ITEM 1.
BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was formed in 1997 by the merger of UE and CIPSCO. 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.
To streamline its organizational structure, during late 2007, Ameren dissolved, merged or consolidated various of its subsidiaries that were inactive or had minimal or ancillary business operations. Among the subsidiaries eliminated was Ameren Energy, Inc., which previously served as a power marketing and risk management agent for UE. UE now performs such functions for itself. To further streamline its organizational structure, in February 2008, Development Company was eliminated through merger and Ameren Energy Resources Company was merged into the newly created Resources Company. As a part of this internal reorganization, on February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest in EEI were transferred to this newly created Resources Company.
The following table presents our total employees at December 31, 2007:
(a)
Total for Ameren includes Ameren registrant and nonregistrant subsidiaries.
The IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 61% of Ameren’s total employees. They represent 72% of the employees at UE, 81% at CIPS, 72% at Genco, 70% at CILCORP, 70% at CILCO, and 90% at IP. All collective bargaining agreements that expired in 2007 have been renegotiated and ratified, with the exception of the benefits provisions contained in the agreements between IP and IBEW locals 51, 309, 702, and 1306. Bargaining over these benefits provisions continues at this time, with existing provisions remaining in effect. The majority of the renegotiated agreements have four- or five-year terms, and expire in 2011 and 2012. Four collective bargaining agreements between IP and the Laborers and Gas Fitters labor unions, covering approximately 127 employees, expire June 30, 2008.
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
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 16 - Segment Information to our financial statements under Part II, Item 8, of this report for additional information on reporting segments.
RATES AND REGULATION
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 regulates UE, CIPS, Genco, CILCO, IP and EEI 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.
About 37% of Ameren’s electric and 13% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2007. About 41% of Ameren’s electric and 87% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2007. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.
Missouri Regulated
About 83% of UE’s electric and 100% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2007.
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. The ISRS permits prudently incurred gas infrastructure replacement costs to be passed directly to the consumer.
A 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 electric 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 that year. Rules for the environmental cost recovery mechanism were approved by the MoPSC in February 2008 and will be effective once published in the Missouri Register. UE will not be able to utilize the cost recovery mechanisms until the MoPSC authorizes them as part of a rate case proceeding. UE was denied use of a fuel and purchased power cost recovery mechanism in its last electric rate order, in May 2007. UE plans to request use of a fuel and purchased power cost recovery mechanism and, potentially an environmental cost recovery mechanism, in its next electric rate case filing, expected in the second quarter of 2008.
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 and for a natural gas delivery rate increase. In March 2007, a stipulation and agreement approved by the MoPSC authorized an increase in annual natural gas delivery revenues of $6 million effective April 1, 2007. As part of this stipulation and agreement, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement did not prevent UE from filing to recover gas infrastructure replacement costs through an ISRS during this three-year rate moratorium. In February 2008, the MoPSC approved UE’s petition requesting the establishment of an ISRS to recover annual revenues of $4 million effective March 29, 2008.
In May 2007, the MoPSC issued an order, which, as clarified, granted UE an increase in base rates for electric service, effective June 4, 2007. For further information on Missouri rate matters, including the Missouri law enabling fuel and purchased power and environmental cost recovery mechanisms, 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 2 - Rate and Regulatory Matters, and Note 13 - 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, 2007:
(a)
AERG’s revenues are not subject to ICC regulation.
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 allows 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 is recoverable by IP from a trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. At December 31, 2007, the trust fund balance was $22 million, including accumulated interest. 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 recoverable through charges assessed to customers under the tariff rider.
New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased on behalf of Ameren Illinois Utilities’ customers in the September 2006 power procurement auction in accordance with a January 2006 ICC order. 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 2 - Rate and Regulatory Matters, and Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information on rate matters. This material summarizes actions taken by certain Illinois legislators, the Illinois governor, the Illinois attorney general, and others regarding the expiration of the rate freeze at the beginning of 2007, opposition to the 2006 power procurement auction, and the Illinois electric settlement agreement and establishment of the IPA, as well as electric and gas delivery service rate cases filed by CIPS, CILCO and IP in November 2007.
General Regulatory Matters
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, AERG 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 intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. 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. On March 30, 2007, FERC granted a new 40-year license for UE’s Osage hydroelectric plant and approved a settlement agreement among UE, the U.S. Department of the Interior, and various state agencies that was submitted in May 2005 in support of the license renewal. The license for UE’s Taum Sauk plant expires on June 30, 2010. UE intends to file with FERC an application for license renewal of the Taum Sauk facility no later than June 30, 2008. The Taum Sauk plant is currently out of service and being rebuilt 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 2 - Rate and Regulatory Matters and Note 13 - 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 subject 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 NOx, 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 13 -
Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
SUPPLY FOR ELECTRIC POWER
Ameren operates an integrated transmission system that comprises the transmission assets of UE, CILCO, CIPS, and IP. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes CILCO, CIPS, IP, AERG and Genco). During 2007, the peak demand in AMMO was 8,606 MW and in AMIL was 9,386 MW. 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. The Ameren transmission system directly connects with 17 other balancing authority areas for the exchange of electric energy.
UE, CIPS, CILCO and IP are transmission-owning members of MISO, and they have transferred functional control of their systems to 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 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information. EEI operates its own balancing authority area and its own transmission facilities in southern Illinois. The EEI transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.
The Ameren Companies and EEI are members of SERC, a regional electric reliability organization with NERC-delegated authority for proposing and enforcing reliability standards. SERC is responsible for the bulk electric power supply system in much of the southeastern United States, including all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP.
Missouri Regulated
Factors that could cause UE 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.
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 these CT facilities to satisfy demand growth until 2018 to 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. See Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report. UE filed in February 2008 an integrated resource plan with the MoPSC. The plan includes proposals to pursue energy efficiency programs, expand the role of renewable energy sources in UE’s overall generation mix, increase operational efficiency at existing power plants, and possibly retire some generating units that are older and less efficient.
