UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-K

 

(X)		Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2006
		OR
( )		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from        to       .

 

Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:

 

Each of the following classes or series of securities is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:

 

 

Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:

 

 

Ameren Energy Generating Company, CILCORP Inc., and Illinois Power Company do not have securities registered under either Section 12(b) or 12(g) of the Securities Exchange Act of 1934.

 

Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.

 

 

Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.

 

 

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (X)     No ( )

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

 

 

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934.

 

 

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

 

 

As of June 30, 2006, Ameren Corporation had 205,831,309 shares of its $0.01 par value common stock outstanding. The aggregate market value of these shares of common stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by nonaffiliates was $10,394,481,105. The shares of common stock of the other registrants were held by affiliates as of June 30, 2006.

 

The number of shares outstanding of each registrant’s classes of common stock as of February 1, 2007, was as follows:

 

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company, Central Illinois Public Service Company, and Central Illinois Light Company for the 2007 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.

 

OMISSION OF CERTAIN INFORMATION

 

Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.

 

This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power Company. Each registrant hereto is filing on its own behalf all of the information contained in this annual report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

 

TABLE OF CONTENTS

 

 

This Form 10-K contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 3 of this Form 10-K under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

 

We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.

 

AERG – AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates a non-rate-regulated electric generation business in Illinois.

AFS – Ameren Energy Fuels and Services Company, a Development Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.

Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.

Ameren Companies – The individual registrants within the Ameren consolidated group.

Ameren Energy – Ameren Energy, Inc., an Ameren Corporation subsidiary that is a power marketing and risk management agent for affiliated companies. Effective January 1, 2007, Ameren Energy serves only UE.

Ameren Illinois Utilities – CIPS, IP and the rate-regulated electric and gas utility operations of CILCO.

Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

AMT – Alternative minimum tax.

APB – Accounting Principles Board.

ARO – Asset retirement obligations.

Baseload  – The minimum amount of electric power delivered or required over a given period of time at a steady rate.

Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.

Capacity factor – A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.

CERCLA (Superfund) – Comprehensive Environmental Response Compensation Liability Act of 1980, a federal environmental law that addresses remediation of contaminated sites.

CILCO – Central Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.

CILCORP – CILCORP Inc., an Ameren Corporation subsidiary that operates as a holding company for CILCO and various non-rate-regulated subsidiaries.

CIPS – Central Illinois Public Service Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.

CIPSCO – CIPSCO Inc., the former parent of CIPS.

Cooling degree-days – The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is a useful measure of electricity demand by residential and commercial customers for summer cooling.

CT – Combustion turbine electric generation equipment used primarily for peaking capacity.

CUB – Citizens Utility Board.

Dekatherm (Dth) – one million BTUs of natural gas.

Development Company – Ameren Energy Development Company, which is a Resources Company subsidiary and Genco, Marketing Company and AFS parent.

DMG – Dynegy Midwest Generation, Inc., a Dynegy subsidiary.

DOE – Department of Energy, a U.S. government agency.

DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.

Dynegy – Dynegy Inc.

DYPM – Dynegy Power Marketing, Inc., a Dynegy subsidiary.

EEI – Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40% owned by UE and 40% owned by Development Company) that operates non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. The remaining 20% is owned by Kentucky Utilities Company.

EITF – Emerging Issues Task Force, an organization designed to assist the FASB in improving financial reporting through the identification, discussion and resolution of financial issues in keeping with existing authoritative literature.

ELPC – Environmental Law and Policy Center.

EPA – Environmental Protection Agency, a U.S. government agency.

Equivalent availability factor – A measure that indicates the percentage of time an electric power generating unit was available for service during a period.

ERISA – Employee Retirement Income Security Act of 1974, as amended.

Exchange Act – Securities Exchange Act of 1934, as amended.

FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

FERC – The Federal Energy Regulatory Commission, a U.S. government agency.

FIN – FASB Interpretation.  A FIN statement is an explanation intended to clarify accounting pronouncements previously issued by the FASB.

Fitch – Fitch Ratings, a credit rating agency.

FSP – FASB Staff Position, which provides application guidance on FASB literature.

FTRs – Financial transmission rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.

Fuelco – Fuelco LLC, a limited-liability company that provides nuclear fuel management and services to its members. The members are UE, Texas Generation Company LP, and Pacific Energy Fuels Company.

GAAP – Generally accepted accounting principles in the United States.

Genco – Ameren Energy Generating Company, a Development Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.

Gigawatthour – One thousand megawatthours.

Heating degree-days – The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.

IBEW – International Brotherhood of Electrical Workers, a labor union.

ICC – Illinois Commerce Commission, a state agency that regulates the Illinois utility businesses and operations of CIPS, CILCO and IP.

Illinois Customer Choice Law – Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and introduced competition into the retail supply of electric energy in Illinois.

Illinois EPA – Illinois Environmental Protection Agency, a state government agency.

Illinois Regulated – A financial reporting segment consisting of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO and IP.

Illinova – Illinova Corporation, the former parent company of IP.

IP – Illinois Power Company, an Ameren Corporation subsidiary acquired from Dynegy on September 30, 2004. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.

IP LLC – Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited-liability company. Under FIN 46R, Consolidation of Variable-interest Entities, IP LLC was no longer consolidated within IP’s financial statements as of December 31, 2003.

IP SPT – Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law. Pursuant to FIN 46R, IP SPT is a variable-interest entity, as the equity investment is not sufficient to permit IP SPT to finance its activities without additional subordinated debt.

IUOE – International Union of Operating Engineers, a labor union.

JDA – The joint dispatch agreement among UE, CIPS, and Genco under which UE and Genco jointly dispatched electric generation prior to its termination on December 31, 2006.

Kilowatthour – A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.

MAIN – Mid-America Interconnected Network, Inc., a regional electric reliability council organized to coordinate the planning and operation of the nation’s bulk power supply. MAIN ceased operations on January 1, 2006.

Marketing Company – Ameren Energy Marketing Company, a Development Company subsidiary that markets power for Genco, AERG and EEI.

Medina Valley – AmerenEnergy Medina Valley Cogen (No. 4) LLC and its subsidiaries, all Development Company subsidiaries, which indirectly own a 40-megawatt gas-fired electric generation plant.

Megawatthour – One thousand kilowatthours.

MGP – Manufactured gas plant.

