (1,162) (47) 1,614,206 1,581,339 1,582,501 Retained Earnings:

Beginning balance 1,613,960 1,505,827 1,472,200 Net income 468,545 457,094 385,095 Dividends (348,947) (348,961) (351,468) 1,733,558 1,613,960 1,505,827 Accumulated Other Comprehensive Income:

Beginning balance Change in current period 4,417 -

4,417 -

Other:

Beginning balance Unamortized restricted stock compensation (5,704) -

Compensation amortized and mark-to-market adjustments 903 (4,801)

Total Common Stockholders' Equity $3,348,760 $3,196,671 $3,089,700 Comprehensive Income, Net of Taxes:

Net income $ 468,545 $ 457,094 $ 385,095 Cumulative effect of accounting change (11,258) -

Unrealized net gain on derivative hedging instruments 15,675 -

$ 472,962 $ 457,094 $ 385,095 See Notes to ConsolidatedFinancialStatements.

AMEREN 2001 ANNUAL REPORT 133

TOSNOTES CONSOLIDATED FINANCIAL STATEMENTS II NOTE 1 -

SUMMARY

OF SIGNIFICANT References to the Company are to Ameren on a consoli ACCOUNTING POLICIES dated basis. However, in certain circumstances, the Basis of Presentation subsidiaries are separately referred to in order to distinguish Ameren Corporation (Ameren or the Company) is a holding among their different business activities.

company registered under the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union Electric Regulation Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) Ameren is subject to regulation by the Securities and combined to form Ameren, with AmerenUE and CIPSCO's Exchange Commission (SEC). Certain of Ameren's subsidiaries subsidiaries, Central Illinois Public Service Company are also regulated by the Missouri Public Service Commission (AmerenCIPS) and CIPSCO Investment Company (CIC), (MoPSC), Illinois Commerce Commission (ICC), Nuclear becoming subsidiaries of Ameren (the Merger). The outstand Regulatory Commission (NRC) and the Federal Energy Regulatory ing preferred shares of AmerenUE and AmerenCIPS were not Commission (FERC). The accounting policies of the Company affected by the Merger. conform to U.S. generally accepted accounting principles (GAAP).

The accompanying consolidated financial statements See Note 2 - Regulatory Matters for further information.

include the accounts of Ameren and its subsidiaries (collec Property and Plant tively, the Company). All subsidiaries for which the Company The cost of additions to, and betterments of, units of prop owns directly or indirectly more than 50% of the voting stock erty and plant is capitalized. Cost includes labor, material, appli are included as consolidated subsidiaries. Ameren's primary cable taxes and overheads. An allowance for funds used operating companies, AmerenUE, AmerenCIPS, and during construction is also added for the Company's regulated AmerenEnergy Generating Company (Generating Company), assets, and interest during construction is added for nonregu a wholly-owned subsidiary of AmerenEnergy Resources lated assets. Maintenance expenditures and the renewal of Company (Resources Company), are engaged principally in items not considered units of property are charged to income, the generation, transmission, distribution and sale of electric as incurred. When units of depreciable property are retired, the energy and the purchase, distribution, transportation and sale original cost and removal cost, less salvage value, are charged of natural gas. The operating companies serve 1.5 million to accumulated depreciation.

electric and 300,000 natural gas customers in a 44,500-square mile area of Missouri and Illinois. The Company's other Depreciation principal subsidiaries include: CIC, an investing subsidiary; Depreciation is provided over the estimated lives of the AmerenEnergy, Inc., an energy trading and marketing various classes of depreciable property by applying composite subsidiary; Ameren Development Company, a nonregulated rates on a straight-line basis. The provision for depreciation in products and services subsidiary; Resources Company, a 2001, 2000, and 1999 was approximately 3% of the average holding company for the Company's nonregulated generating depreciable cost.

operations; and Ameren Services Company, a shared support Fuel and Gas Costs services subsidiary. The Company also has a 60% interest in In the Company's retail electric utility jurisdictions, the cost Electric Energy, Inc. (EEl). EEl owns and/or operates electric of fuel for electric generation is reflected in base rates with no generation and transmission facilities in Illinois that supply provision for changes in such cost to be reflected in billings to electric power primarily to a uranium enrichment plant located customers through fuel adjustment clauses. In the Company's in Paducah, Kentucky. All significant intercompany balances retail gas utility jurisdictions, changes in gas costs are generally and transactions have been eliminated from the consolidated reflected in billings to gas customers through purchased gas financial statements. adjustment clauses.

34j1WWW.AMEREN.COM

Nuclear Fuel a cash flow hedge, or a foreign currency hedge will determine The cost of nuclear fuel is amortized to fuel expense on a when the gains or losses on the derivatives are to be reported unit-of-production basis. Spent fuel disposal cost is charged in earnings and when they are to be reported as a component to expense, based on net kilowatthours generated and sold. of other comprehensive income in stockholders' equity. See Note 3 - Risk Management and Derivative Financial Cash and Cash Equivalents Instruments for further information.

Cash and cash equivalents include cash on hand and The Emerging Issues Task Force of the Financial temporary investments purchased with an original maturity Accounting Standards Board (EITF) Issue 98-10, 'Accounting of three months or less.

for Energy Trading and Risk Management Activities" became Income Taxes effective on January 1, 1999. EITF 98-10 provides guidance The Company and its subsidiaries file a consolidated federal on the accounting for energy contracts entered into for the tax return. Deferred tax assets and liabilities are recognized purchase or sale of electricity, natural gas, capacity and trans for the tax consequences of transactions that have been portation. The EITF reached a consensus in EITF 98-10 that treated differently for financial reporting and tax return sales and purchase activities being performed need to be purposes, measured using statutory tax rates. classified as either trading or non-trading. Furthermore, trans Investment tax credits utilized in prior years were deferred actions that are determined to be trading activities would be and are being amortized over the useful lives of the related recognized on the balance sheet measured at fair value, with properties. changes in fair market value included in earnings.

Allowance for Funds Used During Construction AmerenEnergy, Inc. enters into contracts, some of which Allowance for funds used during construction (AFC) is are derivatives, for the sale and purchase of energy on behalf a utility industry accounting practice whereby the cost of of AmerenUE and Generating Company. Derivatives are borrowed funds and the cost of equity funds (preferred and accounted for under SFAS 133 or EITF 98-10 based on the common stockholders' equity) applicable to the Company's Company's intent when entering into the contract. Virtually regulated construction program are capitalized as a cost of all non-derivative contracts are accounted for using the accrual construction. AFC does not represent a current source of or settlement method.

cash funds. This accounting practice offsets the effect on Software earnings of the cost of financing current construction, and Statement of Position (SOP) 98-1, 'Accounting for the treats such financing costs in the same manner as construc Costs of Computer Software Developed or Obtained for tion charges for labor and materials. Internal Use" became effective on January 1, 1999. SOP 98-1 Under accepted ratemaking practice, cash recovery of AFC, provides guidance on accounting for the costs of computer as well as other construction costs, occurs when completed software developed or obtained for internal use. Under SOP projects are placed in service and reflected in customer rates. 98-1, certain costs may be capitalized and amortized over The AFC ranges of rates used were 4% - 10% during 2001, some future period.

6% - 10% during 2000, and 5% - 10% during 1999.

Evaluation of Assets for Impairment Unamortized Debt Discount, Premium and Expense SFAS 121, 'Accounting for the Impairment of Long-Lived Discount, premium and expense associated with long-term Assets and for Long-Lived Assets to be Disposed Of," prescribes debt are amortized over the lives of the related issues.

general standards for the recognition and measurement of Revenue impairment losses. The Company determines if long-lived The Company accrues an estimate of electric and gas assets are impaired by comparing their undiscounted expected revenues for service rendered, but unbilled, at the end of future cash flows to their carrying amount. An impairment loss each accounting period. is recognized if the undiscounted expected future cash flows Energy Contracts are less than the carrying amount of the asset. SFAS 121 also Statement of Financial Accounting Standards (SFAS) No. requires that regulatory assets which are no longer probable 133, 'Accounting for Derivative Instruments and Hedging of recovery through future revenues be charged to earnings Activities," became effective on January 1, 2001. SFAS 133 (see Note 2 - Regulatory Matters for further information).

establishes accounting and reporting standards for derivative As of December 31, 2001, no impairment was identified.

instruments, including certain derivative instruments embed In August 2001, the Financial Accounting Standards Board ded in other contracts, and for hedging activities and requires (FASB) issued SFAS No. 144, "Accounting for the Impairment recognition of all derivatives as either assets or liabilities on or Disposal of Long-Lived Assets." SFAS 144 addresses the balance sheet measured at fair value. The intended use of the financial accounting and reporting for the impairment derivatives and their designation as either a fair value hedge, or disposal of long-lived assets and supersedes SFAS 121.

AMEREN 2001 ANNUAL REPORT1 3

SFAS 144 retains the guidance related to calculating and purchase price to the assets and liabilities of the acquired recording impairment losses, but adds guidance on the enterprise based on fair market value. It prohibits use of the accounting for discontinued operations, previously accounted pooling-of-interests method of accounting for business combi for under Accounting Principles Board Opinion No. 30. SFAS nations. SFAS 141 is effective for all business combinations 144 was adopted by the Company on January 1, 2002, and did initiated after June 30, 2001, or transactions completed using not have a material effect on the Company's financial position, the purchase method after June 30, 2001. SFAS 142 requires results of operations or liquidity. goodwill recorded in the financial statements to be tested Asset Retirement Obligations for impairment at least annually, rather than amortized over a In July 2001, the FASB issued SFAS 143, 'Accounting for fixed period, with impairment losses recorded in the income Asset Retirement Obligations." SFAS 143 requires an entity statement. SFAS 142 became effective for the Company to record a liability and corresponding asset representing the on January 1, 2002. SFAS 141 and SFAS 142 did not have a present value of legal obligations associated with the retirement material effect on the Company's financial position, results of tangible, long-lived assets. SFAS 143 is effective for fiscal of operations or liquidity upon adoption.

years beginning after June 15, 2002. At this time, the Company Reclassifications is assessing the impact of SFAS 143 on its financial position, Certain reclassifications have been made to prior years' results of operations and liquidity upon adoption. However, financial statements to conform with 2001 reporting.