Illinois Regulated
As of January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who did not purchase electric supply from third-party suppliers through the Illinois reverse power procurement auction held in September 2006. CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including their affiliate, Marketing Company. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve their customers at an all-inclusive fixed price with one-third of the supply contracts expiring in each of May 2008, 2009 and 2010. New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007. The new rates reflected delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased on behalf of Ameren Illinois Utilities’ customers in the September 2006 reverse power procurement auction.
A portion of the electric power supply required for the Ameren Illinois Utilities to satisfy their distribution customers’ requirements is purchased from Marketing Company on behalf of Genco, AERG and EEI. As part of the Illinois electric settlement agreement reached in 2007, the reverse power procurement auction in Illinois was discontinued and will be replaced with a new process led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary power and energy requirements not already supplied through the September 2006 auction contracts, primarily through a request-for-proposal process, subject to ICC review and approval. Existing supply contracts from the September 2006 reverse power procurement auction remain in place. Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. See Note 2 - Rate and Regulatory Matters and Note 12 - 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
Factors that could cause Marketing Company to purchase power for the Non-rate-regulated Generation business segment include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, and extreme weather conditions.
In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into new power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and such amount of associated energy commencing on January 1, 2007. All of Genco’s and AERG’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 12 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information.
On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. EEI entered into a power supply agreement with Marketing Company whereby EEI sells 100% of its capacity and energy to Marketing Company at market-based prices. All of EEI’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 12 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information.
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Less than 1% of total fuel supply.
The following table presents the cost of fuels for electric generation for the years ended December 31, 2007, 2006 and 2005.
(a)
The fuel cost for coal represents the cost of coal, costs for transportation, which includes diesel fuel adders, and cost of emission allowances.
(b)
The fuel cost for natural gas represents the actual cost of natural gas and variable costs for transportation, storage, balancing, and fuel losses for delivery to the plant. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the generating facilities.
(c)
Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal.
Coal
UE, Genco, AERG and EEI have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2012. 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. Ameren burned 40.6 million (UE - 22.4 million, Genco - 10.1 million, AERG - 3.1 million, EEI - 5.0 million) tons of coal in 2007. See Part II, Item 7A - Quantitative and Qualitative Disclosures about Market Risk of this report for additional information about coal supply contracts.
About 94% of Ameren’s coal (UE - 97%, Genco - 88%, AERG - 92%, EEI - 100%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically 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, 2007, coal inventories for UE, Genco, AERG and EEI were adequate and in excess of historical levels, but below targeted levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
Nuclear
Fuel assemblies for the 2008 fall refueling at UE’s Callaway nuclear plant will begin manufacture during the second quarter of 2008. Enriched uranium for such assemblies is already at the facility. UE also has agreements or inventories to price-hedge 87% of Callaway’s 2010 and 2011 refueling requirements. There is no refueling scheduled in 2009 or 2012. UE expects to enter into additional contracts to purchase nuclear fuel. 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 May 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, Genco 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. They 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, 2007, UE had hedged about 25% of its required gas supply for generation in 2008 and Genco about 90%. As of December 31, 2007, EEI did not have any of its required gas supply for generation hedged for price risk.
NATURAL GAS SUPPLY FOR DISTRIBUTION
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 customers of UE, CIPS, CILCO and IP in Illinois and Missouri 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. Also see Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report, Note 1 - Summary of Significant Accounting Policies, Note 7 - Derivative Financial Instruments, Note 12 - Related Party Transactions, Note 13 - Commitments and Contingencies, and Note 14 - Callaway Nuclear Plant to our financial statements under Part II, Item 8.
INDUSTRY ISSUES
We are facing issues common to the electric and gas utility industry and the non-rate-regulated electric generation industry. These issues include:
•
political and regulatory resistance to higher rates;
•
the potential for changes in laws, regulation, and policies at the state and federal level, including those resulting from election cycles;
•
the potential for more intense competition in generation and supply;
•
the potential for reregulation in some states, which could cause electric distribution companies to build generation facilities and to purchase less power from electric generating companies like Genco, AERG and EEI;
•
changes in the structure of the industry as a result of changes in federal and state laws, including the formation of non-rate-regulated generating entities and RTOs;
•
fluctuations in power prices due to the balance of supply and demand and fuel prices;
•
the availability of fuel and increases in prices;
•
the availability of labor and material and rising costs;
•
regulatory lag;
•
negative free cash flows due to rising investments and the regulatory framework;
•
continually developing and complex environmental laws, regulations and issues, including new air-quality standards, mercury regulations, and increasingly likely greenhouse gas limitations;
•
public concern about the siting of new facilities;
•
construction of power generation and transmission facilities;
•
proposals for programs to encourage or mandate energy efficiency and renewable sources of power;
•
public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste;
•
uncertainty in the credit markets; and
•
consolidation of electric and gas companies.
We are monitoring these issues. Except as otherwise noted in this report, 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 2 - Rate and Regulatory Matters, and Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years.
AVAILABLE INFORMATION
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 and risk 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; policies and procedures with respect to related-person transactions; a code of ethics for principal executive officers 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.
ITEM 1A.
ITEM 1A. RISK FACTORS
The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions, which are largely outside of our control. Any such events that prevent UE, CIPS, CILCO or IP from recovering their respective costs or from earning appropriate returns on their investments could have a material adverse effect on future results of operations, financial position, or liquidity.
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, and 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 results of operations, financial position, or liquidity.
Our electric and gas utility rates are typically established in a regulatory proceeding that takes up to 11 months to complete. Rates established in those proceedings are primarily based on historical costs and include an allowed return on our investments by the regulator.
Our company, and the industry as a whole, is going through a period of rising costs, including increases in fuel, purchased power, labor and material costs, coupled with significant increases in capital, operation and maintenance and financing costs targeted at enhanced distribution system reliability and environmental compliance. Due to rising costs and the fact that our rates are primarily based on historical costs, UE, CIPS, CILCO and IP are not earning the allowed return established by their regulators (often referred to as regulatory lag). As a result, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases and
requests for cost recovery mechanisms will be necessary. A period of increasing rates to our customers could result in additional regulatory, legislative, political, economic and competitive pressures that could have a material adverse effect on our results of operations, financial position, or liquidity.