MISO – Midwest Independent Transmission System Operator, Inc.

MISO Day Two Energy Market – A market that began operating on April 1, 2005. It uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power. The previous system required generators to make advance reservations for transmission service.

Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.

Missouri Regulated – A financial reporting segment consisting of all the operations of UE’s business, except for UE’s 40% interest in EEI and other non-rate-regulated activities.

Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between rate-regulated and non-rate-regulated businesses. These are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.

Moody’s – Moody’s Investors Service Inc., a credit rating agency.

MoPSC – Missouri Public Service Commission, a state agency that regulates the Missouri utility business and operations of UE.

NCF&O – National Congress of Firemen and Oilers, a labor union.

Non-rate-regulated Generation – A financial reporting segment consisting of the operations or activities of Genco, CILCORP holding company, AERG, EEI and Marketing Company.

NO_x – Nitrogen oxide.

Noranda – Noranda Aluminum, Inc.

NRC – Nuclear Regulatory Commission, a U.S. government agency.

NYMEX – New York Mercantile Exchange.

NYSE – New York Stock Exchange, Inc.

OATT – Open Access Transmission Tariff.

OCI – Other comprehensive income (loss) as defined by GAAP.

OTC – Over-the-counter.

PGA – Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.

PJM – PJM Interconnection LLC.

PUHCA 1935 – The Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 that was enacted on August 8, 2005.

PUHCA 2005 – The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.

Resources Company – Ameren Energy Resources Company, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Development Company, Genco, Marketing Company, AFS, and Medina Valley.

RTO – Regional Transmission Organization.

S&P – Standard & Poor’s Ratings Services, a credit rating agency that is a division of The McGraw-Hill Companies, Inc.

SEC – Securities and Exchange Commission, a U.S. government agency.

SERC – Southeastern Electric Reliability Council, Inc., one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.

SFAS – Statement of Financial Accounting Standards, the accounting and financial reporting rules issued by the FASB.

SO₂ – Sulfur dioxide.

TFN – Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP must designate a portion of cash received from customer billings to pay the TFNs. The proceeds received by IP are remitted to IP SPT. The proceeds are restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. Since the application of FIN 46R, IP does not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet.

TVA – Tennessee Valley Authority, a public power authority.

UE – Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri as AmerenUE.

 

 

 

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

 

 

Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

 

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren was formed in 1997 by the merger of UE and CIPSCO, the former parent company of CIPS. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP. Ameren’s subsidiaries, which are separate, independent legal entities, operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock depend upon distributions made to it by its subsidiaries.

 

The following table presents our total employees at December 31, 2006:

 

 

 

The IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 63% of Ameren’s total employees. They represent 73% of the employees at UE, 83% at CIPS, 71% at Genco, 71% at CILCORP, 71% at CILCO, and 91% at IP. Two IBEW collective bargaining agreements covering about 320 UE workers expired on September 30, 2006. Another IBEW agreement covering 17 IP workers expired on November 30, 2006. The UE collective bargaining agreements have been extended indefinitely by mutual agreement, and the IP agreement is currently in force under an extension, while negotiations continue on all three agreements. At this time, all employees continue to work without disruption. The most significant remaining issue associated with the UE agreements involves health care benefit plan revisions, and the most significant issue associated with the IP agreement involves continuity of work and incentive pay provisions. Most of the remaining collective bargaining agreements, covering 5,000 employees at UE, CIPS, Genco, CILCORP, CILCO and IP, expire throughout 2007.

 

For additional information about the development of our businesses, our business operations, and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.

 

BUSINESS SEGMENTS

 

Before the third quarter of 2006, Ameren reported only one business segment, Utility Operations, which comprised electric generation and electric and gas transmission and distribution operations. Ameren holding company activity was listed in the caption called Other.

 

In the third quarter of 2006, Ameren determined that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE determined it has one reportable segment: Missouri Regulated. CILCORP and CILCO determined they have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 17 – Segment Information to our financial statements under Part II, Item 8, of this report for additional information on reporting segments.

 

Rates

 

Rates that UE, CIPS, CILCO and IP are allowed to charge for their utility services are the single most important influence upon their and Ameren’s consolidated results of operations, financial position, and liquidity. The utility rates charged to UE, CIPS, CILCO and IP customers are determined by governmental entities. Decisions by these entities are influenced by many factors, including the cost of providing service, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views. Decisions made by these governmental entities regarding rates could have a material impact on the results of operations, financial position, or liquidity of UE, CIPS, CILCORP, CILCO, IP and Ameren.

 

The ICC regulates rates and other matters for CIPS, CILCO and IP. The MoPSC regulates UE.

 

FERC also regulates UE, CIPS, Genco, CILCO and IP as to their ability to charge market-based rates for the sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters. Less than 5% of the Ameren Companies’ electric operating revenues fall under FERC regulations.

 

About 39% of Ameren’s electric and 12% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2006. About 43% of

Ameren’s electric and 88% of its gas operating revenues were subject to regulation by the ICC that year. Interchange revenues are not subject to direct MoPSC or ICC regulation.

 

Missouri Regulated

 

About 82% of UE’s electric and 100% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2006.

 

If certain criteria are met, UE’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.

 

A new Missouri law enacted in July 2005 enables the MoPSC to put in place fuel and purchased power and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006 and became effective during the fourth quarter of 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. UE requested approval of a fuel and purchased power cost recovery mechanism in its electric rate case filed with the MoPSC in July 2006. The MoPSC staff and intervenors have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost recovery mechanism as part of this electric rate case. However, no environmental adjustment clause has been submitted in the rate case since final environmental cost recovery rules have not been adopted. UE’s requests are subject to approval by the MoPSC.

 

For further information on Missouri rate matters, including the Missouri law enabling fuel, purchased power and environmental cost recovery mechanisms, UE’s pending electric and gas rate cases following the expiration of a rate-adjustment moratorium in 2006 and termination of the JDA among UE, CIPS and Genco, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 – Rate and Regulatory Matters, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

 

Illinois Regulated

 

The following table presents the approximate percentage of electric and gas operating revenues subject to regulation by the ICC for each of the Illinois Regulated companies for the year ended December 31, 2006:

 

 

 

During 2006, retail electric rates were subject to a legislative rate freeze in Illinois. In February 2005, CIPS, CILCO and IP filed with the ICC a proposal for power procurement through an ICC-monitored auction including, among other things, a rate mechanism that would pass power supply costs directly through to customers after the rate freeze expired on January 1, 2007, and power supply contracts expired December 2006. In January 2006, the ICC issued an order that unanimously approved the Ameren Illinois Utilities’ proposed power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to electric customers.