SFAS 143 is expected to result in significant increases to the Company's reported assets and liabilities as a result of its NOTE 2 - REGULATORY MATTERS ongoing collection through rates of and obligations associated Missouri Electric with Callaway Nuclear Plant decommissioning costs. See In July 1995, the MoPSC approved an agreement estab Note 12 - Callaway Nuclear Plant for further information. lishing contractual obligations involving AmerenUE's Stock Compensation Plans Missouri retail electric rates. Included was a three-year The Company applies Accounting Principles Board Opinion experimental alternative regulation plan (the Original Plan)

(APB) 25, 'Accounting for Stock Issued to Employees" in that ran from July 1, 1995, through June 30, 1998, which accounting for its plans. See Note 10- Stock-Based provided that earnings in those years in excess of a 12.61%

Compensation for further information. regulatory return on equity (ROE) be shared equally between Earnings Per Share customers and stockholders, and earnings above a 14% ROE The Company's calculation of diluted earnings per share be credited to customers. The formula for computing the resulted in dilution of $.01 for 2001. There was no differ credit used twelve-month results ending June 30, rather than ence between the basic and diluted earnings per share calendar year earnings.

amounts in 2000 and 1999. The reconciling item in each The MoPSC staff proposed adjustments to AmerenUE's of the years is comprised of assumed stock option conver estimated customer credit of $43 million for the final year of sions, which increased the number of shares outstanding in the Original Plan ended June 30, 1998, which were the subject the diluted earnings per share calculation by 331,813 shares, of regulatory proceedings before the MoPSC in 1999. In 183,201 shares, and 38,786 shares in 2001, 2000 and 1999, December 1999, the MoPSC issued a Report and Order (Order) respectively. concerning these proposed adjustments. Based on the provi sions of that Order, AmerenUE revised its estimated final year Use of Estimates credit of the Original Plan to $31 million in the quarter ended The preparation of financial statements in conformity December 31, 1999. Subsequently, AmerenUE filed a request with GAAP requires management to make certain estimates for rehearing of the Order with the MoPSC, asking that it and assumptions. Such estimates and assumptions affect reconsider its decision to adopt certain of the MoPSC staff's reported amounts of assets and liabilities and disclosure of adjustments. The request was denied by the MoPSC and in contingent assets and liabilities at the date of the financial February 2000, AmerenUE filed a Petition for Writ of Review statements and the reported amounts of revenues and with the Circuit Court of Cole County, Missouri, requesting that expenses during the reported period. Actual results could the Order be reversed. The appeal is pending and the ultimate differ from those estimates.

outcome cannot be predicted; however, the final decision New Accounting Pronouncements is not expected to materially impact the financial condition, In July 2001, the FASB issued SFAS No. 141, "Business results of operations or liquidity of the Company. A partial stay Combinations," and SFAS No. 142, "Goodwill and Other of the Order was granted by the Court pending the appeal.

Intangible Assets." SFAS 141 requires business combinations A new three-year experimental alternative regulation plan to be accounted for under the purchase method of accounting, (the New Plan) was included in the joint agreement authorized which requires one party in the transaction to be identified by the MoPSC in its February 1997 order approving the as the acquiring enterprise and for that party to allocate the Merger. Like the Original Plan, the New Plan required an 361 WWW.RMEREN.COM

earnings over a 12.61% ROE up to a 14% ROE be shared with all pertinent parties with the intent to continue with an equally between customers and stockholders. The New Plan incentive regulation plan, similar in form to the New Plan. The also returned to customers 90% of all earnings above a 14% Company cannot predict the outcome of these negotiations ROE up to a 16% ROE. Earnings above a 16% ROE were and their impact on the Company's financial position, results of credited entirely to customers. The New Plan ran from July 1, operations or liquidity; however, the impact could be material.

1998 through June 30, 2001. In May 2001, the MoPSC Gas approved a stipulation and agreement of the parties regarding In October 2000, the MoPSC approved a $4 million annual the credit for the plan year ended June 30, 2000 of $28 rate increase for natural gas service in AmerenUE's Missouri million, which was paid. At December 31, 2001, the Company jurisdiction. The rate increase became effective November 1, recorded an estimated credit that AmerenUE expects to pay 2000. In February 1999, the ICC approved a $9 million total its Missouri electric customers of $40 million for the plan year annual rate increase for natural gas service in AmerenUE's ended June 30, 2001. During the year ended December 31, and AmerenCIPS' Illinois jurisdictions. The increase became 2001, the Company reduced the estimated credit previously effective in February 1999.

recorded for the plan year ended June 30, 2001 by $10 million, compared to estimated credits of $65 million recorded in Midwest ISO and Alliance RTO the year ago period for plan years ended June 30, 2001 and In 1998, AmerenUE and AmerenCIPS joined a group of 2000. These credits were reflected as a reduction in electric companies that originally supported the formation of the revenues. The final amount of the 2001 credit will depend Midwest Independent System Operator (Midwest ISO).

on several factors, including approval by the MoPSC. An ISO operates, but does not own, electric transmission With the New Plan's expiration on June 30, 2001, on July systems and maintains system reliability and security, while 2, 2001, the MoPSC staff filed with the MoPSC an excess facilitating wholesale and retail competition through the elimi earnings complaint against AmerenUE that proposed to nation of "pancaked" transmission rates. The Midwest ISO is reduce its annual electric revenues ranging from $213 million regulated by the FERC. The FERC conditionally approved the to $250 million. Factors contributing to the MoPSC staff's formation of the Midwest ISO in September 1998.

recommendation included return on equity (ROE), revenues In December 1999, the FERC issued Order 2000 relating to and customer growth, depreciation rates and other cost of Regional Transmission Organizations (RTOs) that would meet service expenses. The ROE incorporated into the MoPSC certain characteristics such as size and independence. RTOs, staff's recommendation ranged from 9.04% to 10.04%. The including ISOs, are entities that ensure comparable and non MoPSC is not bound by the MoPSC staff's recommendation. discriminatory access to regional electric transmission systems.

In January 2002, the MoPSC issued an order that established Order 2000 calls on all transmission owners to join RTOs.

the test year to be used to determine rates as July 1, 2000 In the fourth quarter of 2000, the Company announced its through June 30, 2001, with updates to that test year permit intention to withdraw from the Midwest ISO and to join the ted through September 30, 2001. The MoPSC staff had Alliance RTO, and recorded a pretax charge to earnings of $25 utilized a test year of July 1, 1999 through June 30, 2000 in million ($15 million after taxes, or 11 cents per share), which its original complaint. In addition, the MoPSC order stated related to the Company's estimated obligation under the that AmerenUE would be permitted to propose an incentive Midwest ISO agreement for costs incurred by the Midwest regulation plan in this proceeding. ISO, plus estimated exit costs. In 2001, the Company The MoPSC order also included a revised procedural announced that it had signed an agreement to join the schedule to allow all parties additional time to review data Alliance RTO. In a proceeding before the FERC, the Alliance and file testimony, due to the utilization of a more current RTO and the Midwest ISO reached an agreement that would test year. Under the new schedule, the MoPSC staff will file enable Ameren to withdraw from the Midwest ISO and to join direct testimony on March 1, 2002, with AmerenUE and the the Alliance RTO. This settlement agreement was approved Office of Public Counsel filing rebuttal testimony on May 10, by the FERC. The Company's withdrawal from the Midwest 2002. Evidentiary hearings on the MoPSC staff's recommen ISO remains subject to MoPSC approval. In July 2001, the dation are scheduled to be conducted before the MoPSC FERC conditionally approved the formation, including the rate beginning in July 2002. In the event that the MoPSC ulti structure, of the Alliance RTO. However, on December 20, mately determines that a rate decrease is warranted in this 2001, the FERC issued an order that reversed its position and case, that rate reduction would be retroactive to April 1, 2002, rejected the formation of the Alliance RTO. Instead, the FERC regardless of when the MoPSC issues its decision. A final granted RTO status to the Midwest ISO and ordered the decision on this matter may not occur until the fourth quarter Alliance RTO Companies and the Midwest ISO to discuss how of 2002. Depending on the outcome of the MoPSC's deci the Alliance RTO business model could be accommodated sion, further appeals in the courts may be warranted. within the Midwest ISO. The Alliance RTO members have In the interim, the Company expects to continue negotiations until February 19, 2002 to respond to the FERC's December RMEREN 2001 ANNUAL REPORT 137

2001 order. At this time, the Company is evaluating its alterna federal regulatory approvals, AmerenCIPS transferred its tives, including the possible appeal of the FERC's December electric generating assets and liabilities, at historical net book 2001 order, and is unable to determine the impact that the value, to Generating Company, in exchange for a promissory FERC's latest ruling will have on its future financial condition, note from Generating Company in the principal amount of results of operations or liquidity. approximately $552 million and Generating Company common Illinois Electric Restructuring and Related Matters stock (the Transfer). The promissory note bears interest at In December 1997, the Governor of Illinois signed the 7% and has a term of five years payable based on a 10-year Electric Service Customer Choice and Rate Relief Law of 1997 amortization. The transferred assets represent a generating (the Illinois Law) providing for electric utility restructuring in capacity of approximately 2,900 megawatts. Approximately Illinois. This legislation introduces competition into the supply 45% of AmerenCIPS' employees were transferred to of electric energy at retail in Illinois. Generating Company as part of the transaction.

Under the Illinois Law, retail direct access, which allows In conjunction with the Transfer, an electric power supply customers to choose their electric generation suppliers, will agreement was entered into between Generating Company be phased in over several years. Access for commercial and and its newly created nonregulated affiliate, AmerenEnergy industrial customers occurred over a period from October Marketing Company (Marketing Company), also a wholly 1999 to December 2000, and access for residential customers owned subsidiary of Resources Company. Under this agree will occur after May 1, 2002. ment, Marketing Company is entitled to purchase all of the As a requirement of the Illinois Law, in March 1999, Generating Company's energy and capacity. This agreement AmerenUE and AmerenCIPS filed delivery service tariffs with may not be terminated until at least December 31, 2004. In the ICC. These tariffs would be used by electric customers addition, Marketing Company entered into an electric power who choose to purchase their power from alternate suppliers. supply agreement with AmerenCIPS to supply it sufficient In August 1999, the ICC issued an order approving the delivery energy and capacity to meet its obligations as a public utility.

service tariffs, with an allowed rate of return on equity of This agreement expires December 31, 2004. Power will 10.45%. In December 2000, AmerenUE and AmerenCIPS continue to be jointly dispatched between AmerenUE and filed revised Illinois delivery service tariffs with the ICC. The Generating Company.

purpose of the filing was to update financial information that The creation of the new subsidiaries and the transfer of was used to establish the initial rates and to propose new AmerenCIPS' generating assets and liabilities had no effect rates. Additionally, the filing establishes tariffs for residential on the consolidated financial statements of Ameren as of customers who may choose to purchase their power from the date of the Transfer.

alternate suppliers beginning in May 2002. In December In August 1999, the Company filed a transmission system 2001, the ICC issued an Order approving the delivery service rate case with the FERC. This filing was primarily designed tariffs, with an allowed rate of return on equity of 11.35%. to implement rates, terms and conditions for transmission Under the Illinois Law, the Company is subject to a residen service for wholesale customers and those retail customers tial electric rate decrease of up to 5% in 2002, to the extent its in Illinois who choose other suppliers as allowed under the rates exceed the Midwest utility average at that time. In 2001, Illinois Law. In January 2000, the Company and other parties the Company's Illinois electric rates were below the Midwest to the rate case entered into a settlement agreement resolving utility average. all issues pending before the FERC. In May 2000, the FERC The Illinois Law also contains a provision requiring that approved the settlement and allowed the settlement rates to one-half of excess earnings from the Illinois jurisdiction for become effective as of the first quarter of 2000.

the years 1998 through 2004 be refunded to Ameren's Illinois The provisions of the Illinois Law could also result in lower customers. Excess earnings are defined as the portion of revenues, reduced profit margins and increased costs of the two-year average annual rate of return on common equity capital and operations expense. At this time, the Company in excess of 1.5% of the two-year average of an Index, as is unable to determine the impact of the Illinois Law on the defined in the Illinois Law. The Index is defined as the sum of Company's future financial condition, results of operations the average for the twelve months ended September 30 of or liquidity.

the average monthly yields of the 30-year U.S. Treasury bonds, Missouri Electric Restructuring plus prescribed percentages ranging from 4% to 7%. Filings In Missouri, where approximately 70% of the Company's must be made with the ICC on, or before, March 31 of each retail electric revenues are derived, restructuring bills have year 2000 through 2005. The Company did not record any been introduced but no legislation has been passed. Further estimated refunds to Illinois customers in 2001. more, no restructuring legislation is expected to be passed by In conjunction with another provision of the Illinois Law, the Missouri state legislature in 2002. The potential negative on May 1, 2000, following the receipt of all required state and consequences of electric industry restructuring could be 381 WWW.AMEREN.COM

significant and include the impairment and write-down of NOTE 3 - RISK MANAGEMENT AND certain assets, including generation-related plant and net DERIVATIVE FINANCIAL INSTRUMENTS regulatory assets, lower revenues, reduced profit margins The Company handles market risks in accordance with and increased costs of capital and operations expense. At established policies, which may include entering into various December 31, 2001, the Company's net investment in genera derivative transactions. In the normal course of business, tion facilities related to its Missouri jurisdiction approximated the Company also faces risks that are either non-financial or

$2.8 billion and was included in electric plant in-service on the non-quantifiable. The Company's risk management objective Company's balance sheet. In addition, at December 31, 2001, is to optimize its physical generating assets within prudent the Company's Missouri net generation-related regulatory risk parameters. Risk management policies are set by a Risk assets approximated $449 million. Management Steering Committee, which is comprised of Regulatory Assets and Liabilities senior-level Ameren officers.