Illinois
Pending Delivery Service Rate Cases
Due to inadequate recovery of costs and low returns on equity experienced in 2007 and expected in 2008, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million, and IP - $139 million). In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The ICC has until the end of September 2008 to render a decision in these rate cases. It could materially reduce the amount of the increase requested, or even reduce rates.
Illinois Electric Settlement Agreement
Due to the magnitude of rate increases that went into effect following the end of a rate freeze on January 2, 2007 under the Illinois Customer Choice Law, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP at the level in effect prior to January 2, 2007, or would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. The rate rollback and freeze legislation would have prevented the Ameren Illinois Utilities from recovering from retail customers substantial portions of the cost of electric energy that the Ameren Illinois Utilities are obligated to purchase under wholesale contracts, and would also have caused the Ameren Illinois Utilities to under-recover their delivery service costs until the ICC could approve higher delivery service rates.
In order to address these concerns, the Illinois electric settlement agreement was reached in 2007. Ameren, on behalf of Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon, on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings, Inc., Midwest Generation, LLC, and MidAmerican Energy Company agreed to contribute an aggregate of $1 billion over four years to fund both rate relief programs and a new power procurement agency, the IPA. Approximately $488 million of the funding is earmarked as rate relief for customers of the Ameren Illinois Utilities. The Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, which commenced in 2007, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. The Illinois electric settlement agreement provides that if legislation freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on generation of electricity is enacted before August 1, 2011, then the remaining funding commitments will expire. Any funds set aside in support of those commitments will be refunded to the utilities and electric generators. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for additional information on the Illinois electric settlement agreement.
The following factors resulting from implementation of the Illinois electric settlement agreement could have a material adverse effect on the results of operations, financial position or liquidity of Ameren, the Ameren Illinois Utilities, Genco or AERG:
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uncertainty as to the implementation of the new power procurement process in Illinois for 2008 and 2009, including ICC review and approval requirements, the role of the IPA, timely procurement of power and recovery of costs from the Ameren Illinois Utilities’ customers, and the ability of the Ameren Illinois Utilities or other electric distribution companies to lease or invest in generation facilities;
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the extent to which the IPA may exercise its statutory authority to build or invest in generation facilities;
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the increase in short-term or long-term borrowings by the Ameren Illinois Utilities, Genco and AERG to fund contributions under the Illinois electric settlement agreement or to pay for or collateralize their obligations under future power purchase agreements;
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the failure by the electric generators that are party to the settlement agreement to perform in a timely manner under their respective funding agreements, which permit the Ameren Illinois Utilities to seek reimbursement for a portion of the rate relief that will be provided to certain of their electric customers; and
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the extent to which Genco and AERG will be successful in making future sales to meet a portion of Illinois’ total electric demand through the revised power procurement mechanism.
If, notwithstanding the Illinois electric settlement agreement, any decision is made or any action occurs 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, and such decision or action is not promptly enjoined, it could result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP.
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 March 2007, a stipulation and agreement approved by the MoPSC authorized an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. As part of this stipulation and agreement, UE agreed not to file a natural gas delivery rate case before March 15,
2010. This agreement did not prevent UE from filing to recover infrastructure costs through an ISRS during this three-year rate moratorium. In February 2008, the MoPSC approved UE’s petition requesting the establishment of an ISRS to recover annual revenues of $1 million effective March 29, 2008.
In May 2007, the MoPSC issued an order authorizing a $43 million increase in UE’s base rates for electric service based on a return on equity of 10.2%. Certain aspects of the MoPSC decision have been appealed by UE, the Office of Public Counsel and the Missouri attorney general to the Court of Appeals for the Western District of Missouri. In its order, the MoPSC denied UE the use of a fuel and purchased power cost recovery mechanism. UE expects to incur significant increases in fuel and related transportation costs over the next three years. Without a rate recovery mechanism, UE may experience regulatory lag and not fully recover these costs.
Increased federal and state environmental regulation will cause UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and increased operating costs. Future limits on greenhouse gas emissions would likely require UE, Genco, CILCO (through AERG) and EEI to incur significant additional increases in capital expenditures and operating costs. Such expenses, if excessive, could result in the closures of coal-fired generating plants.
About 61% of Ameren’s (UE - 54%, Genco - 60%, AERG - 95%, EEI - 95%) generating capacity is coal-fired. About 84% (UE - 76%, Genco - 96%, AERG - 99%, EEI - 100%) of its electric generation was produced by its coal-fired plants in 2007. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. The EPA has issued final regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. These regulations require significant additional reductions in the emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009, and significant capital expenditures. Missouri has adopted rules that substantially follow the federal regulations.
Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, AERG, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. In 2009, Genco, AERG and EEI will begin putting into service equipment designed to reduce mercury emissions.
In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that effectively vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The Court’s decision is subject to appeal, and it is uncertain how the EPA will respond. At this time, we are unable to determine the impact that this action would have on our estimated expenditures for compliance with environmental rules, our results of operations, financial position, or liquidity.
Ameren’s estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air Mercury Rule and related state implementation plans range from $4 billion to $5 billion by 2017 (UE - $1.8 billion to $2.3 billion; Genco - $1.3 billion to $1.6 billion, AERG - $620 million to $760 million, EEI - $310 million to $410 million).
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. Ameren believes that currently proposed legislation can be classified as moderate to extreme depending upon proposed CO2 emission limits, the timing of implementation of those limits, and the method of allocating allowances. The moderate scenarios include provisions for a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. When consumed natural gas emits about half the amount of CO2 as coal. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also would affect the cost of nonelectric transportation, heating for our customers and many industrial processes. Under some policy scenarios being considered by Congress, Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly-situated electric power generators to close some coal-fired facilities. 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 power plants. We are currently in discussions with the EPA and the state of Illinois regarding these matters, but we are unable to predict the outcome of these discussions. Resolution of the matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, Genco, AERG and EEI. A resolution could result in increased capital expenditures, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would probably require the installation of emission control technology, some of which has already been planned for compliance with other regulatory requirements, such as the Clean Air Interstate Rule and the Illinois mercury emission rules.
New environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties and closure of power plants for UE, Genco, AERG and EEI. 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. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.
The construction of, and capital improvements to, UE’s, CIPS’, CILCO’s and IP’s electric and gas utility infrastructure as well as to Genco’s, CILCO’s (through AERG) and EEI’s non-rate-regulated power generation facilities involve substantial risks, particularly as the Ameren Companies expect to incur significant capital expenditures over the next five years and beyond for compliance with environmental regulations and to make significant investments in our utility infrastructure to improve overall system reliability. Should construction or capital improvement efforts be unsuccessful, it could have a material adverse impact on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.
The Ameren Companies will incur significant capital expenditures over the next five years for compliance with environmental regulations and to make significant investments in their electric and gas utility infrastructure and their non-rate-regulated power generation facilities. The Ameren Companies estimate that they will incur up to $10.6 billion (UE - up to $4.9 billion; CIPS - up to $505 million; Genco - up to $2.1 billion; CILCO (Illinois Regulated) - up to $425 million; CILCO (AERG) - up to $870 million; IP - up to $1.1 billion; EEI - up to $555 million, Other - up to $205 million) of capital expenditures during the period from 2008 through 2012, including construction expenditures, capitalized interest and allowance for funds used during construction (except for Genco, which has no allowance for funds used during construction), and estimated expenditures for compliance with EPA and state regulations regarding SO2 and NOx emissions and mercury emissions from coal-fired power plants. Costs for these types of projects continue to escalate.
Investment in Ameren’s regulated operations is expected to be recoverable from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased costs generally for generators.
The ability of the Ameren Companies to successfully complete those facilities currently under construction, and those projects yet to begin construction within established estimates is contingent upon many variables and are subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, and other events beyond our control may occur that may materially affect the schedule, cost and performance of these projects. With respect to capital expenditures related to the installation of pollution control equipment, there is a risk that such electric generating plants would not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such construction efforts be unsuccessful, the Ameren Companies could be subject to additional costs and the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase additional electricity or gas to supply its customers until the projects are completed. All of these risks may have a material adverse effect on the Ameren Companies’ results of operations, financial position or liquidity.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to various arrangements 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.
Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries because of transactions involving energy, coal, or other commodities and services and because of hedging transactions. If one Ameren entity failed to perform under any of these arrangements, other Ameren entities might incur losses. Their results of operations, financial position or liquidity could be adversely affected, resulting in such nondefaulting Ameren entity being unable to meet its obligations to unrelated third parties. Hedging activities are generally undertaken with a view
to the Ameren-wide exposures. Some Ameren Companies may therefore be more or less hedged than if they were to engage in such hedging alone.
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. In May 2007, the MoPSC issued an electric rate order that allows UE to recover through customer rates pension expense incurred under GAAP. Ameren expects to fund its pension plans at a level equal to the pension expense. Based on Ameren’s assumptions at December 31, 2007, and reflecting this pension funding policy, Ameren expects to make annual contributions of $40 million to $65 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 65%, 8%, 11%, 5%, and 11%, respectively. 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, efficiency levels, operating costs, and investment levels. Among these risks are:
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increased prices for fuel and fuel transportation;
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facility shutdowns due to operator error or a failure of equipment or processes;
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longer-than-anticipated maintenance outages;
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disruptions in the delivery of fuel and lack of adequate inventories;
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lack of water for cooling plant operations;
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labor disputes;
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inability to comply with regulatory or permit requirements;
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disruptions in the delivery of electricity;
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increased capital expenditure requirements, including those due to environmental regulation;
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unusual or adverse weather conditions, including drought; and
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catastrophic events such as fires, explosions, floods, or other similar occurrences affecting electric generating facilities.
Even though agreements have been reached with state and federal authorities, 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.
In October 2006, FERC approved a stipulation and consent agreement between UE and FERC’s Office of Enforcement that resolves all issues arising from an investigation by FERC’s Office of Enforcement 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. In November 2007, UE entered into a settlement agreement with the state of Missouri represented by the Missouri attorney general, the Missouri Conservation Commission and the Missouri Department of Natural Resources. The agreement resolved the state of Missouri’s lawsuit and claims for damages and other relief related to the December 2005 Taum Sauk breach. A business owners’ suit, which was filed in the Missouri Circuit Court of Reynolds County and remains pending, seeks damages relating to business losses and lost profit and unspecified punitive damages.
In February 2007, UE submitted to FERC an environmental report to rebuild the upper reservoir at Taum Sauk. UE received approval from FERC in August 2007 and hired a contractor in November 2007. The estimated cost to rebuild the upper reservoir is in the range of $450 million. The Taum Sauk plant is expected to be out of service at least through the fall of 2009.
As part of the settlement agreement with the state of Missouri, UE agreed not to attempt to recover from ratepayers in any future rate increase any in-kind or monetary payments to the state parties required by the settlement agreement or any costs incurred in the rebuilding of the upper reservoir (expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that are currently not reasonably foreseeable, and costs that would have been incurred absent the December 2005 breach of the upper reservoir at the Taum Sauk plant).
If UE needs to purchase power because of the unavailability of the Taum Sauk facility during the rebuild of the upper reservoir, UE has committed to not seek these additional costs from ratepayers. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2008 pretax earnings by $15 million to $20 million. UE expects to face higher-cost sources of
power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs.
UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. Until litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
The Missouri Parks Association and the Missouri Coalition for the Environment initiated legal proceedings over FERC’s decision to authorize the rebuilding of the upper reservoir at Taum Sauk. They seek injunctive and other relief. If they obtain injunctive relief, it could delay the construction of the rebuild and could delay the return of the plant to service.
Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risks.
In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into new power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and such amount of associated energy commencing on January 1, 2007. All of Genco’s and AERG’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company.
On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. EEI entered into a power supply agreement with Marketing Company whereby EEI sells 100% of its capacity and energy to Marketing Company. All of EEI’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company.
To the extent that electricity generated by these facilities is not under a fixed-price 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:
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current and future delivered market prices for natural gas, fuel oil, and coal and related transportation costs;
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current and forward prices for the sale of electricity;
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the extent of additional supplies of electric energy from current competitors or new market entrants;
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the regulatory and pricing structures developed for evolving Midwest energy markets and the pace at which regional markets for energy and capacity develop outside of bilateral contracts;
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changes enacted by the Illinois legislature, the ICC, the IPA or other government agencies with respect to power procurement procedures;
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the potential for reregulation of generation in some states;
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future pricing for, and availability of, services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit our ability to sell energy in our markets;
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the growth rate in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs;
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climate conditions in the Midwest market; and
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environmental laws and regulations.
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 19% of UE’s 2007 generation. Therefore, UE is subject to the risks of nuclear generation, which include the following:
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potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
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the lack of a permanent waste storage site;
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limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE or other U.S. nuclear operations;
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uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate;
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increased public and governmental concerns over the adequacy of security at nuclear power plants;
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uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE’s facility operating license for the Callaway nuclear plant expires in 2024);
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limited availability of fuel supply; and
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costly and extended outages for scheduled or unscheduled maintenance.
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 the fall of 2008. 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 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. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any additional 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 procurement and pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings and cash flows.
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, 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 requirements related to future environmental compliance. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with near-term regulatory lag, we expect to need more short-term and long-term debt financing. 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, such as the recent collapse of the subprime mortgage market may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. Certain of the Ameren Companies rely in part on Ameren for access to capital. Circumstances that limit Ameren’s access to capital, including those relating to its other subsidiaries, could impair its ability to provide those Ameren Companies with needed capital. 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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.
ITEM 2. PROPERTIES.
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 5 - Long-term Debt and Equity Financings, and Note 13 - 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 2008 peak summer electrical demand:
(a)
“Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.
(b)
This facility is out of service. It is not operational because of a breach of its upper reservoir in December 2005. Its 2005 peak summer electrical demand net kilowatt capability was 440,000. For additional information on the Taum Sauk incident, see Note 13 - Commitments and Contingencies under Part II, Item 8 of this report.
(c)
This facility will be out of service in 2008.
(d)
There are economic development lease arrangements applicable to these CTs.
(e)
Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).
(f)
Ameren owns an 80% interest in EEI. See Part I, Item 1, Business and Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
(g)
There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).
(h)
These CTs are owned by Genco and were leased to Development Company prior to its elimination in an internal reorganization in February 2008. The operating lease was terminated in February 2008. Genco received rental payments under the lease in fixed monthly amounts that varied over the term of the lease and ranged from $0.8 million to $1.0 million.
(i)
Genco has granted the city of Columbia, Missouri, options to purchase an undivided ownership interest in these facilities, which would result in a sale of up to 72 megawatts (about 50%) of the facilities. Columbia can exercise one option for 36 megawatts at the end of 2010 for a purchase price of $15.5 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other option can be exercised for another 36 megawatts at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5 million, or at the end of 2023 for a purchase price of $4 million. A power purchase agreement pursuant to which Columbia is now purchasing up to 72 megawatts of capacity and energy generated by these facilities from Marketing Company will terminate if Columbia exercises the purchase options.
The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2007:
Our other properties include 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:
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A portion of UE’s Osage plant reservoir, certain facilities at UE’s Sioux plant, most of UE’s Peno Creek and Audrain CT facilities, Genco’s Columbia CT facility, AERG’s Indian Trails generating facility, Medina Valley’s generating facility, certain of Ameren’s substations, and most of our transmission and distribution lines and gas mains are situated on lands we occupy under leases, easements, franchises, licenses or permits.
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The United States or the state of Missouri may own or may have paramount rights to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which
certain of UE’s generating and other properties are located.
•
The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of UE’s Keokuk plant is located.
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 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. These plants 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 4 - Credit Facilities and Liquidity for details of the credit facilities.
UE has conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city through 2022. Under the terms of this capital lease, UE is responsible for all operation and maintenance responsibilities for the facility. Ownership of the facility will transfer to UE at the expiration of the lease, at which time the property and plant will 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.
See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for information on mechanics’ liens filed against CILCO’s Duck Creek plant.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
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 December 2007, Caterpillar Inc., in conjunction with other industrial customers as a coalition, intervened in the 2007 rate cases filed by CILCO and IP with the ICC to modify their electric and natural gas delivery service rates. 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.
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 2 - Rate and Regulatory Matters, and Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth quarter of 2007 with respect to any of the Ameren Companies.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2007, 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. All of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
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 April 27, 2007, Ameren submitted to the NYSE a certificate of its chief executive officer certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.
Ameren common shareholders of record totaled 74,419 on January 31, 2008. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2007 and 2006.
There is no trading market for the common stock of UE, CIPS, Genco, CILCORP, CILCO or IP. Ameren holds all outstanding common stock of UE, CIPS, CILCORP and IP; Resources Company holds all outstanding common stock of Genco; and CILCORP holds all outstanding common stock of CILCO.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries during 2007 and 2006:
(a)
CILCO paid dividends to CILCORP of $50 million in the quarterly period ended March 31, 2006, and $15 million in the quarterly period ended September 30, 2006.
On February 8, 2008, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 63.5 cents per share. The common share dividend is payable March 31, 2008, to stockholders of record on March 5, 2008.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see 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.
Purchases of Equity Securities
The following table presents Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:
(a)
Included in December were 1,000 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren Board of Directors’ compensation awards. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligations upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.