 

The power procurement auction was held and declared successful for fixed-price customers in September 2006. The vast majority of electric customers of CIPS, CILCO and IP are fixed-price customers.

 

If certain criteria are met, CIPS’, CILCO’s and IP’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.

 

Environmental adjustment rate riders authorized by the ICC permit the recovery of prudently incurred MGP remediation and litigation costs from CIPS’, CILCO’s and IP’s Illinois electric and natural gas utility customers. As a part of the order approving Ameren’s acquisition of IP, the ICC also approved a tariff rider that would allow IP to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.

 

This report includes further information on rate matters, including the ICC order allowing for the recovery of prudently incurred power costs effective January 2, 2007, and related court proceedings; CIPS’, CILCO’s and IP’s 2006 ICC electric delivery services rate case orders; and actions taken by certain Illinois legislators, the Illinois governor, the Illinois attorney general, and others regarding the expiration of the rate freeze and oppositions to the power procurement auction. See Results of Operations and Outlook in Management’s Discussion and Analysis of Financial

Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 – Rate and Regulatory Matters, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

 

General Regulatory Matters

 

PUHCA 2005, enacted as part of the Energy Policy Act of 2005, repealed PUHCA 1935, effective February 8, 2006. Under PUHCA 2005, UE, CIPS, CILCO and IP must receive FERC approval to issue short-term debt securities and to conduct certain acquisitions, mergers and consolidations involving electric utility holding companies having a value in excess of $10 million. In addition, these Ameren utilities must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities with maturities of more than 12 months and to conduct mergers, affiliate transactions, and various other activities. Genco and EEI are subject to FERC’s jurisdiction when they issue any securities.

 

Under PUHCA 2005, FERC and any state public utility regulatory agencies may access books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren, the ICC, or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.

 

Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on June 11, 2024. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for the Osage plant expired on February 28, 2006, but the plant is allowed to operate under this license pending FERC’s decision on UE’s license renewal application. In May 2005, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage plant for another 40 years. The settlement must be approved by FERC. The license for UE’s Taum Sauk plant expires on June 30, 2010. The Taum Sauk plant is currently out of service due to a major breach of the upper reservoir in December 2005. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under open-ended authority, granted by an Act of Congress in 1905.

 

For additional information on regulatory matters, see Note 3 – Rate and Regulatory Matters and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, which include a discussion about the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.

 

Environmental Matters

 

Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These matters include identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on us. We could be subjected to criminal or civil penalties by regulatory agencies. We could be ordered to make payment to private parties by the courts. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.

 

For additional discussion of environmental matters, including NO_x, SO₂, and mercury emission reduction requirements and the December 2005 breach of the upper reservoir at UE’s Taum Sauk hydroelectric plant, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

 

During 2006, the Ameren Companies’ peak demand from retail and wholesale customers was 17,703 megawatts. The combined peak capability to deliver power from owned generation and power supply agreements was 20,899 megawatts. Ameren-owned generation and purchased power currently meet the energy needs of UE, Genco, AERG and Marketing Company customers, with the required reserve margins. Power for the Ameren Illinois Utilities is purchased through an ICC-approved auction that was first held in September 2006. Factors that could cause us to purchase power include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it.

 

Effective January 1, 2006, Ameren became a member of SERC, a regional electric reliability organization. SERC is responsible for promoting, coordinating and ensuring the reliability and adequacy of the bulk electric power supply system in much of the southeastern United States, including portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP. Ameren was previously a member of MAIN, which ceased operations on January 1, 2006.

 

Before the termination of the JDA on December 31, 2006, the bulk power system of UE, CIPS and Genco operated as a single control area and transmission system,

and CILCO and IP operated as separate control areas. On July 7, 2006, UE, CIPS and Genco mutually agreed to terminate the JDA on December 31, 2006. This action was accepted by the FERC in September 2006. In conjunction with terminating the JDA, Ameren’s transmission-owning entities restructured their control areas into one control area in Missouri for UE’s transmission facilities and one in Illinois for the transmission facilities of CIPS, CILCO and IP. See Note 3 – Rate and Regulatory Matters and Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for more information on the JDA. In 2006, we had at least 18 direct connections with other control areas for the exchange of electric energy, some directly and some through the facilities of others. EEI operates a separate control area in southern Illinois. EEI’s transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG. UE, CIPS, CILCO and IP are transmission-owning members of the MISO, and they have transferred functional control of their systems to the MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems is provided pursuant to the terms of the MISO OATT on file with FERC. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.

 

Missouri Regulated

 

UE’s electric supply is obtained primarily from its own generation. In March 2006, UE completed the purchase of three CT facilities, totaling 1,490 megawatts of capacity at a price of $292 million. These purchases were designed to help meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining when to add future baseload generating capacity. UE expects the addition of these CT facilities to satisfy demand growth until about 2018. In the meantime, UE will be evaluating baseload electric generating plant options, including coal-fired, nuclear, pumped-storage and integrated gasification combined cycle coal technology. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for a discussion of the CT facilities purchases.

 

Illinois Regulated

 

CIPS, CILCO and IP own no generation facilities. CIPS bought power from Genco, and CILCO bought power from AERG, both under contracts that expired at the end of 2006. IP’s primary power supply contract with Dynegy also expired at the end of 2006. In connection with the expiration of the power supply agreements, the ICC approved an auction framework to allow electric utilities in Illinois, including CIPS, CILCO and IP, to procure power for use by their customers in 2007. The power procurement auction was held in September 2006. See Note 3 – Rate and Regulatory Matters and Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of the ICC-approved power procurement auction.

 

Non-rate-regulated Generation

 

In December 2005, EEI entered into a power supply agreement with Marketing Company, whereby EEI sells 100% of its capacity and energy to Marketing Company. Commencing in 2007, Genco and AERG are also selling power to Marketing Company. Marketing Company sold power through the Illinois power procurement auction to CIPS, CILCO and IP and is selling power through other contracts with wholesale and retail customers. See Note 3 – Rate and Regulatory Matters and Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of power supply agreements.