In accordance with SFAS No. 71 'Accounting for the Market Risk Effects of Certain Types of Regulation," the Company has The Company engages in price risk management activities deferred certain costs pursuant to actions of its regulators, related to electricity and fuel. In addition to physically buying and is currently recovering such costs in electric rates and selling these commodities, the Company uses derivative charged to customers. financial instruments to manage market risks and to reduce At December 31, the Company had recorded the following exposure resulting from fluctuations in interest rates and the regulatory assets and regulatory liability: prices of electricity and fuel. Hedging instruments used In Millions 2001 2000 include futures, forward contracts, options and swaps. The primary use of these instruments is to manage and hedge Regulatory Assets:

contractual commitments and to reduce exposure related to Income taxes (a) $604 $600 commodity market prices and interest rate volatility.

Callaway costs (b) 84 88 Unamortized loss on reacquired debt (c) 28 31 Credit Risk Recoverable costs-contaminated facilities(d) 26 6 Credit risk represents the loss that would be recognized Merger costs (e) 12 17 if counterparties fail to perform as contracted. New York Other 17 17 Mercantile Exchange (NYMEX) traded futures contracts are Regulatory Assets $771 $759 supported by the financial and credit quality of the clearing Regulatory Liability: members of the NYMEX and have nominal credit risk. On Income taxes (a) $172 $184 all other transactions, the Company is exposed to credit risk Regulatory Liability $172 $184 in the event of nonperformance by the counterparties in the transaction.

(a) See Note 8 - Income Taxes. The Company's physical and financial instruments are (b) Represents Callaway NuclearPlant operationsand maintenance subject to credit risk consisting of trade accounts receiv expenses,property taxes and carrying costs incurred between the plant ables and executory contracts with market risk exposures.

in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaininglife of the plant (through2024). The risk associated with trade receivables is mitigated by (c) Represents losses relatedto refundeddebt. These amounts are being the large number of customers in a broad range of indus amortized over the lives of the related new debt issues or the remaining "trygroups comprising the Company's customer base. No lives of the old debt issues if no new debt was issued. customer represents greater than 10% of the Company's (d) Represents the recoverableportion of accrued environmental accounts receivable. The Company's revenues are prima site liabilities. rily derived from sales of electricity and natural gas to (e) Represents the portion of merger-relatedexpenses applicableto the customers in Missouri and Illinois. The Company analyzes Missouriretailjurisdiction. These costs are being amortized within 10 years, based on a MoPSC order. each counterparty's financial condition prior to entering into forwards, swaps, futures or option contracts. The The Company continually assesses the recoverability of its Company also establishes credit limits for these counter regulatory assets. Under current accounting standards, regu parties and monitors the appropriateness of these limits latory assets are written off to earnings when it is no longer on an ongoing basis through a credit risk management probable that such amounts will be recovered through future program which involves daily exposure reporting to senior revenues. However, as noted in the above paragraphs, management, master trading and netting agreements, electric industry restructuring legislation may impact the and credit support management (e.g., letters of credit and recoverability of regulatory assets in the future. parental guarantees).

AMEREN 2001 ANNUAL REPORT 1 39

Derivative Financial Instruments gas, fuel and electricity cause (1) an unrealized appreciation In January 2001, the Company adopted SFAS No. 133, or depreciation of the Company's firm commitments to

'Accounting for Derivative Instruments and Hedging purchase or sell when purchase or sales prices under the firm Activities." The impact of that adoption resulted in the commitment are compared with current commodity prices; Company recording a cumulative effect charge of $7 million (2) market values of fuel and natural gas inventories or after taxes to the income statement, and a cumulative effect purchased power to differ from the cost of those commodi adjustment of $11 million after income taxes to Accumulated ties under the firm commitment; and (3) actual cash outlays Other Comprehensive Income (OCI), which reduced stock for the purchase of these commodities to differ from antici holders' equity. In June 2001, the Derivatives Implementation pated cash outlays. The derivatives that the Company uses Group (DIG), a committee of the FASB responsible for provid to hedge these risks are dictated by risk management poli ing guidance on the implementation of SFAS 133, reached a cies and include forward contracts, futures contracts, options conclusion regarding the appropriate accounting treatment and swaps. Ameren primarily uses derivatives to optimize of certain types of energy contracts under SFAS 133. the value of its physical and contractual positions. Ameren Specifically, the DIG concluded that power purchase or sales continually assesses its supply and delivery commitment agreements (both forward contracts and option contracts) positions against forward market prices and internally fore may be accounted for as normal purchases and sales if casts forward prices and modifies its exposure to market, certain criteria are met. This guidance was effective begin credit and operational risk by entering into various offsetting ning July 1, 2001, and did not have a material impact on transactions. In general, these transactions serve to reduce the Company's financial condition, results of operations or price risk for the Company.

liquidity. However, in October and again in December 2001, As of December 31, 2001, the Company has recorded the DIG revised this guidance, with the revisions generally the fair value of derivative financial instrument assets of effective April 1, 2002. The Company does not expect the $17 million in Other Assets and the fair value of derivative impact of the DIG's revisions to have a material effect on financial instrument liabilities of $18 million in Other Deferred the Company's financial condition, results of operations, Credits and Liabilities.

or liquidity upon adoption.

SFAS 133 requires all derivatives to be recognized on Cash Flow Hedges the balance sheet at their fair value. On the date that the The Company routinely enters into forward purchase and Company enters into a derivative contract, it designates the sales contracts for electricity based on forecasted levels of derivative as (1) a hedge of the fair value of a recognized economic generation and load requirements. The relative asset or liability or an unrecognized firm commitment (a "fair balance between load and economic generation varies value" hedge); (2) a hedge of a forecasted transaction or throughout the year. The contracts typically cover a period the variability of cash flows that are to be received or paid in of twelve months or less. The purpose of these contracts connection with a recognized asset or liability (a "cash flow" is to hedge against possible price fluctuations in the spot hedge); or (3) an instrument that is held for trading or market for the period covered under the contracts. The non-hedging purposes (a "non-hedging" instrument). The Company formally documents all relationships between Company reevaluates its classification of individual derivative hedging instruments and hedged items, as well as its risk transactions daily. management objective and strategy for undertaking various Changes in the fair value of derivatives are recorded each hedge transactions.

period in current earnings or OCI, depending on whether a As of December 31, 2001, a gain of $7 million ($4.3 million, derivative is designated as part of a hedge transaction and, if after tax) associated with interest rate swaps for debt to be it is, the type of hedge transaction. For fair-value hedge trans issued was in OCI and will be amortized over the life of the actions, changes in the fair value of the derivative instrument debt ultimately issued or will be recognized immediately to are offset in the income statement by changes in the hedged the income statement if a determination is made that debt item's fair value. For cash-flow hedge transactions, changes will not be issued.

in the fair value of the derivative instrument are reported in For the year ended December 31, 2001, the pretax net OCI. The gains and losses on the derivative instrument that gain, which represented the impact of discontinued cash flow are reported in OCI will be reclassified as earnings in the hedges, the ineffective portion of cash flow hedges, as well periods in which earnings are impacted by the variability of as the reversal of amounts previously recorded in OCI due to the cash flows of the hedged item. The ineffective portion transactions going to delivery, was approximately $15 million.

of all hedges is recognized in current-period earnings. As of December 31, 2001, the entire net gain on derivative The Company utilizes derivatives principally to manage instruments accumulated in OCI is expected to be recognized the risk of changes in market prices for natural gas, fuel, in earnings during the next twelve months upon delivery of electricity and emission credits. Price fluctuations in natural the commodity being hedged.

401 WWW.AMEREN.COM

Other Derivatives NOTE 5 - SHAREHOLDER RIGHTS PLAN The Company enters into option transactions to manage AND PREFERRED STOCK OF SUBSIDIARIES the Company's positions in sulfur dioxide (SO 2 ) allowances, In October 1998, the Company's Board of Directors coal, heating oil, and electricity. These transactions are approved a share purchase rights plan designed to assure treated as non-hedge transactions under SFAS 133. The net shareholders of fair and equal treatment in the event of a change in the market value of SO 2 options is recorded as proposed takeover. The rights will be exercisable only if a electric revenues, while the net change in the market value person or group acquires 15% or more of Ameren's common of coal, heating oil, and electricity options is recorded as fuel stock or announces a tender offer, the consummation of and purchased power in the income statement. which would result in ownership by a person or group of The Company has entered into fixed-price forward 15% or more of the common stock. Each right will entitle contracts for the purchase of fuel. While these contracts the holder to purchase one one-hundredth of a newly issued meet the definition of a derivative under SFAS 133, the preferred stock at an exercise price of $180. If a person Company records these transactions as normal purchases or group acquires 15% or more of Ameren's outstanding and normal sales because the contracts are expected to result common stock, each right will entitle its holder (other than in physical delivery. In September 2001, the DIG issued guid such person or members of such group) to purchase, at the ance regarding the accounting treatment for fuel contracts right's then-current exercise price, a number of Ameren's that combine a forward contract and a purchased option common shares having a market value of twice such price.

contract. The DIG concluded that contracts containing both a In addition, if Ameren is acquired in a merger or other busi forward contract and a purchased option contract that extends ness combination transaction after a person or group has the quantity to be purchased at a fixed price are not eligible acquired 15% or more of the Company's outstanding to qualify for the normal purchases and sales exception under common stock, each right will entitle its holder to purchase, SFAS 133. This guidance is effective as of April 1, 2002. The at the right's then-current exercise price, a number of the Company continues to evaluate the impact of this guidance on acquiring company's common shares having a market value its future financial condition, results of operations or liquidity; of twice such price. The acquiring person or group will not however, the impact is not expected to be material. be entitled to exercise these rights. The SEC approved the plan under PUHCA in December 1998. The rights were NOTE 4 - NUCLEAR FUEL LEASE issued as a dividend payable January 8, 1999, to shareholders The Company has a lease agreement that provides for of record on that date; these rights expire in 2008. One right the financing of a portion of its nuclear fuel. At December 31, will accompany each new share of Ameren common stock 2001, the maximum amount that could be financed under issued prior to such expiration date.

the agreement was $120 million. Pursuant to the terms of At December 31, 2001 and 2000, AmerenUE and the lease, the Company has assigned to the lessor certain AmerenCIPS had 25 million shares and 4.6 million shares contracts for purchase of nuclear fuel. The lessor obtains, respectively, of authorized preferred stock.

through the issuance of commercial paper or from direct loans Outstanding preferred stock is entitled to cumulative under a committed revolving credit agreement from commer dividends and is redeemable at the prices shown in the cial banks, the necessary funds to purchase the fuel and make following table:

interest payments when due.