None of the other Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the period October 1 to December 31, 2007.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31, 2007. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI Index), which comprises most investor-owned electric utilities in the United States. The comparison assumes that $100 was invested on December 31, 2002, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
Ameren management cautions that the stock price performance shown in the graph above should not be considered indicative of potential future stock price performance.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
(a)
Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for CILCORP since the acquisition date of January 31, 2003; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
For the years ended December 31, 2005 and 2003, net income included income (loss) from cumulative effect of change in accounting principle of $(22) million and $18 million or ($(0.11) and $0.11 per share) for Ameren, $(16) million and $18 million for Genco, $(2) million and $4 million for CILCORP, $(2) million and $24 million for CILCO, and $- and $(2) million for IP.
(c)
Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent, Dynegy.
(d)
Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN 46R, “Variable Interest Entities.” See Note 1 - Summary of Significant Accounting Policies, Variable-interest Entities, to our financial statements under Part II, Item 8, of this report for further information.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Operations
In 2007, we accomplished some key objectives that we believe will bring significant long-term benefits to our customers and shareholders. In Illinois, the Ameren Illinois Utilities, Genco and AERG reached a comprehensive settlement that will help Ameren Illinois Utilities customers’ transition to higher electric rates and bring stability to the power procurement process. Rate rollback and freeze legislation in response to higher electric rates in Illinois, driven by deregulation of that market, would have had severe negative operational and financial consequences for Ameren, CIPS, CILCORP, CILCO and IP, as well as significantly impacted the Ameren Illinois Utilities’ ability to deliver reliable service to their customers. Major stakeholders involved with this issue, including the Illinois governor’s office, leaders of the House of Representatives and Senate in Illinois, and the Illinois attorney general’s office, agreed to the Illinois electric settlement agreement. As a result, the Illinois electric settlement agreement provides significantly greater levels of legislative, regulatory and legal certainty. It also enables a viable competitive power supply market to continue to develop in Illinois.
In late 2007, the Ameren Illinois Utilities requested to increase annual revenues for electric and gas delivery services by $247 million in the aggregate. The Ameren Illinois Utilities also requested ICC approval to implement rate adjustment mechanisms for bad debt expenses, certain electric infrastructure investments and the decoupling of natural gas revenues from sales volumes. The ICC has until the end of September 2008 to render a decision in these rate cases. UE also expects to file an electric rate increase request in Missouri in the second quarter of 2008 to mitigate higher cost and investment levels. Constructive outcomes for the rate cases in Illinois and Missouri are very important to UE and the Ameren Illinois Utilities. UE, CIPS, CILCO and IP need to recover their costs to continue investing in their energy infrastructure on a timely basis and provide their customers with safe and reliable service.
In Missouri, we were able to settle all state and federal issues associated with the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. UE has begun rebuilding the upper reservoir and expects the plant to be out of service until the fall of 2009, if not longer. The cost of the rebuild is expected to be in the range of $450 million. UE believes that substantially all damages and liabilities (but not fines and penalties) caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost or replacement power, up to $8 million annually, will be covered by insurance.
In February 2008, UE filed an integrated resource plan with the MoPSC. The integrated resource plan outlines support for energy efficiency measures to reduce demand growth, expand renewable generation and increase existing power plant efficiency. Some of UE’s coal-fired power plants are aging, and an analysis will be completed in 2009 to determine which units are likely candidates for retirement. The integrated resource plan concludes that a new baseload plant is expected to be required in our regulated Missouri operations in the 2018 to 2020 timeframe. For that reason, UE is preserving the option to develop additional nuclear generation, while researching clean coal and carbon sequestration technologies. UE expects to file in 2008 a
construction and operating license application with the NRC for a new unit at UE’s Callaway nuclear plant site. While this filing will not represent a final decision, it preserves the option to build a nuclear unit. UE will not proceed on any new baseload power plant unless construction costs are recoverable through rates in Missouri. In addition to considering a new unit at Callaway, UE also began the process in 2008 to extend through 2044 the existing unit license at Callaway, which currently expires in 2024.
In 2007, Ameren’s Non-rate-regulated Generation business segment continued to execute its plan for investing in its power plants to improve their future productivity, as well as to effectively market their generation, consistent with their risk management framework. Non-rate-regulated Generation has also begun significant work on some of its coal-fired plants to begin installing additional environmental controls.
Earnings
Ameren reported net income of $618 million, or $2.98 per share, for 2007 compared to net income of $547 million, or $2.66 per share, in 2006. Earnings in 2007 principally benefited from, among other things, higher-priced power sales contracts in Ameren’s Non-rate-regulated Generation business segment, the June 2007 implementation of a Missouri electric rate order and greater demand for electricity and natural gas caused by warmer summer and cooler winter weather than in 2006.
Ameren’s 2007 earnings were reduced by 21 cents per share for the net cost of the Illinois electric settlement agreement. Storm-related costs in 2006 reduced net income by 26 cents per share. The impact of storm restoration efforts was less in 2007, but still significant. Ameren’s 2007 earnings were reduced by 9 cents per share as a result of the cost of restoration efforts associated with a severe ice storm in January 2007. In addition, a FERC order retroactively adjusting prior years’ RTO costs reduced 2007 earnings by 6 cents per share. Other items that unfavorably impacted earnings were, among other things, higher fuel costs and bad debt expenses, lower emission allowance sales, increased expenditures to improve reliability in Ameren’s regulated business segments and higher depreciation and financing costs due to greater energy infrastructure investment. In addition, there were fewer sales of noncore properties in 2007.
Liquidity
Cash flows from operations of $1.1 billion in 2007 at Ameren, along with other funds, were used to pay dividends to common shareholders of $527 million and to fund capital expenditures of $1.4 billion. Financing activities in 2007 primarily consisted of refinancing debt and funding capital investment with borrowings under credit facilities.