 

The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2006, 2005 and 2004:

 

 

The following table presents the cost of fuels for electric generation for the years ended December 31, 2006, 2005 and 2004.

 

 

 

Coal

 

UE, Genco, CILCO (AERG) and EEI have agreements in place to purchase coal and to transport it to electric generating facilities through 2011. UE, Genco, AERG and EEI expect to enter into additional contracts to purchase coal. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. As of December 31, 2006, 100% of UE’s, Genco’s, AERG’s and EEI’s expected 2007 coal usage was under contract, and about 54% of the expected coal usage for 2008 to 2011 was under contract. Ameren burned 40 million (UE – 23 million, Genco – 8 million, AERG – 4 million, EEI – 5 million) tons of coal in 2006.

 

More than 90% of Ameren’s coal is purchased from the Powder River Basin in Wyoming. The remaining coal is purchased from the Illinois Basin. UE, Genco, AERG and EEI have a policy to maintain coal inventory consistent with their projected usage. Inventory may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. As of December 31, 2006, coal inventories for UE, Genco, AERG and EEI were adequate and consistent with historical levels, but below targeted levels due to rail deliveries from the Powder River Basin below requested levels. Disruptions in deliveries of coal could cause UE, Genco, AERG and EEI to incur higher costs for fuel and purchased power and could reduce their interchange sales.

 

Nuclear

 

Fuel assemblies for the 2007 spring refueling are already at UE’s Callaway nuclear plant. UE also has agreements or inventories to meet 61% of Callaway’s 2008 to 2011 requirements. UE expects to enter into additional contracts to purchase nuclear fuel. Prices cannot be accurately predicted at this time. UE is a member of Fuelco, which allows UE to join with other member companies to increase its purchasing power and opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was

completed in November 2005. The next refueling is scheduled for April 2007.

 

Natural Gas Supply for Power Generation

 

Ameren’s portfolio of natural gas supply resources includes firm transportation capacity, and firm no-notice storage capacity leased from interstate pipelines to maintain gas deliveries to our gas-fired generating units throughout the year, especially during the summer peak demand. UE, Genco and EEI primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to generating units. In addition to physical transactions, Ameren uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.

 

UE’s, Genco’s and EEI’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. UE, Genco and EEI do this in two ways. UE, Genco and EEI optimize transportation and storage options and minimize cost and price risk through various supply and price hedging agreements that allow them to maintain access to multiple gas pools, supply basins, and storage. As of December 31, 2006, UE had about 39% and Genco had 100% of its required gas supply for generation for 2007 hedged for price risk. For 2008 to 2011, UE has 1% of its estimated required natural gas supply for generation hedged for price risk, and Genco has 7% hedged. As of December 31, 2006, EEI did not have any of its required gas supply for generation hedged for price risk.

 

Purchased Power

 

We believe that we can obtain enough purchased power to meet future needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected. The Ameren transmission system has a minimum of 18 direct connections to other control areas, which give us access to numerous sources of supply. UE, CIPS, CILCO and IP are members of the MISO. The MISO Day Two Energy Market is designed to provide transparency of power pricing and to make generation dispatch efficient. The MISO Day Two Energy Market also makes available power from the entire MISO transmission grid.

 

Illinois Regulated

 

CIPS, CILCO and IP were subject to legislative electric rate freezes in Illinois through January 1, 2007, and had power supply contracts in place through December 31, 2006, to meet their customers’ needs. In January 2006, the ICC approved a power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates at which power supply costs would be passed through to customers. The power procurement auction was held at the beginning of September 2006. The auction was designed to procure the power supply needs of CIPS, CILCO and IP through a portfolio of one-, two- and three-year supply agreements for residential and small commercial customers and one-year agreements for large commercial and industrial customers. Through the auction, CIPS, CILCO and IP acquired 100% of expected power supply requirements for all customers through May 31, 2008, two-thirds of supply requirements for residential and small commercial customers for June 1, 2008, through May 31, 2009, and one-third of the requirements for these customers for June 1, 2009, through May 31, 2010. See Note 14 – Commitments and Contingencies under Part II, Item 8, of the report for more information on the results of the Illinois power procurement auction. The next Illinois power procurement auction is scheduled for January 2008.

 

See Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Risk Factors under Part I, Item 1A, and Note 3 – Rate and Regulatory Matters, under Part II, Item 8, of this report for a discussion of credit rating changes issued in response to potential actions in Illinois that could threaten the financial solvency of CIPS, CILCO and IP and their ability to procure power.

 

Non-rate-regulated Generation

 

In December 2006, Genco and AERG each entered into separate power supply agreements to sell all of their generation capacity to Marketing Company. Both agreements began on January 1, 2007, and will continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement. In December 2005, Marketing Company entered into a power supply agreement with EEI, whereby EEI agreed to sell 100% of its capacity and energy to Marketing Company. This agreement expires on December 30, 2015. A portion of this power was sold by Marketing Company into the Illinois power procurement auction. For additional information on the electric power supply agreements, see Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report.

 

UE, CIPS, CILCO and IP are responsible for the purchase and delivery of natural gas to their gas utility customers. UE, CIPS, CILCO and IP develop and manage a portfolio of gas supply resources, including firm gas supply under term agreements with producers, interstate and intrastate firm transportation capacity, firm storage capacity leased from interstate pipelines, and on-system storage facilities to maintain gas deliveries to our customers throughout the year and especially during peak demand. UE, CIPS, CILCO and IP primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, and the Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to physical transactions, financial instruments including those entered into in the NYMEX futures market and in the OTC

financial markets are used to hedge the price paid for natural gas. Prudently incurred natural gas purchase costs are passed on to UE, CIPS, CILCO and IP gas customers in Illinois and Missouri dollar-for-dollar under PGA clauses, subject to prudency review by the ICC and the MoPSC.

 

For additional information on our fuel and purchased power supply, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation and Changing Prices in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report; Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report; and Note 1 – Summary of Significant Accounting Policies, Note 8 – Derivative Financial Instruments, Note 13 – Related Party Transactions, Note 14 – Commitments and Contingencies, and Note 15 – Callaway Nuclear Plant to our financial statements under Part II, Item 8, of this report.