The Company is obligated to reimburse the lessor for Redemption Price December 31, Dollars In Millions (per share) 2001 2000 expenditures for nuclear fuel, interest and related costs under the lease. Obligations under this lease become due as any Preferred Stock of Subsidiaries Not leased nuclear fuel is consumed at the Company's Callaway Subject to Mandatory Redemption:

Nuclear Plant. No leased nuclear fuel was consumed in Without par value and stated 2001. The Company reimbursed the lessor $13 million in value of $100 per share 2000 and $16 million during 1999 for amounts consumed $7.64 Series -330,000 shares $103.82(a) $ 33 $ 33 under the lease. $5.50 Series A - 14,000 shares 110.00 1 1 The Company has capitalized the cost, including certain $4.75 Series -20,000 shares 102.176 2 2 interest costs, of the leased nuclear fuel and has recorded the $4.56 Series -200,000 shares 102.47 20 20 related lease obligation. Total interest charges under the lease $4.50 Series -213,595 shares 110.00(b) 21 21 were $4 million in 2001, $8 million in 2000, and $5 million in $4.30 Series -40,000 shares 105.00 4 4 1999. Interest charges for these years were based on average $4.00 Series - 150,000 shares 105.625 15 15 interest rates of approximately 5% for 2001 and 7% for 2000 $3.70 Series -40,000 shares 104.75 4 4 and 1999. Interest charges of $4 million in 2001, $6 million in $3.50 Series -130,000 shares 110.00 13 13 2000, and $4 million in 1999 were capitalized. (Continuedon next page)

AMEREN 2001 ANNUAL REPORT 141

Redemption Price December 31, NOTE 7 - LONG-TERM DEBT Dollars In Millions (per share) 2001 2000 December 31, Preferred Stock of Subsidiaries Not In Millions 2001 2000 Subject to Mandatory Redemption, continued: First Mortgage Bonds (a)

With par value of $100 per share 8.33% Series due 2002 $75 $75 4.00% Series -150,000 shares 101.00 15 15 6 %% Series Z due 2003 40 40 4.25% Series -50,000 shares 102.00 5 5 7.65% Series due 2003 100 100 4.90% Series -75,000 shares 102.00 8 8 6 1/4% Series due 2004 188 188 4.92% Series -50,000 shares 103.50 5 5 7 %% Series due 2004 85 85 5.16% Series -50,000 shares 102.00 5 5 7 V2% Series X due 2007 50 50 1993 Auction -300,000 shares 100.00(c) 30 30 6 %%Series due 2008 148 148 6.625% Series due 2011 150 6.625% Series - 125,000 shares 100.00 12 12 7.61% 1997 Series due 2017 40 40 Without par value and stated 8 %%Series due 2021 125 125 value of $25 per share 8'4% Series due 2022 104 104

$1.735 Series - 1,657,500 shares 25.00 42 42 8% Series due 2022 85 85 Total Preferred Stock of Subsidiaries 7.15% Series due 2023 75 75 Not Subject to Mandatory Redemption $235 $235 7% Series due 2024 100 100 6.125% Series due 2028 60 60 (a) Beginning February 15, 2003, eventually declining to $100 per share. 5.45% Series due 2028 (b) 44 44 (b) In the event of voluntary liquidation,$105.50. Other 5.375% - 7.05% due 2002 through 2008 93 123 (c) Dividend rates, and the periods duringwhich such rates apply vary 1,562 1,442 depending on the Company'sselection of certain defined dividendperiod lengths. The average dividend rate during2007 was 3.63%. Environmental Improvement/

Pollution Control Revenue Bonds NOTE 6 - SHORT-TERM BORROWINGS 1991 Series due 2020 (c) 43 43 Short-term borrowings of the Company consist of bank 1992 Series due 2022 (c) 47 47 loans and commercial paper (maturities generally within 1-45 1993 Series A 6%% due 2028 35 35 days). At December 31, 2001 and 2000, $641 million and 1993 Series C-1 5.95% due 2026 (h) 35 35 1998 Series A due 2033 (c) 60 60

$203 million, respectively, of short-term borrowings were 1998 Series B due 2033 (c) 50 50 outstanding. The weighted average interest rates on short 1998 Series C due 2033 (c) 50 50 term borrowings outstanding at December 31, 2001 and 2000 Series A 5.5% due 2014 (h) 51 51 2000, were 1.9% and 6.7%, respectively. 2000 Series A due 2035 (c) 64 64 At December 31, 2001, the Company had committed bank 2000 Series B due 2035 (c) 63 63 lines of credit, aggregating $156 million, all of which were 2000 Series C due 2035 (c) 60 60 unused and available at such date. These lines make avail Other 5% - 5.90% due 2026 through 2028 60 60 able interim financing at various rates of interest based on 618 618 LIBOR, the bank certificate of deposit rate, or other options.

Subordinated Deferrable Interest Debentures The lines of credit are renewable annually at various dates 7.69% Series A due 2036 (d) 66 66 throughout the year.

Unsecured Loans The Company also has bank credit agreements totaling Commercial paper - 19

$700 million, expiring at various dates between 2002 1991 Senior medium term notes and 2003, that support the Company's commercial paper 8.60% due through 2005 27 33 programs. At December 31, 2001, all of the bank credit 1994 Senior medium term notes agreements were unused; however, due to commercial paper 6.61% due through 2005 31 39 borrowings and other commitments, $126 million of such 2000 Senior notes 7.61% due 2004 40 40 borrowing capacity was available. 2000 Senior notes series C The Company has money pool agreements with and 7 %%due 2005 (e) 225 225 among its subsidiaries to coordinate and provide for certain 2000 Senior notes series D short-term cash and working capital requirements. Separate 8.35% due 2010 (f) 200 200 2001 Floating rate notes money pools are maintained between regulated and nonregu due 2003 (g) 150 lated businesses. Interest is calculated at varying rates of 673 556 interest depending on the composition of internal and exter Nuclear Fuel Lease 63 114 nal funds in the money pools. This debt and the related inter Unamortized Discount and Premium on Debt (8) (7) est represent intercompany balances, which are eliminated Maturities Due Within One Year (139) (44) at the Ameren Corporation consolidated level. Total Long-Term Debt $2,835 $2,745 42 WWW. AMEREN.COM

(a) At December31, 2001, a majority of the propertyand plant was mortgaged unable to determine the amount of the additional financing, under,and subject to liens of; the respective indentures pursuantto which as well as the additional financing's impact on the Company's the bonds were issued. financial position, results of operations or liquidity.

(b) EnvironmentalImprovement Series (c) Interest rates,and the periods during which such rates apply, vary depending NOTE 8 - INCOME TAXES on the Company's selection of certain defined rate modes. The average interest ratesfor the year 2001 are as follows: Total income tax expense for 2001 resulted in an effective 1991 Series 3.15% tax rate of 39% on earnings before income taxes (39% in 1992 Series 3.11% 2000 and 1999).

1998 Series A 3.07% Principal reasons such rates differ from the statutory 1998 Series B 3.07% federal rate:

1998 Series C 3.04% 2001 2000 1999 2000 Series A 2.99%

2000 Series B 2.97% Statutory Federal Income Tax Rate: 35% 35% 35%

2000 Series C 3.03% Increases (decreases) from:

(d) Duringthe terms of the debentures, the Company may under certain Depreciation differences 2 2 1 circumstances,defer the payment of interest for up to five years. State tax 3 3 4 (e) Interestis payable semiannuallyin arrearson May I and November 1 Other (1) (1) (1) of each year; commencing May 1, 2001. Principalwill be payable on Effective Income Tax Rate 39% 39% 39%

November 1,2005.

(0) Interestis payable semiannuallyin arrearson May 1 and November 1 Income tax expense components:

of each year; commencing May 1,2001. Principalwill be payable on In Millions 2001 2000 1999 November 1,2010.

(g) Interestis payable quarterly commencing March 12, 2002. Principalis Taxes Currently Payable payable on December 12, 2003. The per annum interest rate on the notes (Principally Federal):

for each interestperiod will be a floating rate equal to three month LIBOR Included in operating expenses 3280 $307 $287 plus a spread of 0.95%. Included in other income (h) Variable rate tax-exempt pollution control indebtedness was converted Miscellaneous, net 6 (2) (3) to long-term fixed rates. 286 305 284 Maturities of long-term debt through 2006 are as follows:

Deferred Taxes (Principally Federal):

In Millions Principal Amount Included in operating expenses 2002 $139 Depreciation differences 9 (5) 3 2003 340 Other 19 7 (23) 2004 344 Included in other income Other - - (2) 2005 259 28 2 (22) 2006 20 In January 2002, Ameren Corporation issued 5.70% Notes Deferred Investment Tax Credits, totaling $100 million. Interest is payable semi-annually on Amortization:

February 1 and August 1 of each year, beginning August 1, Included in operating expenses (8) (8) (8) 2002, and on the date of maturity, February 1, 2007. Ameren Total Income Tax Expense $306 $299 $254 Corporation received net proceeds of $99.1 million after a discount to the public and deduction of underwriters' commis In accordance with SFAS 109, 'Accounting for Income sions. With the proceeds, Ameren Corporation reduced its Taxes," a regulatory asset, representing the probable recovery short-term borrowings. from customers of future income taxes, which is expected The Company anticipates securing additional financing to occur when temporary differences reverse, was recorded in 2002. In January 2002, Ameren Corporation filed a shelf along with a corresponding deferred tax liability. Also, a regu registration statement with the SEC on Form S-3 which, upon latory liability, recognizing the lower expected revenue result its effectiveness, will allow the offering from time to time of ing from reduced income taxes associated with amortizing various forms of debt and equity securities, up to an aggre accumulated deferred investment tax credits, was recorded.

gate offering price of $1 billion. The proceeds from any sale Investment tax credits have been deferred and will continue to of such securities may be used to finance the Company's be credited to income over the lives of the related property.

subsidiaries' ongoing construction and maintenance The Company adjusts its deferred tax liabilities for changes programs, to redeem, repurchase, repay or retire outstanding enacted in tax laws or rates. Recognizing that regulators indebtedness, including indebtedness of the Company's will probably reduce future revenues for deferred tax liabilities subsidiaries, to finance strategic investments in or future initially recorded at rates in excess of the current statutory acquisitions of other entities or other assets and for other rate, reductions in the deferred tax liability were credited to general corporate purposes. At this time, the Company is the regulatory liability.