Outlook
Over the next few years, we expect to make significant investments in our electric and gas infrastructure to improve the reliability of our distribution systems and to comply with environmental regulations. These investments are consistent with our customers’ and regulators’ expectations. We expect that earnings growth in our rate-regulated businesses will come from updating existing customer rates to better reflect these investments and the current levels of costs UE and the Ameren Illinois Utilities are experiencing. However, in the near-term, the returns experienced in 2007 and expected to be experienced in 2008 by UE and the Ameren Illinois Utilities are below levels allowed by the respective state utility commissions in their last rate cases. That is due to the fact that UE’s and the Ameren Illinois Utilities’ current rates are significantly below the cost and investment levels they are incurring in their businesses today. In a rising cost environment, earnings will be negatively impacted due to regulatory lag until appropriate levels of rate relief are granted. Our plan to address this shortfall and to achieve earnings growth is very straightforward: UE and the Ameren Illinois Utilities will file more frequent rate cases requesting moderate rate increases, as well as seek appropriate cost recovery mechanisms to mitigate regulatory lag.
In addition, we will continue to optimize Ameren’s Non-rate-regulated Generation’s assets, focusing on improving the output of these plants and related energy marketing. While we currently believe that rising costs, including fuel, depreciation and financing costs will largely offset these productivity gains, we believe our plants will be well positioned for earnings growth in the future should energy and capacity prices improve.
The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2008 and 2017 Ameren expects that certain Ameren Companies will be required to invest between $4 billion and $5 billion to retrofit their power plants with pollution control equipment. Costs for these types of projects continue to escalate. These investments will also result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 45% of this investment will be in Ameren’s regulated UE operations, and it is therefore expected to be recoverable from ratepayers.
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. Ameren believes that currently proposed legislation can be classified as moderate to extreme depending upon proposed CO2 emission limits, the timing of implementation of those limits, and the method of allocating allowances. We support public policy that will result in substantial reductions in CO2 emission. However, CO2 policy must take into account the profound economic implications of moving toward a carbon constrained economy. We believe any legislation should include the following principles in order to limit the negative impact on our customers, economy and company:
•
Recognition of the significant economic impact of greenhouse gas policies on consumers and businesses in regions now dependent on coal.
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Compliance timelines consistent with development of advanced technologies.
•
Provisions for significant research funding.
•
Provisions for an effective cap and trade program.
•
Allowances for greenhouse gas offsets, such as reforestation.
•
Removal of potential regulatory and financial barriers to improvement in existing infrastructure.
•
Broad-based CO2 regulation across all industries.
•
A national and global policy approach.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. The costs to comply with future legislation or regulations could be so expensive that Ameren and other similarly situated electric power generators may be forced to close some coal-fired facilities. 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 Ameren Companies will incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures not funded with operating cash flows are expected to be funded primarily with debt.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries 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, as discussed below. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for a detailed description of our principal subsidiaries.
•
UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, UE also operated those businesses in Illinois.
•
CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
•
Genco operates a non-rate-regulated electric generation business.
•
CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG) in Illinois.
•
IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are expressed in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding during the applicable year.
RESULTS OF OPERATIONS
Earnings Summary
Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently have a fuel and purchased power cost recovery mechanism in Missouri for our electric utility business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, for a discussion of pending and recently decided rate cases and the Illinois electric settlement agreement. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Ameren’s net income was $618 million ($2.98 per share) for 2007, $547 million ($2.66 per share) for 2006, and $606 million ($3.02 per share) for 2005. In 2005, Ameren’s net income included a net cumulative effect aftertax loss of $22 million (11 cents per share) associated with recording liabilities for conditional AROs as a result of our adoption of FIN 47, “Accounting for Conditional Asset Retirement Obligations.” The net cumulative effect aftertax
loss of adopting FIN 47 is presented below for the applicable registrant companies:
(a)
Includes amounts for EEI.
Ameren’s net income increased $71 million and earnings per share increased 32 cents in 2007 compared with 2006.
Compared with 2006 earnings, 2007 earnings were favorably affected by:
•
higher margins in the Non-rate-regulated Generation segment due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts;
•
favorable weather conditions (estimated at 14 cents per share);
•
the absence of costs in 2007 that were incurred in 2006 related to the reservoir breach at UE’s Taum Sauk plant (15 cents per share);
•
higher electric rates, lower depreciation expense, decreased income tax expense and $5 million in SO2 emission allowance sales in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (21 cents per share); and
•
decreased costs associated with outages caused by severe storms (17 cents per share).
Compared with 2006 earnings, 2007 earnings were negatively affected by:
•
electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities’ electric customers under the Illinois electric settlement agreement (21 cents per share) described in Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report;
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the combined effect of the elimination of the Ameren Illinois Utilities’ bundled tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts;
•
higher fuel and related transportation prices (31 cents per share);
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higher labor and employee benefit costs (18 cents per share);
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increased depreciation and amortization expense (13 cents per share);
•
higher financing costs (17 cents per share);
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a planned refueling and maintenance outage at UE’s Callaway nuclear plant net of an unplanned outage at Callaway in 2006 (9 cents per share);
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increases in distribution system reliability expenditures (15 cents per share);
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higher bad debt expenses (8 cents per share);
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lower emission allowance sales (16 cents per share); and
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reduced gains on the sale of noncore properties, including leveraged leases (15 cents per share).
The cents per share information presented above is based on average shares outstanding in 2006.
Ameren’s net income before cumulative effect of the adoption of FIN 47 decreased $81 million and earnings per share decreased 47 cents in 2006 compared with 2005.
Compared with 2005 earnings, 2006 earnings were negatively affected by:
•
costs and lost electric margins associated with outages caused by severe storms (26 cents per share);
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milder weather conditions (estimated at 17 cents per share);
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costs associated with the reservoir breach at UE’s Taum Sauk plant (20 cents per share);
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an unscheduled outage at UE’s Callaway nuclear plant (7 cents per share);
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higher depreciation expense (11 cents per share);
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increased taxes other than income taxes (8 cents per share);
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contributions made in association with the Illinois Customer Elect electric rate increase phase-in plan (5 cents per share);
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increased fuel and purchased power costs; and
•
higher financing costs.