 

We are facing issues common to the electric and gas utility industry and the non-rate-regulated electric generation industry. These issues include:

 

 

We are monitoring these issues. We are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 3 – Rate and Regulatory Matters, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

 

 

The following tables present key electric and natural gas operating statistics for Ameren for the past three years. Unless otherwise indicated, IP is included only for the periods after its acquisition on September 30, 2004.

 

 

 

 

 

 

The Ameren Companies make available free of charge through Ameren’s Internet Web site (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through an Internet Web site maintained by the SEC (www.sec.gov).

 

The Ameren Companies also make available free of charge through Ameren’s Web site (www.ameren.com) the charters of Ameren’s board of directors’ audit committee, human resources committee, nominating and corporate governance committee, nuclear oversight committee, and public policy committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to the Ameren Companies.

 

These documents are also available in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. The public may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

 

 

The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are currently the subject of rate case proceedings and potential legislative action. The outcome of these proceedings and of other potential legislative action or future rate proceedings is largely outside of our control. Should these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position, or liquidity. In particular, we believe freezing electric rates at 2006 levels in Illinois would lead to CIPS, CILCORP, CILCO and IP being financially insolvent.

 

The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, or liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on our results of operations, financial position, or liquidity.

 

Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. Ameren expects that many of its operating expenses will continue to rise. Ameren further expects to continue to make significant investment in its energy infrastructure. These are the two principal factors underlying the pending rate increase requests with the MoPSC and the rate increase requests recently acted upon and pending rehearing with the ICC. We cannot predict the outcome of these rate case proceedings or of potential Illinois legislative action to deny full recovery of costs. In addition, in response to competitive, economic, political, legislative and regulatory pressures, in connection with the resolution of our current rate case proceedings or otherwise, we may be subject to further rate moratoriums, rate refunds, limits on rate increases, or rate reductions, including phase-in plans. Any or all of these could have a material adverse effect on our results of operations, financial position, or liquidity.

 

Illinois

 

Electric Delivery Service Rate Cases

 

A provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS – $14 million, CILCO – $43 million and IP – $145 million). In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS – an $8 million decrease, CILCO – a $21 million increase and IP – an $84 million increase) based on an allowed return on equity of 10%. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling $50 million, that were disallowed. The ICC’s decision on the recovery of these expenses is due in May 2007. The ICC denied requests for rehearings filed by other parties in this case. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which includes the cost of power, so these delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.

 

Potential Electric Rate Freeze and Recovery of Post-2006 Power Supply Costs

 

Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expired on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006.

 

Subsequently, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, and the independent auction manager declared a successful result in the auction for these fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. In February 2006, legislation was introduced in the Illinois House of Representatives that would have extended the electric rate freeze in Illinois at 2006 levels through 2010. On October 2, 2006, Speaker of the Illinois House of Representatives Michael Madigan sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly to consider this rate freeze legislation. The governor sent a letter indicating that once the votes to pass the legislation were in place, he would immediately call for a special session of the legislature. The governor’s letter further provided that if a consensus among members of the general assembly could not be reached in the near future, he would call a special session as well. The governor’s letter stated that he continued to support legislation extending the rate freeze and would like to sign it into law as soon as possible. No special session was called in 2006. During the Illinois General Assembly’s session that ended in January 2007, the Illinois House of Representatives passed legislation to freeze rates at 2006 levels through 2010, and the Illinois Senate passed legislation containing an electric rate increase phase-in plan. The Illinois Senate bill provided for a mandatory phase-in of the 2007 increase in residential electric rates over a three-year period. Neither piece of legislation was passed by the other chamber before the end of the session in early January 2007.

 

Any legislative measure will need to be approved by the Illinois House of Representatives and Illinois Senate, and signed by the Illinois governor before it can become law. New rates for CIPS, CILCO and IP reflecting the power costs resulting from the ICC-approved September 2006 auction and the delivery service rates authorized by the November 2006 ICC order became effective January 2, 2007. A new Illinois General Assembly went into session in late January 2007. As a result, all previous bills expired. New bills have been introduced during the current legislative session, including legislation to rollback rates to 2006 levels similar to previously proposed legislation. On February 27, 2007, the Ameren Illinois Utilities announced that they intended to file an electric rate increase mitigation plan with the ICC. As part of the plan, which is subject to ICC approval, the Ameren Illinois Utilities would fund an approximate $20 million one-time reduction to active residential accounts that would appear on electric bills in March and April 2007. The rate mitigation plan is targeted to customers with high volume usage. As part of the filing, the carrying charge of 3.25% in the current ICC-approved phase-in plan would be eliminated. If approved by the ICC, the one-time credit for residential customers would result in a charge to Ameren’s earnings in 2007 of $20 million, or 6 cents per share. In addition, eliminating the below-market interest rate on deferred amounts under the phase-in plan would increase financing costs for the Ameren Illinois Utilities during the deferral period. The actual cost to Ameren will depend on the level of participation in the phase-in plan.

 

CIPS, CILCORP, CILCO and IP believe that legislation freezing electric rates at 2006 levels, if enacted, would have a material adverse effect on their results of operations, financial position, and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP. They believe it could cause significant job losses and, without governmental intervention, significant disruptions in electric and gas

service. Since Ameren’s Illinois utilities own no generation facilities, the companies must purchase power on the competitive market to meet customers’ energy needs. If electric rates were to be frozen at 2006 levels, the major credit rating agencies have stated that the Ameren Illinois Utilities’ credit ratings would be downgraded to deep junk (or speculative) status. Such a downgrade of CILCO’s ratings would also result in a similar downgrade of CILCORP’s ratings. We believe that CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements for products and services, such as natural gas, and would eventually run out of cash and available credit and be unable to borrow. We believe that this would cause the Ameren Illinois Utilities and CILCORP to become financially insolvent. In reaction to intensified political discussion in Illinois regarding electric rate freeze extension legislation, in October 2006, S&P downgraded the short- and long-term credit ratings of the Ameren Companies and kept the Ameren Companies on credit watch with negative implications; Moody’s placed the long-term debt ratings of the Ameren Companies under review for possible downgrade; and Fitch placed the ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.