AMEREN 2001 ANNUAL REPORT 43

Temporary differences gave rise to the following deferred Components of Ameren's tax assets and deferred tax liabilities at December 31: Net Periodic Pension Benefit Cost:

In Millions In Millions 20 01 2000 1999 2001 2000 Accumulated Deferred Income Taxes: Service cost $ 32 $ 30 $ 33 Depreciation $1,040 Interest cost 100 98 91

$1,043 Regulatory assets, net Expected return on plan assets (1 15) (110) (104) 434 417 Capitalized taxes and expenses Amortization of:

184 181 Deferred benefit costs Transition asset (1) (1) (1)

(68) (73)

Other Prior service cost 9 7 7 31 22 Actuarial gain 21) (21) (2)

Total Net Accumulated Deferred Net Periodic Benefit Cost $ 4 $ 3 $ 24 Income Tax Liabilities $1,621 $1,590 Weighted-average Assumptions for Actuarial NOTE 9 - RETIREMENT BENEFITS Present Value of Projected Benefit Obligations:

The Company has defined benefit retirement plans covering 2001 2000 substantially all employees of AmerenUE, AmerenCIPS, Discount rate at measurement date 7.25% 7.50%

and Ameren Services Company and certain employees of Expected return on plan assets 8.50% 8.50%

Resources Company and its subsidiaries. Benefits are based Increase in future compensation 4.25% 4.50%

on the employees' years of service and compensation. The Company's plans are funded in compliance with income tax On January 1, 2000, the AmerenUE and the AmerenCIPS regulations and federal funding requirements. postretirement benefit plans combined to form the Ameren Pension costs for 2001 and 2000 were $4 million and Plans. The Ameren Plans cover substantially all employees

$3 million, respectively, of which 16% and 21%, respectively, of AmerenUE, AmerenCIPS, and Ameren Services Company were charged to construction accounts. and certain employees of Resources Company and its subsidiaries. The AmerenUE and AmerenCIPS postretirement Funded Status of Ameren's Pension Plans:

In Millions plans' information for 1999 is presented separately. Following 2001 2000 is the postretirement plan information related to Ameren's Change in Benefit Obligation plans as of December 31.

Net benefit obligation at beginning of year $1,362 $1,257 Ameren's funding policy is to annually fund the Voluntary Service cost 32 30 Employee Beneficiary Association trusts (VEBA) with the Interest cost 100 98 Plan amendments lesser of the net periodic cost or the amount deductible for 28 Actuarial loss 14 38 federal income tax purposes. Postretirement benefit costs Benefits paid (90) (89) were $63 million and $58 million for 2001 and 2000, respec Net benefit obligation at end of year 1,418 1,362 tively, of which approximately 18% and 17%, respectively, were charged to construction accounts. Ameren's transition Change in Plan Assets*

obligation at December 31, 2001 is being amortized over the Fair value of plan assets at beginning of year 1,359 1,427 Actual return on plan assets next 12 years.

(45) 20 Employer contributions 1 The MoPSC and the ICC allow the recovery of postretire 1

Benefits paid (90) (89) ment benefit costs in rates to the extent that such costs Fair value of plan assets at end of year 1,225 1,359 are funded.

Funded status - deficiency 193 3 Funded Status of Ameren's Unrecognized net actuarial gain/(Ioss) (33) 160 Postretirement Benefit Plans:

Unrecognized prior service cost (77) (82) In Millions 2001 2000 Unrecognized net transition asset 5 6 Change in Benefit Obligation Accrued Pension Cost at December 31 $ 88 $ 87 Net benefit obligation at beginning of year $589 $492

• Planassets consistprincipally of common stocks and fixed income securities. Service cost 23 20 Interest cost 47 43 Plan amendments - (26)

Actuarial loss 80 94 Benefits paid (38) (34)

Net benefit obligation at end of year 701 589 Change in Plan Assets*

Fair value of plan assets at beginning of year 290 269 Actual return on plan assets (17) (4)

Employer contributions 65 59 Benefits paid (38) (34) 441 WWW.AMEREN.COM Fair value of plan assets at end of year 300 290

Funded Status of Ameren's Components of AmerenClPS' Postretirement Benefit Plans, continued: Net Periodic Postretirement Benefit Cost:

In Millions 2001 2000 In Millions 1999 Funded status - deficiency 401 299 Service cost $ 3 (134) (14) Interest cost 9 Unrecognized net actuarial loss Unrecognized prior service cost 2 2 Expected return on plan assets (9)

Unrecognized net transition obligation (180) (196) Amortization of:

$ 91 Transition obligation 6 Postretirement Benefit Liability at December31 $ 89 Actuarial gain (6)

• Plan assets consist principallyof common stocks, bonds, and money market instruments. Net Periodic Benefit Cost $3 Components of Ameren's Net Periodic Postretirement Benefit Cost: NOTE 10- STOCK-BASED COMPENSATION In Millions 2001 2000 The Company has a long-term incentive plan (the Plan) for

$ 23 $19 eligible employees, which provides for the grant of options, Service cost Interest cost 47 43 performance awards, restricted stock, dividend equivalents Expected return on plan assets (25) (18) and stock appreciation rights. The Company applies APB 25 Amortization of: in accounting for its stock-based compensation. The Company Transition obligation 16 16 has adopted the disclosure-only method of fair value data Actuarial (gain)/loss 2 (2) under SFAS 123, 'Accounting for Stock-Based Compensation."

Net Periodic Benefit Cost $ 63 $ 58 Under the Plan, 141,788 restricted shares of the Company's stock were granted at $39.60 in 2001. Upon the achievement Assumptions for the Obligation Measurements: of certain Company performance levels, the restricted stock 2001 2000 award vests over a period of seven years, beginning at the Discount rate at measurement date 7.25% 7.50% date of grant, and include provisions requiring certain stock Expected return on plan assets 8.50% 8.50% ownership levels. An accelerated vesting provision is also Medical cost trend rate 5.25% 5.00% included in the Plan, which reduces the vesting period from A 1% increase in the medical cost trend rate is estimated seven years to three years. The Company records unearned to increase the net periodic cost and the accumulated postre compensation (as a component of stockholders' equity) equal tirement benefit obligation approximately $7 million and $55 to the market value of the restricted stock on the date of grant million, respectively. A 1% decrease in the medical cost trend and charges the unearned compensation to expense over rate is estimated to decrease the net periodic cost and the the vesting period. In accordance with APB 25 and under SFAS 123, the Company's compensation expense relating accumulated postretirement benefit obligation approximately

$7 million and $51 million, respectively. to restricted stock awards totaled $903,000 in 2001.

AmerenUE's plans cover substantially all employees of Also under the terms of the Plan, options may be AmerenUE as well as certain employees of Ameren Services granted at a price not less than the fair market value Company. Postretirement benefit costs were $46 million of the common shares at the date of grant. Granted for 1999, of which approximately 18% was charged to options vest over a period of five years, beginning at the construction accounts. date of grant, and provide for acceleration of exercisabil ity of the options upon the occurrence of certain events, Components of AmerenUE's including retirement. Outstanding options expire on Net Periodic Postretirement Benefit Cost: various dates through 2010. Under the Plan, subject to In Millions 1999 adjustment as provided in the Plan, four million shares Service cost $15 have been authorized to be issued or delivered under Interest cost 25 the Company's Plan. In accordance with APB 25, no Expected return on plan assets (6) compensation expense has been recognized for the Amortization of transition obligation 12 Company's stock options. If the fair value method set Net Periodic Benefit Cost $46 forth under SFAS 123 had been used to account for AmerenCIPS' plans cover substantially all employees of options, the effects on net income and earnings would AmerenCIPS as well as certain employees of Ameren Services have been immaterial.

Company. Postretirement benefit costs were $3 million for 1999, of which approximately 10% was charged to construc tion accounts.

AMEREN 2001 ANNUAL REPORT 145

The following table summarizes stock option activity during NOTE 11 - COMMITMENTS 2001, 2000 and 1999: AND CONTINGENCIES 2001 The Company is engaged in a capital program under Weighted which expenditures of approximately $3.5 billion, including Average AFC and capitalized interest, are anticipated over the next Exercise five years. This estimate includes capital expenditures for Shares Price the purchase of new combustion turbine generating facilities Outstanding at beginning of year 2,430,532 $35.38 and for the replacement of four steam generators at its Granted Callaway Nuclear Plant. In addition, this estimate includes Exercised 106,416 38.31 capital expenditures for transmission, distribution and other Cancelled or expired 83,009 35.77 generation related activities, as well as for compliance with Outstanding at End of Year 2,241,107 $35.23 new NOx control regulations, as discussed later in this Note.

Commitments have been made with regard to certain of Exercisable at End of Year 572,092 $38.74 these capital expenditures.

The Company has committed to purchase combustion 2000 1999 turbine generator equipment, which will add nearly 1,400 Weig hted Weighted megawatts to its net peaking capacity and are expected to Averrage Average cost approximately $630 million. The Company plans to add Exer cise Exercise 710 megawatts (approximately 470 megawatts at Resources Shares P'rice Shares Price Company and 240 megawatts at AmerenUE) of combustion Outstanding at turbine generating capacity during 2002. Total costs beginning of year 1,834,108 $38.22 1,095,180 $39.41 expected to be incurred for these combustion turbine gener Granted 957,100 31.00 768,100 36.63 ating units approximate $340 million. Due to expected Exercised 295,693 38.41 11,162 37.20 Cancelled or expired increased demand, and the need to maintain appropriate 64,983 37.38 18,010 42.45 Outstanding at reserve margins, the Company believes it will need addi End of Year 2,430,532 $35.38 1,834,108 $38.22 tional regulated generating capacity in the future. In 2002, Exercisable at AmerenUE expects to purchase up to 500 megawatts of End of Year 312,736 $39.58 391,456 $39.06 capacity for the summer. Additional future resource options under consideration by the Company include the transfer Additional information about stock options outstanding at of AmerenUE's Illinois-based electric and gas business to December 31, 2001: AmerenCIPS. Other alternatives include the addition of 650 megawatts of combustion turbine generating units. These Weighted Average Exercise Price Outstanding Shares units are estimated to cost $280 million and would be Life (Years) Exercisable Shares added subsequent to 2004. As of December 31, 2001, the

$31.00 908,500 8.1 8,000 Company had noncancelable reservation commitments of 35.50 800 3.6 800 $22 million related to the potential purchase of these units.

35.875 35,880 3.3 35,880 The Company continually reviews its generation portfolio and 36.625 633,050 7.0 148,550 expected electrical needs, and as a result, could modify its 38.50 102,985 5.1 71,170 plan for generation asset purchases, which could include the 39.25 464,616 6.2 215,066 timing of when certain assets will be added to, or removed 39.8125 5,300 6.5 2,650 from its portfolio, whether the generation will be added to 43.00 89,976 3.8 89,976 the regulated or nonregulated portfolio, the type of genera The fair values of stock options were estimated using a bino tion asset technology that will be employed, or whether mial option-pricing model with the following assumptions: capacity may be purchased, among other things. Changes to the Company's plans for future generating needs could result in losses being incurred by the Company, which could Grant Risk-free Option Expected Expected Date Interest Rate be material.

Term Volatility Dividend Yield 2/11/00 6.81% 10 years 17.39% 6.61%

2/12/99 5.44% 10 years 18.80% 6.51%

6/16/98 5.63% 10 years 17.68% 6.55%

4/28/98 6.01% 10 years 17.63% 6.55%

2/10/97 5.70% 10 years 13.17% 6.53%

2/7/96 5.87% 10 years 13.67% 6.32%

461 WWW. AMEREN.COM

The Company has commitments for the purchase of coal (d) Includes premature decommissioning costs.

(e) Weekly indemnity of $3.5 million, for 52 weeks which commences under long-term contracts. Coal contract commitments, after the first 12 weeks of an outage, plus $2.8 million per week for including transportation costs, for 2002 through 2006 are 110 weeks thereafter.

estimated to total $2.0 billion. Total coal purchases, including Price-Anderson limits the liability for claims from an inci transportation costs, for 2001, 2000 and 1999 were $562 dent involving any licensed U.S. nuclear facility. The limit is million, $507 million, and $603 million, respectively. The based on the number of licensed reactors and is adjusted at Company also has existing contracts with pipeline and natural least every five years based on the Consumer Price Index.

gas suppliers to provide, transport and store natural gas for Utilities owning a nuclear reactor cover this exposure through distribution and electric generation. Gas-related contract cost a combination of private insurance and mandatory participa commitments for 2002 through 2006 are estimated to total tion in a financial protection pool, as established by Price

$253 million. Total delivered natural gas costs were $222 Anderson.

million for 2001, $209 million for 2000, and $131 million for If losses from a nuclear incident at Callaway exceed the 1999. The Company's nuclear fuel commitments for 2002 limits of, or are not subject to, insurance, or if coverage is through 2006, including uranium concentrates, conversion, not available, the Company will self-insure the risk. Although enrichment and fabrication, are expected to total $76 million, the Company has no reason to anticipate a serious nuclear and are expected to be substantially financed under the incident, if one did occur, it could have a material, but indeter nuclear fuel lease. Nuclear fuel expenditures were $24 million minable, adverse effect on the Company's financial position, for 2001, and $22 million in each of the years 2000 and 1999.

results of operations or liquidity.

Additionally, the Company has long-term contracts with other The State of Illinois has developed a NOx control regula utilities to purchase electric capacity. These commitments tion for utility boilers in the State consistent with a United for 2002 through 2006 are estimated to total $301 million.

States Environmental Protection Agency (EPA) program During 2001, 2000 and 1999, electric capacity purchases aimed at reducing ozone levels in the Eastern United States.

were $31 million, $40 million, and $44 million, respectively.

As a result of these state requirements, Generating Company In 1999, AmerenCIPS and two of its coal suppliers executed anticipates a 75% reduction from current levels of NOx emis agreements to terminate their existing coal supply contracts, sions from its power plant boilers in Illinois by the year 2004.

effective December 31, 1999. Under these agreements, Generating Company estimates spending approximately AmerenCIPS has made termination payments to the suppliers

$210 million for capital expenditures to comply with these totaling approximately $52 million. These termination rules, of which approximately $50 million was spent in 2001.

payments were recorded as an unusual charge in the fourth On February 13, 2002, the EPA proposed similar rules for quarter of 1999, equivalent to $31 million, after income taxes, Missouri which require an approximate 64% reduction from or 23 cents per share.

current levels of NOx emissions. AmerenUE estimates The Company's insurance coverage for Callaway Nuclear approximately $140 million will be required to be spent to Plant at December 31, 2001, was as follows:

comply with these rules for NOx control on the AmerenUE Type and Source of Coverage generating system by 2005. The Company is still evaluat Maximum ing the impact of the EPAs regulations as applied to its Assessments Missouri operations and may challenge certain aspects Maximum for Single Coverages Incidents of those rules. In summary, the Company currently esti In Millions mates that its capital expenditures to comply with the final Public liability: NOx regulations could range from $300 million to $350 American Nuclear Insurers $ 200 $ million. This estimate includes the assumption that Pool Participation 9,338 88(a) the regulations will require the installation of Selective

$ 9,538 (b) $88 Catalytic Reduction (SCR) technology on some of the Nuclear worker liability: Company's units, as well as additional controls.

American Nuclear Insurers $ 200 (c) $ 3 Under both Illinois and Missouri regulatory programs, Property damage: Generating Company and AmerenUE have applied for Early Nuclear Electric Insurance Ltd. $ 2,750 (d) $23 Reduction NOx credits which would allow the companies Replacement power: to manage compliance strategies by either purchasing NOx Nuclear Electric Insurance Ltd. $ 490 (e) $ 5 control equipment or utilizing credits. Generating Company (a) Retrospective premium underthe Price-Andersonliability provisions of the and AmerenUE may be eligible for such credits due to the Atomic Energy Act of 1954, as amended (Price-Anderson). Subject to retro current low NOx emission rates of some of the companies' spective assessment with respect to loss from an incidentat any U.S. reactor boilers under current state regulations.

payable at $10 million per year Price-Anderson expires in 2002.

(b) Limit of liability for each incidentunder Price-Anderson.

In July 1997, the EPA issued regulations revising the (c) Industry limit for potential liabilityfrom workers claiming exposure to National Ambient Air Quality Standards for ozone and the hazard of nuclearradiation.

AMEREN 2001 ANNUAL REPORT 147

particulate matter. The standards were challenged by industry and properly incurred and are subject to annual reconciliation and some states, and arguments were eventually heard by review by the ICC. Through December 31, 2001, the total the U.S. Supreme Court. On February 27, 2001, the Supreme costs deferred, net of recoveries from insurers and through Court upheld the standards in large part, but remanded a environmental adjustment clause rate riders, was $26 million.

number of significant implementation issues back to the EPA In addition, the Company owns or is otherwise responsible for resolution. The EPA is currently working on a new rulemak for 10 MGP sites in Missouri and one in Iowa. Unlike Illinois, ing to address the issues raised by the Supreme Court. New the Company does not have in effect in Missouri a rate rider ambient standards may require significant additional reductions mechanism which permits remediation costs associated with in SO 2 and NO, emissions from the Company's power plants MGP sites to be recovered from utility customers, and the by 2008. At this time, the Company is unable to predict the Company has no retail utility operations in Iowa.

ultimate impact of these revised air quality standards on its In June 2000, the EPA notified AmerenUE and numerous future financial condition, results of operations or liquidity. other companies that former landfills and lagoons in Sauget, In December 1999, the EPA issued a decision to regulate Illinois, may contain soil and groundwater contamination.

mercury emissions from coal-fired power plants by 2008. These sites are known as Sauget Area 1 and Sauget Area 2.

The EPA is scheduled to propose regulations by 2004. These From approximately 1926 until 1976, AmerenUE operated regulations have the potential to add significant capital and/or a power generating facility adjacent to Sauget Area 2 and operating costs to the Ameren generating systems after 2005. currently owns and operates electric transmission and distri On July 20, 2001, the EPA issued proposed Best Available bution facilities in or near Sauget Area 1.

Retrofit Technology (BART) guidelines to address visibility In September 2000, the United States Department of impairment (so called "Regional Haze") across the United Justice was granted leave by the United States District Court States from sources of air pollution, including coal-fired power Southern District of Illinois to add numerous additional parties, plants. The guidelines are to be used by States to mandate including AmerenUE, to a preexisting lawsuit between the pollution control measures for SO 2 and NOx emissions. These government and others. The government seeks recovery rules could also add significant pollution control costs to the of response costs under the Comprehensive Environmental Ameren generating systems between 2008 and 2012. Response Compensation Liability Act of 1980 (commonly In addition, the United States Congress has been working known as CERCLA or Superfund), incurred in connection on legislation to consolidate the numerous air pollution regula with the remediation of Sauget Area 1. The Company tions facing the utility industry. This "multi-pollutant" legisla believes that the final resolution of this lawsuit and the reme tion is expected to be deliberated in Congress in 2002. While diation of Sauget Area 1 will not have a material adverse the cost to comply with such legislation, if enacted, could be effect on its financial position, results of operations or liquidity.

significant, it is anticipated that the costs would be less than With respect to Sauget Area 2, AmerenUE has joined with the combined impact of the new National Ambient Air Quality other PRPs to evaluate the extent of potential contamination.

Standards, mercury and Regional Haze regulations, discussed At this time, the Company is unable to predict the ultimate above. Pollution control costs under such legislation are impact of the Sauget Area 2 site on its financial position, expected to be incurred in phases from 2007 through 2015. results of operations or liquidity.

At this time, the Company is unable to predict the ultimate On September 13, 2001, the EPA proposed in the Federal impact of the above expected regulations and this legislation Register that Sauget Area 1 and Sauget Area 2 be listed on on its future financial condition, results of operations, or liquid the National Priorities List (NPL). The inclusion of a site on ity; however, the impact could be material. the NPL allows the EPA to access Superfund trust monies The Company is involved in a number of remediation to fund site remediations.

actions to clean up hazardous waste sites as required by In addition, the Company's operations, or that of its prede federal and state law. Such statutes require that responsible cessor companies, involve the use, disposal and, in appropri parties fund remediation actions regardless of fault, legality of ate circumstances, the cleanup of substances regulated under original disposal, or ownership of a disposal site. AmerenUE environmental protection laws. The Company is unable and AmerenCIPS have been identified by the federal or state to determine the impact these actions may have on the governments as a potentially responsible party (PRP) at Company's financial position, results of operations or liquidity.

several contaminated sites. Certain employees of the Company are represented by The Company owns or is otherwise responsible for 14 the International Brotherhood of Electrical Workers and the former manufactured gas plant (MGP) sites in Illinois. The International Union of Operating Engineers. These employees ICC permits the recovery of remediation and litigation costs comprise approximately 66% of the Company's workforce.

associated with certain former MGP sites located in Illinois Contracts with collective bargaining units representing approx from the Company's Illinois electric and natural gas utility imately 30% of these employees will expire in 2002. In addi customers through environmental adjustment clause rate tion, contracts with collective bargaining units representing riders. To be recoverable, such costs must be prudently approximately 70% of these employees will expire in 2003.

481 WWW.AMEREN.COM

Regulatory changes enacted and being considered at the as increases in the nuclear decommissioning trust fund and federal and state levels continue to change the structure of in the accumulated provision for nuclear decommissioning.

the utility industry and utility regulation, as well as encourage The staff of the SEC has questioned certain accounting increased competition. At this time, the Company is unable practices of the electric utility industry, regarding the recogni to predict the impact of these changes on the Company's tion, measurement, and classification of decommissioning future financial condition, results of operations or liquidity. costs for nuclear generating stations in the financial state See Note 2 - Regulatory Matters for further information. ments of electric utilities. In response to these questions, The Company is involved in other legal and administrative the FASB issued SFAS No. 143, 'Accounting for Asset proceedings before various courts and agencies with respect Retirement Obligations" (see Note 1 - Summary of Significant to matters arising in the ordinary course of business, some Accounting Policies).

of which involve substantial amounts. The Company believes NOTE 13 - FAIR VALUE OF FINANCIAL that the final disposition of these proceedings will not have INSTRUMENTS a material adverse effect on its financial position, results of The following methods and assumptions were used to operations or liquidity.

estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

NOTE 12 - CALLAWAY NUCLEAR PLANT Cash and Temporary Under the Nuclear Waste Policy Act of 1982, the Investments/Short-Term Borrowings Department of Energy (DOE) is responsible for the permanent The carrying amounts approximate fair value because storage and disposal of spent nuclear fuel. The DOE currently of the short-term maturity of these instruments.

charges one mill per nuclear-generated kilowatthour sold for future disposal of spent fuel. Electric utility rates charged to Marketable Securities customers provide for recovery of such costs. The DOE is The fair value is based on quoted market prices obtained not expected to have its permanent storage facility for spent from dealers or investment managers.

fuel available until at least 2015. The Company has sufficient Nuclear Decommissioning Trust Fund storage capacity at the Callaway Nuclear Plant site until 2020 The fair value is estimated based on quoted market prices and has the capability for additional storage capacity through for securities.

the licensed life of the plant. The delayed availability of the Preferred Stock of Subsidiaries DOE's disposal facility is not expected to adversely affect the The fair value is estimated based on the quoted market continued operation of the Callaway Nuclear Plant.

prices for the same or similar issues.