 

CIPS, CILCO and IP strongly believe that freezing rates at 2006 levels in Illinois would not be in the best interests of any of the Ameren Illinois Utilities or their customers. In December 2006, the ICC approved a constructive rate increase phase-in plan proposed by CILCO, CIPS and IP for residential, small commercial, and eligible local governmental and school customers to address the significant increases in customer rates for the Ameren Illinois Utilities beginning in 2007. However, if the Illinois legislature passes rate phase-in legislation that does not allow for the full and timely recovery of costs, it could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.

 

Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies, and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their legal and financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois Utilities will prevail over the stated opposition of certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois Utilities are considering will be successful.

 

We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs. Nor can we predict the actions the Illinois General Assembly and governor may take that may affect electric rates or the power procurement process for CIPS, CILCO and IP. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk (or speculative) status, a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, significant risk of disruption in electric and gas service, significant job losses, and financial insolvency. In addition, Ameren, CILCORP and IP could be required to record a charge for goodwill impairment for the goodwill that was recorded when Ameren acquired CILCORP and IP. As of December 31, 2006, Ameren had $830 million, CILCORP $542 million and IP $213 million of goodwill on their balance sheets. Furthermore, if the Ameren Illinois Utilities are unable to recover their costs from customers, the utilities could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which allows CIPS, CILCORP, CILCO and IP to defer certain costs pursuant to actions of rate regulators and to recover such costs in rates charged to customers. This would result in the elimination of all regulatory assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary charge on their statements of income that could be material. As of December 31, 2006, CIPS had $146 million, CILCORP $75 million, CILCO $75 million and IP $401 million recorded as regulatory assets on their balance sheets.

 

Missouri

 

With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In December 2006, the MoPSC staff and other stakeholders filed direct testimony in response to UE’s rate case filings. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million and a gas rate increase of $2 million to $3 million. During the course of the rate proceeding, parties to the case may change their positions. A decision from the MoPSC is expected no later than June 2007. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.

 

UE does not currently have a rate-adjustment clause for its electric operations in Missouri that would allow it to recover from customers the costs for purchased power, fuel, or infrastructure investment. Therefore, insofar as UE has not hedged its fuel and power costs, UE is exposed to changes in fuel and power prices to the extent they exceed the costs embedded in current electric rates. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism that would be subject to MoPSC approval. The MoPSC staff and intervenors in the electric rate case have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost-recovery mechanism as part of its pending Missouri electric rate case, but no rules have been established for such a mechanism. Any new energy infrastructure investment could result in increased

financing requirements for UE, which could increase further depending on rate case outcomes. The lack of timely recovery of these costs could have a material adverse effect on UE’s results of operations, financial position, or liquidity. We are unable to predict whether the MoPSC will approve our request for a fuel and purchased power cost recovery mechanism in our pending electric rate case. We also are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted.

 

If Illinois electric rates are frozen at 2006 levels or if the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates is otherwise impaired, there may be a material adverse effect on Ameren, UE and Genco in addition to the Ameren Illinois Utilities and CILCORP.

 

We believe that freezing electric rates at 2006 levels in Illinois would cause CIPS, CILCORP, CILCO and IP to become financially insolvent. Although the Ameren Companies are separate, independent legal entities with separate businesses, assets and liabilities, there is a risk that the financial insolvency of CIPS, CILCORP, CILCO and IP could have a materially adverse effect on Ameren, UE and Genco. If rates are frozen at 2006 levels in Illinois for CIPS, CILCO and IP, or if the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates is otherwise impaired, such events might increase Ameren’s, UE’s and Genco’s cost of capital or adversely affect the ability of these companies to access the capital markets, particularly during times of uncertainty in the capital markets, which could negatively affect their ability to maintain and expand their businesses. Moody’s, S&P and Fitch each have indicated that they would lower the credit ratings for CIPS, CILCORP, CILCO and IP to deep junk (or speculative) status, if electric rates were frozen at 2006 levels, reflecting the material impact such action would have on the cash flow and liquidity of these companies. It is possible that the rating agencies could decide to lower the credit ratings of Ameren, UE or Genco at the same time. Any adverse change in the ratings of Ameren, UE or Genco could also increase their cost of borrowing under existing credit facilities, and suppliers might begin to request prepayment for products and services (such as fuel, power and gas) or the posting of collateral.

 

If CIPS, CILCORP, CILCO and IP become insolvent, their commitments to Ameren, Genco and AERG might be unfulfilled. Pursuant to agreements executed in connection with the recent Illinois power procurement auction, Marketing Company is selling to CIPS, CILCO and IP power that is being supplied under contracts from Genco and AERG. If CIPS, CILCORP, CILCO and IP become insolvent, Genco, AERG or Marketing Company may not be able to recover the cost of power delivered to those companies but not paid for prior to insolvency. Marketing Company’s commitments to sell power to CIPS, CILCO, IP and other unaffiliated parties also rely, in part, on power supplied by AERG. In the event of financial insolvency, AERG may not be able to deliver power it has committed to sell to Marketing Company; that could force Marketing Company to acquire the power to meet its commitments at a higher cost.

 

In addition, dividends on Ameren’s common stock and the payment of Ameren’s other obligations, including its debt, depend on distributions made to it by its subsidiaries. If CIPS, CILCORP, CILCO and IP should become insolvent, they will not be able to make distributions to Ameren. Additionally, if CIPS, CILCORP, CILCO and IP fall below investment grade in ratings of their securities, they will be limited in the amount of dividends they may pay. As a result, the board of directors of Ameren might decide to rely more heavily on UE and Ameren’s unregulated operations to support dividends on Ameren’s common stock, or to reduce or eliminate the payment of dividends. Moreover, the absence of distributions from the Illinois utilities and CILCORP could force Ameren to use other available sources of liquidity to service its debt obligations.

 

We cannot determine at this time whether the freezing of rates at 2006 levels in Illinois that would lead to CIPS, CILCORP, CILCO and IP insolvency will occur. We also cannot determine what the resulting effect would be on Ameren, UE and Genco. However, the financial insolvency of CIPS, CILCORP, CILCO and IP could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren, UE and Genco.

 

Our counterparties may not meet their obligations to us.

 

We are exposed to the risk that counterparties to various arrangements (including our affiliates) who owe us money, energy, coal or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. In such event, we might incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.

 

Increased federal and state environmental regulation will require UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and to incur increased operating costs. Future limits on greenhouse gas emissions could result in significant increases in capital and operating expenditures.