Electric utility rates charged to customers provide for recovery of Callaway Nuclear Plant decommissioning costs Long-Term Debt over the life of the plant, based on an assumed 40-year life, The fair value is estimated based on the quoted market ending with expiration of the plant's operating license in prices for same or similar issues or on the current rates 2024. The Callaway site is assumed to be decommissioned offered to the Company for debt of comparable maturities.

using the DECON (immediate dismantlement) method. Derivative Financial Instruments Decommissioning costs, including decontamination, disman Market prices used to determine fair value are based tling and site restoration, are estimated to be $585 million on management's estimates, which take into consideration in current year dollars and are expected to escalate approxi factors like closing exchange prices, over-the-counter prices, mately 4% per year through the end of decommissioning and time value of money and volatility factors.

activity in 2033. Decommissioning costs are charged Carrying amounts and estimated fair values of the to depreciation expense over Callaway's service life and Company's financial instruments at December 31:

amounted to approximately $7 million in each of the years 2001 2000 2001, 2000 and 1999. Every three years, the MoPSC and ICC Carrying Fair Carrying Fair require the Company to file updated cost studies for decom In Millions Amount Value Amount Value missioning Callaway, and electric rates may be adjusted at Long-term debt such times to reflect changed estimates. The latest studies (including current portion) $2,974 $3,052 $2,789 $2,841 were filed in 1999. Costs collected from customers are Preferred stock 235 207 235 186 deposited in an external trust fund to provide for Callaway's decommissioning. Fund earnings are expected to average The Company has investments in debt and equity securities approximately 9% annually through the date of decommis that are held in trust funds for the purpose of funding the sioning. If the assumed return on trust assets is not earned, nuclear decommissioning of its Callaway Nuclear Plant (see the Company believes it is probable that any such earnings Note 12 - Callaway Nuclear Plant). The Company has classi deficiency will be recovered in rates. Trust fund earnings, fied these investments in debt and equity securities as avail net of expenses, appear on the consolidated balance sheet able for sale and has recorded all such investments at their AMEREN 2001 ANNUAL REPORT149

fair market value at December 31, 2001 and 2000. In 2001, The table below presents information about the reported 2000 and 1999, the proceeds from the sale of investments revenues, net income, and total assets of Ameren for the were $230 million, $61 million, and $83 million, respectively. years ended December 31:

Using the specific identification method to determine cost, Utility Reconciling the gross realized gains on those sales were approximately 2001 In Millions Operations Other Items Total

$4 million for 2001, $1 million for 2000, and $11 million Revenues $5,063 $248 $(805)* $4,506 for 1999. Net realized and unrealized gains and losses are Net income 467 2 - 469 reflected in the accumulated provision for nuclear decommis Total assets 11,171 240 (1,010) 10,401 sioning on the consolidated balance sheet, which is consistent with the method used by the Company to account for the 2000 In Millions decommissioning costs recovered in rates. Revenues $4,120 $294 $ (557)* $3,857 Costs and fair values of investments in debt and equity Net income 457 - - 457 securities in the nuclear decommissioning trust fund at Total assets 10,777 287 (1,350) 9,714 December 31 were as follows:

1999 In Millions 2001 In Millions Gross Unrealized Revenues $3,467 $243 $ (174)* $3,536 Security Type Cost Gain (Loss) Fair Value Net income 384 1 385 Debt securities $ 57 $ 2 $ - $ 59 Total assets 8,825 435 (82) 9,178 Equity securities 78 44 - 122

• Elimination of intercompanyrevenues.

Cash equivalents 6 - - 6

$141 $46 $ - $187 Specified items included in segment profit/loss for the years ended December 31:

2000 In Millions Gross Unrealized Utility Reconciling Security Type Cost Gain (Loss) Fair Value 2001 In Millions Operations Other Items Total Debt securities $ 71 $ 3 $ - $ 74 Interest expense $ 231 $ 11 $ (43)* $ 199 Equity securities 52 61 - 113 Depreciation and Cash equivalents 4 - - 4 amortization expense 382 12 12 406

$127 $64 $ - $191 Income tax expense 289 7 4 300 The contractual maturities of investments in debt 2000 In Millions securities at December 31, 2001 were as follows: Interest expense $ 205 $ 12 $ (37)* $ 180 Depreciation and In Millions Cost Fair Value amortization expense 360 13 10 383 Less than 5 years $20 $ 21 Income tax expense 297 4 - 301 5 years to 10 years 22 23 Due after 10 years 15 15 1999 In Millions

$57 $ 59 Interest expense $ 163 $ 9 $ (4)* $ 168 Depreciation and NOTE 14- SEGMENT INFORMA1TION amortization expense 349 12 2 363 Ameren's principal business segment is comprised of the Income tax expense 261 (2) - 259 utility operating companies that provide electric and gas

• Elimination of intercompanyinterest charges.

service in portions of Missouri and Illinois. The other reportable segment includes the nonutility subsidiaries, as Specified items related to segment assets as of well as the Company's 60% interest in Electric Energy, Inc. December 31:

The accounting policies of the segments are the same Utility Reconciling as those described in Note 1 - Summary of Significant 2001 In Millions Operations Other Items Total Accounting Policies. Segment data includes intersegment Expenditures for additions revenues, as well as a charge allocating costs of administra to long-lived assets $1,059 $ 10 $ 34 $1,103 tive support services to each of the operating companies.

These costs are accumulated in a separate subsidiary, Ameren 2000 In Millions Services Company, which provides a variety of support serv Expenditures for additions ices to Ameren and its subsidiaries. The Company evaluates to long-lived assets $ 872 $ 45 $ 12 $ 929 the performance of its segments and allocates resources to them, based on revenues, operating income and net income. 1999 In Millions Expenditures for additions 50sWWW.AMEREN.COM to long-lived assets $ 342 $179 $ 50 $ 571

SSELECTED CONSOLIDATED FINANCIAL INFORMATION Millions of Dollars, Except Share and Per Share Amounts and Ratios 2001 2000 1999 1998 1997 1996 Results of Operations Year Ended December 31, Operating revenues $4,506 $3,857 $3,536 $3,318 $3,327 $3,328 Operating expenses 3,841 3,217 2,973 2,747 2,744 2,752 Operating income 665 640 563 571 582 576 Income before extraordinary charge and cumulative effect of change in accounting principle 476 457 385 386 387 372 Extraordinary charge and cumulative effect of change in accounting principle, net of income taxes 7 52 Net income 469 457 385 386 335 372 Average common shares outstanding 137,320,692 137,215,462 137,215,462 137,215,462 137,215,462 137,215,462 Assets, Obligations and Equity Capital December 31, Total assets $10,401 $9,714 $9,178 $8,847 $8,828 $8,933 Long-term debt obligations 2,835 2,745 2,448 2,289 2,506 2,335 Preferred stock subject to mandatory redemption S..-.. 1 Preferred stock of subsidiaries not subject to mandatory redemption 235 235 235 235 235 298 Common equity 3,349 3,197 3,090 3,056 3,019 3,016 Financial Indices Year Ended December 31, Earnings per share of common stock before extraordinary charge $3.41 $3.33 $2.81 $2.82 $2.82 $2.71 Extraordinary charge, net of income taxes - $(.38)

Earnings per share of common stock (based on average shares outstanding) $3.41 $3.33 $2.81 $2.82 $2.44 $2.71 Dividend payout ratio 74' %o 76% 90% 90% 99% 88%

Return on average common stock equity 14.54' %0 14.60% 12.56% 12.82% 11.14% 12.51%

Ratio earnings to fixed charges AmerenUE 6.04 5.33 5.64 4.99 4.70 4.68 AmerenCIPS 2.87 4.05 2.98 4.13 3.64 4.30 Book value per common share $24.26 $23.30 $22.52 $22.27 $22.00 $21.98 Capitalization Ratios December 31, Common equity 52.1% 51.8% 53.5% 54.8% 52.4% 53.4%

Preferred stock 3.7 3.8 4.1 4.2 4.1 5.3 Long-term debt 44.2 44.4 42.4 41.0 43.5 41.3 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

AMEREN 2001 ANNUAL REPORT I S1

SELECTRIC OPERATING STATISTICS Year Ended December 31, 2001 2000 1999 1998 1997 1996 Electric Operating Revenues Millions Residential $1,133 $1,142 $1,097 $1,125 $1,064 $1,070 Commercial 1,020 997 956 966 927 920 Industrial 542 505 505 511 500 500 Wholesale 236 208 108 91 91 91 Other 22 24 24 23 24 28 Native 2,953 2,876 2,690 2,716 2,606 2,609 Interchange 957 477 399 240 224 280 EEl 110 164 177 152 207 198 Miscellaneous 125 75 72 29 47 22 Credit to customers 10 (65) (38) (43) (20) (47)

Total Electric Operating Revenues $4,155 $3,527 $3,300 $3,094 $3,064 $3,062 Kilowatthour Sales Millions Residential 15,678 15,683 14,863 15,188 14,325 14,418 Commercial 16,873 16,644 15,418 15,555 14,990 14,872 Industrial 13,175 11,914 11,549 11,582 11,404 11,191 Wholesale 6,992 6,244 3,002 2,446 2,323 2,328 Other 284 307 303 303 317 305 Native 53,002 50,792 45,135 45,074 43,359 43,114 Interchange 27,079 14,679 12,371 8,075 9,402 10,768 EEl 5,824 6,914 9,270 8,296 11,220 10,554 Total Kilowatthour Sales 85,905 72,385 66,776 61,445 63,981 64,436 Electric Customers End of Year Residential 1,311,275 1,307,237 1,298,008 1,289,548 1,282,042 1,275,534 Commercial 192,390 190,399 186,598 179,773 178,301 174,716 Industrial 5,926 5,957 6,188 5,926 6,554 6,660 Wholesale 30 22 20 20 21 20 Miscellaneous 3,909 4,295 4,293 4,098 4,286 4,303 Total Electric Customers 1,513,530 1,507,910 1,495,107 1,479,365 1,471,204 1,461,233 Residential Customer Data Average Kilowatthours used 11,956 12,579 11,827 11,986 11,215 11,354 Annual electric bill $869.25 $895.20 $859.53 $873.28 $833.34 $842.82 Revenue per kilowatthour 7.270 7.120 7.27¢ 7.290 7.38¢ 7.30¢ Gross Instantaneous Peak Demand Megawatts AmerenUE 8,651 8,706 8,831 8,429 8,055 8,085 AmerenEnergy Resources/AmerenCIPS 2,854 2,829 2,217 2,163 1,923 1,892 Capability at Time of Peak, Including Net Purchases and Sales Megawatts AmerenUE 9,747 9,359 9,141 9,027 8,950 9,120 AmerenEnergy Resources/AmerenCiPS 3,549 3,560 2,556 2,417 2,491 2,519 Generating Capability at Time of Peak Megawatts AmerenUE 8,618 8,320 8,352 8,282 8,279 8,244 AmerenEnergy Resources/AmerenCIPS 3,945 3,443 3,027 3,040 3,033 3,033 Coal Burned Millions of Tons 24.5 25.3 23.6 23.0 21.4 20.1 Price per Ton of Coal Average $18.88 $18.94 $20.34 $21.29 $23.54 $25.25 Source of Energy Supply Fossil 79.0% 83.2% 85.4% 83.5% 83.8% 79.6%