 

About 61% of Ameren’s generating capacity is coal-fired and about 85% of its electric generation was produced by its coal-fired plants in 2006. The rest is nuclear, gas-fired, hydroelectric, and oil-fired. In May 2005, the EPA issued final regulations with respect to SO₂, NO_x, and mercury emissions from coal-fired power plants. The new rules require significant additional reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of capital compliance costs for Ameren, UE, Genco and AERG range from $3.5 billion to $4.5 billion by 2016.

 

The Missouri Department of Natural Resources formally proposed rules to implement the federal Clean Air Mercury and Clean Air Interstate Rules in November 2006. Missouri

rules are similar to the federal rules. The Missouri Air Conservation Commission approved the rules at their February 2007 meeting. The rules will be effective after publication in the Missouri Register targeted for April 2007. The rules will also need to be approved by the EPA. If approved, these rules when fully implemented are expected to reduce mercury emissions 81% by 2018 and to reduce NO_x emissions 30% and SO₂ emissions 75% by 2015.

 

Illinois has proposed rules to implement the federal Clean Air Interstate Rule program; however it is anticipated that the rules will not be finalized until the second quarter of 2007. The Illinois EPA proposed rules for mercury that are significantly stricter than the federal rules. Illinois has also proposed Clean Air Interstate Rule program rules for NO_x that are more stringent than the federal program. In 2006, Genco, AERG, EEI, and the Illinois EPA entered into an agreement on Illinois’ mercury rules. Under the agreement, Illinois generators may delay the compliance date for mercury reductions in exchange for accelerated installation of NO_x and SO₂ controls. The agreement with the Illinois EPA also restricts the purchase of SO₂ and NO_x emission allowances to meet specific allowed emission rates set forth in the agreement. The Illinois Joint Committee on Administrative Review approved the Illinois mercury rule in December 2006, and the Illinois Pollution Control Board issued a final order and adopted the mercury rule in late December 2006. The final rule was published in the Illinois Register in January 2007. The rule will also need to be approved by the EPA. When fully implemented, these rules are expected to reduce mercury emissions 90%, NO_x emissions 50% and SO₂ emissions 70% by 2015.

 

Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity by the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects. Future legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.

 

The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were made.

 

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act, seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired plants. Genco is asked to respond to specific EPA questions about certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standards required by the Clean Air Act. These information requests are being complied with, but we cannot predict the outcome of this matter.

 

We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on our results of operations, financial position, or liquidity. Any of these factors could result in a significant increase in capital expenditures, closure of power plants, penalties and operating costs for UE, Genco, CILCO (through AERG) and EEI. Therefore, such factors could also result in decreased revenues, increased financing requirements and increased costs for these Ameren companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois.

 

Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.

 

We offer defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2006, and the new contribution requirements in the Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect to pay a required contribution of $100 million to $150 million. Required contributions of $150 million to $200 million each year are also expected for 2010 and 2011. We expect the companies to share future funding requirements as follows: UE – 61%; CIPS – 10%; Genco – 11%; CILCO – 7%; and IP – 11%. These amounts are estimates. They may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.

 

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits may adversely affect our results of operations, financial position, or liquidity.

 

UE’s, Genco’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, liability, and increased purchased power costs.

 

UE, Genco, AERG, Medina Valley, and EEI own and operate coal-fired, nuclear, gas-fired, hydroelectric, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output and efficiency levels. Among these risks are:

 

 

The breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could continue to have an adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.

 

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park.

 

The FERC investigation of the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation by the FERC’s Office of Enforcement. They looked into alleged violations of license conditions and FERC regulations by UE as the licensee of the Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply with a new dam safety program developed in connection with the settlement.

 

In December 2006, the state of Missouri, through its attorney general and 10 business owners filed separate lawsuits regarding the Taum Sauk breach. The attorney general’s lawsuit, which was filed in the Missouri circuit court in St. Louis, alleges negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims. The business owners’ suit, which was filed in the Missouri circuit court in Reynolds County, contains similar allegations. It seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages. In January 2007, the Missouri Department of Natural Resources filed a petition to intervene as a plaintiff in the attorney general’s lawsuit.

 

In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk Plant, assuming successful resolution of outstanding issues with agencies of the state of Missouri. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer. In 2005, the Taum Sauk facility provided 589,000 megawatthours of electricity.

 

To the extent that UE needs to purchase power because of the unavailability of the Taum Sauk facility, there is the risk that UE will not be permitted to recover these additional costs from ratepayers if such a request is made. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2007 pretax earnings by $15 million to $20 million as a result of higher-cost sources of power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs. In addition, there is also the risk that UE will not be permitted to rebuild the Taum Sauk facility upper reservoir. UE could be required to expense its remaining investment in the plant of $64 million immediately.

 

At this time, excluding fines and penalties, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. Under UE’s insurance policies, all claims by UE are subject to review by its insurance carriers. Until the reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, a final decision about whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

 

Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.

 

As of December 31, 2006, Genco and CILCO (through AERG) owned non-rate-regulated electric generating facilities with capacities of 4,222 megawatts and 1,138 megawatts, respectively. During 2006, most of Genco’s and AERG’s wholesale and retail electric power supply agreements

expired. As a result, Genco and AERG now compete for the sale of energy and capacity through Marketing Company.

 

As of December 31, 2006, EEI owned 1,055 megawatts of non-rate-regulated electric generating facilities. On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. All of EEI’s generating capacity now competes for the sale of energy and capacity through Marketing Company.

 

To the extent that electric capacity generated by these facilities is not under contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:

 

 

UE’s ownership and operation of a nuclear generating facility creates business, financial, and waste disposal risks.

 

UE owns the Callaway nuclear plant, which represents about 12% of UE’s generation capacity and produced 13% of UE’s 2006 generation. Therefore, UE is subject to the risks of nuclear generation, which include the following:

 

 

The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position, or liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.

 

UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in 2007. During an outage, which occurs approximately every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, compared with non-outage years.

 

Operating performance at UE’s Callaway nuclear plant has resulted in unscheduled or extended outages. The operating performance at UE’s Callaway nuclear plant has declined both in comparison with its past operating performance and in comparison with the operating performance of other nuclear plants in the United States. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. Management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, training, and overall organizational effectiveness have been reviewed. Some actions have been taken and other actions are under consideration. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren and UE.

 

Our energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings.

 

We are exposed to changes in market prices for natural gas, fuel, electricity, emission allowances, and transmission congestion. Prices for natural gas, fuel, electricity, and emission allowances may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We use long-term purchase and sales contracts in

addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities because of future volatility in these markets.

 

Although we routinely enter into contracts to hedge our exposure to the risks of demand, market effects of weather, and changes in commodity prices, we do not hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, or liquidity.

 

Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.

 

Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs for repair, which could have a material adverse effect on our results of operations, financial position, or liquidity.

 

Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.

 

We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including those related to future environmental compliance. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. See the Credit Ratings section in Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of credit rating changes in response to actions in Illinois with respect to the matter of power procurement commencing in 2007.

 

None.

 

 

For information on our principal properties, see the generating facilities table below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for any planned additions, replacements or transfers. See also Note 2 – Acquisitions, Note 6 – Long-term Debt and Equity Financings, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

 

The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2007 peak summer electrical demand:

 

 

 

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer. For additional information on the Taum Sauk incident, see Note 14 – Commitments and Contingencies under Part II, Item 8 of this report.

 

The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2006:

 

 

Our other properties include distribution lines, underground cables, office buildings, warehouses, garages, and repair shops.

 

With only a few exceptions, we have fee title to all principal plants and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bond and credit facility indebtedness and to certain permitted liens and judgment liens). The exceptions are as follows:

 

 

Substantially all of the properties and plant of UE, CIPS, CILCO and IP are subject to the direct first liens of the indentures securing their mortgage bonds. In October 2003, CILCO transferred substantially all of its generating property and plant to its non-rate-regulated electric generating subsidiary, AERG. In December 2006, CILCO transferred the remainder of its generating property and plant to AERG. As part of these transfers, CILCO’s transferred generating property and plant was released from the lien of the indenture securing its first mortgage bonds. In May 2005, UE transferred substantially all of its Illinois electric and gas transmission and distribution properties to CIPS. As a part of the transfer, UE’s transferred utility properties were released from the lien of the indenture securing its first mortgage bonds and immediately became subject to the lien of the indenture securing CIPS’ first mortgage bonds. In July 2006 and February 2007, AERG recorded open-ended mortgages and security agreements with respect to its E.D. Edwards and Duck Creek power plants to serve as collateral to secure its obligations under multiyear, senior secured credit facilities entered into on July 14, 2006 and February 9, 2007, along with other Ameren subsidiaries. See Note 5 –

Credit Facilities and Liquidity for details of the credit facilities.

 

In December 2002, UE conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city for a 20-year term. As a part of the transaction, most of UE’s Peno Creek CT property and plant was released from the lien of the indenture securing UE’s first mortgage bonds. Under the terms of this capital lease, UE retains all operation and maintenance responsibilities for the facility. Ownership of the facility will return to UE at the expiration of the lease. When ownership of the Peno Creek CT facility is returned to UE by Bowling Green, the property and plant may again become subject to the lien of any outstanding UE first mortgage bond indenture.

 

In March 2006, UE purchased a CT facility located in Audrain County, Missouri, from NRG Audrain Holding, LLC, and NRG Audrain Generating LLC, affiliates of NRG Energy, Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County and assumed NRG’s obligations under the lease. The lease term will expire December 1, 2023. Under the terms of this capital lease, UE has all operation and maintenance responsibilities for the facility, and ownership of the facility will be transferred to UE at the expiration of the lease. When ownership of the Audrain County CT facility is transferred to UE by the county, the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.

 

For additional information on these CT lease arrangements, see Note 2 – Acquisitions under Part II, Item 8, of this report.

 

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.

 

In April 2005, Caterpillar Inc. intervened in the ICC proceedings relating to the power procurement auction and related tariffs of CILCO, CIPS and IP. In the Ameren Illinois Utilities’ 2005 auction process proceedings, Caterpillar Inc., in conjunction with other industrial customers as a coalition, opposed the Ameren Illinois Utilities’ filing on issues regarding auction design and auction process, among others. In February 2006, Caterpillar Inc. intervened in the 2006 rate cases filed by the Ameren Illinois Utilities with the ICC to modify their electric delivery service rates. In the 2006 rate cases, Caterpillar Inc., in conjunction with other industrial customers as a coalition, opposed the Ameren Illinois Utilities’ filings on issues regarding rate design and revenue requirements, among others. Douglas R. Oberhelman is an executive officer of Caterpillar Inc. and a member of the board of directors of Ameren. Mr. Oberhelman did not participate in Ameren Corporation’s board and committee deliberations relating to these matters.

 

Anheuser-Busch, Incorporated, an affiliate of Anheuser-Busch Companies, Inc., and The Boeing Company are members of the Missouri Industrial Energy Consumers group (MIEC) which, on September 1, 2006, intervened in the MoPSC proceedings relating to UE’s request for an increase in base rates for electric service. MIEC’s position in the case is that UE overstated its needed revenue requirement and that a disproportionate amount of the increase has been assigned to industrial customers. MIEC also opposes UE’s requested fuel and purchased power cost recovery mechanism. Patrick T. Stokes is the chairman of the board of directors of Anheuser-Busch Companies, Inc. and James C. Johnson is an officer of The Boeing Company. Mr. Stokes and Mr. Johnson are also members of the board of directors of Ameren. Neither Mr. Stokes nor Mr. Johnson participated in Ameren Corporation’s board and committee deliberations relating to these matters.

 

For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1, Business, and Item 1A, Risk Factors, above. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 3 – Rate and Regulatory Matters, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

 

There were no matters submitted to a vote of security holders during the fourth quarter of 2006 with respect to any of the Ameren Companies.

 

 

The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2006, all positions and offices held with the Ameren Companies, tenure as officer, and business background for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.

 

AMEREN CORPORATION:

 

 

Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the officers. Except for Richard J. Mark and Donna K. Martin, all of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.

 

Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren began trading on January 2, 1998, following the merger of UE and CIPSCO on December 31, 1997. On May 25, 2006, Ameren submitted to the NYSE a certificate of the chief executive officer of Ameren certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.

Ameren common shareholders of record totaled 79,041 on January 31, 2007. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2006 and 2005.