Nuclear 15.1 18.8 17.9 17.7 19.3 19.2 Hydro 1.8 1.6 3.1 3.8 2.7 2.8 Purchased and interchanged, net 4.1 (3.6) (6.4) (5.0) (5.8) (1.6) 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

52 WWW.RMEREN.COM

SGAS OPERATING STATISTICS Year Ended December 31, 2001 2000 1999 1998 1997 1996 Natural Gas Operating Revenues Millions Residential $187 $204 $146 $135 $150 $161 Commercial 83 69 52 50 55 61 Industrial 40 17 18 19 22 21 Off system sales 6 18 4 3 13 Miscellaneous 26 16 8 10 10 11 Total Natural Gas Operating Revenues $342 $324 $228 $217 $250 $254 MMBtu Sales Millions Residential 19 25 21 21 23 27 Commercial 9 9 8 8 9 11 Industrial 7 3 4 6 6 5 Off system sales 1 4 1 1 5 Total MMBtu Sales 36 41 34 36 43 43 Natural Gas Customers End of Year Residential 269,448 269,477 267,086 265,405 263,588 260,989 Commercial 29,723 30,964 29,247 30,245 30,147 29,911 Industrial 380 386 436 407 412 402 Total Natural Gas Customers 299,551 300,827 296,769 296,057 294,147 291,302 Peak Day Throughput Thousands of MMBtus AmerenCIPS 188 226 247 229 281 302 AmerenUE 128 169 184 157 181 189 Total Peak Day Throughput 316 395 431 386 462 491 S SELECTED QUARTERLY INFORMATION (Unaudited)

Thousands of Dollars, Except Per Share Amounts Quarter Ended: Operating Operating Net Earnings Per Revenues Income Income Common Share March 31, 2001 (a) $1,024,528 $116,086 $ 58,492 $ .43 March 31, 2000 (a) 825,376 108,578 61,393 .45 June 30, 2001(b) 1,057,016 145,203 94,630 .69 June 30, 2000 (b) 940,708 159,206 113,585 .83 September 30, 2001 1,431,613 310,422 266,576 1.94 September 30, 2000 (c) 1,195,723 305,685 256,137 1.87 December 31, 2001 992,710 93,276 48,847 .35 December 31, 2000 (d) 895,023 66,841 25,979 .19 (a) The first quarter of 2001 and 2000 included credits to Missourielectric customers that reduced net income approximately$9 million, or 6 cents per share and $6 million, or 4 cents per share,respectively. The first quarterof 2001 also included an unusual charge for the adoption of a new accountingstandard related to derivatives that reduced net income $7 million, or 5 cents per share.

(b) The second quarter of 2001 included a reduction to previously recorded credits to Missouri electric customers that increasednet income approximately

$15 million, or 10 cents per share. The second quarterof 2000 included credits to Missouri electric customers that reduced net income approximately

$3 million, or 2 cents per share.

(c) The third quarter of 2000 included credits to Missouri electric customers that reduced net income approximately $11 million, or 8 cents per share.

(d) The fourth quarterof 2000 included credits to Missouri electric customers that reduced net income approximately $17 million, or 12 cents per share.

The fourth quarterof 2000 also included an unusual charge related to the withdrawal from the Midwest ISO that reduced net income $15 million, or 11 cents per share. (See Note 2 - Regulatory Matters under Notes to ConsolidatedFinancialStatements for further information).

Other changes on quarterlyearnings are due to the effect of weather on sales and other factors that are characteristicof public utility operations.

AMEREN 2001 ANNUAL REPORT 53

• AMEREN CORPORATION DIRECTORS AND OFFICERS AND PRINCIPAL OFFICERS OF KEY SUBSIDIARIES OFFICERS* Jimmy L. Davis BOARD OF DIRECTORS Ameren Corporation Vice President, Energy Delivery William E. Cornelius' Charles W Mueller Gas Operations Support Retired Chairman and Chief Executive Chairman and Chief Executive Officer RichardJ. Mark Officer - Union Electric Company Gary L. Rainwater Vice President, Energy Delivery Clifford L. Greenwalt' President and Chief Operating Officer Customer Service Retired President and Chief Executive Warner L. Baxter MichaelJ. Montana Officer - CIPSCO Incorporated Senior Vice President, Finance Vice President, Supply Services Thomas A. Hays' Jerre E Birdsong Craig D. Nelson Retired Deputy Chairman Vice President and Treasurer Vice President, Corporate Planning The May Department Stores Company Baxter A. Gillette GregoryL. Nelson Thomas H. Jacobsen 2 Vice President, Risk Management Vice President and Tax Counsel Former Chairman - Firstar Corporation, J. Kay Smith a bank holding company Steven R. Sullivan Vice President, Vice President, Corporate RichardA. Liddy2 General Counsel and Secretary Communications and Public Policy Chairman, GenAmerica Financial Martin J. Lyons, Jr Samuel E. Willis Corporation, a provider of insurance Vice President, Industrial Relations products and services Controller Ronald C. Zdellar Gordon R. Lohman' AmerenUE Retired Chairman, Vice President, Energy Delivery Garry L. Randolph President and Chief Executive Officer Distribution Services Senior Vice President, Generation, AMSTED Industries Incorporated and Chief Nuclear Officer AmerenEnergy RichardA. Lumpkin 2 Ronald D. Affolter ClarenceJ. Hopf Jr. Chairman, President and Vice President, Nuclear Senior Vice President Chief Executive Officer- Illinois William J Carr James K. Johnson Consolidated Telephone Company, a Vice President, Energy Delivery Vice President, Energy Trading diversified telecommunications company Regional Elizabeth E. Lahm John PetersMacCarthy I Charles D. Naslund Vice President, Information Technology Retired Chairman and Chief Executive Vice President, Power Operations Officer - Boatmen's Trust Company Brian Rettenmaier William C Shores Controller Hanne M. Merriman Vice President, Energy Delivery Principal Metropolitan AmerenEnergy Resources Hanne Merriman Associates, DanielF Cole a retail business consulting firm AmerenCIPS President Paul L. Miller Jr.2 Gary L. Rainwater President and R. Alan Kelley President and Chief Executive Officer Senior Vice President, P L. Miller and Associates, Chief Executive Officer AmerenEnergy Generating a management consulting firm Gilbert W Moorman Michael G. Mueller Charles W Mueller '

Vice President, Energy Delivery Regional Operations Vice President, Chairman of the Board AmerenEnergy Fuels and Services and Chief Executive Officer Ameren Services Robert L. Powers Ameren Corporation PaulA. Agathen Vice President, AmerenEnergy HarveySaligman 2 Senior Vice President Generating Retired Managing Partner Thomas R. Voss Andrew M. Serri Cynwyd Investments Senior Vice President, Vice President, Janet McAfee Weakley' Energy Delivery AmerenEnergy Marketing Chairman -Janet McAfee, Inc.,

David A. Whiteley Jerry L. Simpson a residential real estate company Senior Vice President Vice President, AmerenEnergy James W Wogsland2 CharlesA. Bremer Generating Retired Vice Chairman - Caterpillar, Inc.

Vice President,

• Certain of these officers hold similarpositions IMember of Executive Committee Information Technology in multiple subsidiariesof Ameren Corporation. 2 Member of Auditing Committee

P INVESTOR INFORMATION COMMON STOCK AND If you have not yet exchanged your Union Electric DIVIDEND INFORMATION Company or CIPSCO Incorporated common stock Ameren's common stock is listed on the New York certificates for Ameren stock certificates, please contact Stock Exchange (ticker symbol: AEE). AEE began Investor Services. This is not an offer to sell, or a trading on January 2, 1998, following the merger of solicitation of an offer to buy, any securities.

Union Electric Company and CIPSCO Incorporated on December 31, 1997. DIRECT DEPOSIT OF DIVIDENDS Common stockholders of record totaled 101,455 for All registered Ameren common and Union Electric Ameren on December 31, 2001. The following includes Company and Central Illinois Public Service Company the price ranges and dividends paid per common share preferred stockholders can have their cash dividends for AEE during 2001 and 2000. automatically credited to their bank accounts. This service gives stockholders immediate access to their dividend on AEE 2001 the dividend payment date and eliminates the possibility Quarter Ended High Low Close Dividends Paid of lost or stolen dividend checks.

March 31 $46.0000 $37.3125 $40.9500 63 Y2 June 30 45.4800 40.2000 42.7000 631/2 RMEREN'S WEB SITE September 30 43.4500 36.5300 38.4000 63 '/

631/2 To obtain AEE's daily stock price, recent December 31 42.9000 37.8000 42.3000 financial statistics and other information about AEE 2000 the company, visit Ameren's home page on Quarter Ended High Low Close Dividends Paid the Internet. Ameren's web site address is:

March 31 $34.2500 $27.5625 $30.9375 631/2 http://www.ameren.com June 30 38.0000 30.6250 33.7500 63Y2 September 30 43.6875 34.0625 41.8750 631/2 INVESTOR SERVICES December 31 46.9375 37.3750 46.3125 631/2 The company's Investor Services representatives are available to help you each business day from ANNUAL MEETING 7:30 a.m. to 4:30 p.m. (Central Time).

The annual meetings of Ameren, Union Electric Please write or call:

Company and Central Illinois Public Service Company stockholders will convene at 9 a.m., Tuesday, April 23, 2002 Ameren Services Company at Powell Symphony Hall, 718 North Grand Boulevard, Investor Services St. Louis, Missouri. PO. Box 66887 St. Louis, MO 63166-6887 DRPLUS St. Louis area 314-554-3502 Through DRPlus - Ameren's dividend reinvestment and Toll-free 1-800-255-2237 stock purchase plan - any person of legal age or entity, whether or not an Ameren stockholder, is eligible to partici TRANSFER AGENT, REGISTRAR pate in DRPlus. Participants can: AND PAYING AGENT The Transfer Agent, Registrar and Paying Agent for

"* make cash investments by check or automatic direct Ameren Corporation common stock and Union Electric debit to their bank accounts to purchase Ameren Company and Central Illinois Public Service Company common stock, totaling up to $120,000 annually. preferred stock is Ameren Services Company.

"* reinvest their dividends in Ameren common stock or receive Ameren dividends in cash. OFFICE

"* place Ameren common stock certificates in safe Ameren General Office Building keeping and receive regular account statements. One Ameren Plaza 1901 Chouteau Avenue 0

0 For more information about DRPlus, you may obtain St. Louis, MO 63103 a prospectus from the company's Investor Services 314-621-3222 representatives.

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0 0 c2 C O) 2).

RMEREN 2001 ANNURL REPORT 55

viAmeren PO. Box 66149 St. Louis, Missouri 63166-6149