An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2006 compared with 2005.
Compared with 2005, earnings in 2006 were favorably affected by:
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higher margins on interchange sales (33 cents per share);
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increased net gains on the sale of noncore properties, including leveraged leases, compared with 2005 (9 cents per share);
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the lack of a refueling and maintenance outage at UE’s Callaway nuclear plant in 2006 (18 cents per share);
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increased sales of emission allowances (5 cents per share); and
•
other factors including improved plant operations, lack of coal conservation efforts, industrial electric customers switching back to the Ameren Illinois Utilities, lower bad debt expenses, and organic growth.
The cents per share information presented above is based on average shares outstanding in 2005.
Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes earnings from a non-rate-regulated 40% interest in EEI.
(b)
Includes net income from non-rate-regulated operations and a 40% interest in EEI held by Development Company, corporate general and administrative expenses, gains on sales of noncore assets, and intercompany eliminations.
Below is a table of income statement components by segment for the years ended December 31, 2007, 2006 and 2005:
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2007, 2006, and 2005. We consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
The effect of storm-related outages increasing interchange revenues is included in the storm-related outages (estimate) line.
2007 versus
Ameren
Ameren’s electric margin increased by $296 million, or 9%, in 2007 compared with 2006. Factors contributing to an increase in Ameren’s electric margin were as follows:
•
More power sold by Non-rate-regulated Generation at market-based prices in 2007. These 2007 sales compared favorably with 2006 sales at below-market prices, pursuant to cost-based power supply agreements that expired on December 31, 2006.
•
Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, increased electric margin by $35 million.
•
UE’s electric rate increase, effective June 4, 2007, which increased electric margin by $29 million.
•
An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased power costs of $12 million associated with an agreement with Entergy Arkansas, Inc. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc.
•
A 67% increase in hydroelectric generation because of improved water levels, which allowed additional generation to be used for interchange sales and reduced utilization of higher priced energy sources, increased Ameren’s electric margin by $27 million.
•
Increased Non-rate-regulated Generation capacity sales of $11 million.
•
Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively impacted electric sales and resulted in a net reduction in overall electric margin of $9 million in 2006.
•
Insurance recoveries of $8 million related to power purchased to replace Taum Sauk generation. See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for more information.
Factors contributing to a decrease in electric margin for 2007 as compared with 2006 were as follows:
•
The combined effect on the Ameren Illinois Utilities’ of the elimination of bundled tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts.
•
A 14% increase in fuel prices.
•
Rate relief and customer assistance programs under the Illinois electric settlement agreement, which reduced electric margin by $73 million.
•
The loss of wholesale margins at Genco from power acquired through the JDA, which terminated in 2006.
•
Decreased emission allowance sales of $53 million, offset by lower emission allowance costs of $15 million.
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Purchased power costs that were $18 million higher for the year because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005.
•
Reduced plant availability. Ameren’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 86%, respectively, in 2007 compared with 80% and 88%, respectively, in 2006.
Ameren’s gas margin increased by $15 million, or 4%, in 2007. The primary causes of the increase were favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by an estimated $10 million, and the UE gas rate increase that went into effect in April 2007, which increased gas margin by $4 million.
Missouri Regulated
UE
UE’s electric margin increased $76 million, or 4%, in 2007 compared with 2006. The following items had a favorable impact on UE’s electric margin:
•
An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. The termination of the JDA allowed UE to sell its
excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased power costs of $12 million associated with an agreement with Entergy Arkansas, Inc. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for more information.
•
The electric rate increase that went into effect June 4, 2007, which increased electric margin by $29 million.
•
A 67% increase in hydroelectric generation because of improved water levels. This allowed additional generation to be used for interchange sales and reduced UE’s use of higher priced energy sources, which increased electric margin by $27 million.
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Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, which increased electric margin by $22 million.
•
Replacement power insurance recoveries of $20 million, including $8 million associated with Taum Sauk. See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for more information.
•
Increased transmission service revenues of $18 million due to the ancillary service agreement with CIPS, CILCO, and IP. See Note 12 - Related Party Transactions to our financial statements under Part II, Item 8, of this report, for more information.
•
Decreased fuel costs due to the lack of $4 million in fees levied by FERC in 2006 upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years.
•
Reduced severe storm-related outages in 2007 compared with 2006, which negatively impacted electric sales that year and resulted in a net reduction in overall electric margin of $7 million in 2006.
Items that had an unfavorable impact on electric margin in 2007 as compared with 2006 were as follows:
•
A 21% increase in fuel prices.
•
Decreased emission allowance sales of $29 million.
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MISO purchased power costs that were $11 million higher due to the March 2007 FERC order.
•
Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $20 million higher.
•
Reduced power plant availability because of planned maintenance activities. UE’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 81% and 89%, respectively, in 2007 compared with 84% and 90%, respectively, in 2006.
UE’s gas margin increased by $10 million, or 17%, in 2007 compared with 2006. The following items had a favorable impact on gas margins:
•
The UE gas rate increase effective in April 2007, which increased gas margin by $4 million.
•
Unrecoverable purchased gas costs totaling $4 million in 2006 that did not recur in 2007.
•
Favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by $2 million.
Illinois Regulated
Illinois Regulated’s electric margin decreased by $64 million, or 8%, and gas margin increased by $10 million, or 3%, in 2007 compared with 2006. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margin decreased by $12 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:
•
The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.
•
The Illinois electric settlement agreement, which reduced electric margin by $11 million.
•
MISO purchased power costs that increased $8 million because of the March 2007 FERC order.
The following items had a favorable impact on electric margin in 2007 as compared with 2006:
•
Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $19 million lower, partly because of customers switching to third party suppliers and the termination of the JDA agreement at the end of 2006.
•
Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively affected electric sales and resulted in a net reduction in overall electric margin of $3 million in 2006.
•
Favorable weather conditions, as evidenced by a 20% increase in cooling degree-days, which increased native load electric margin by $6 million.
CIPS’ gas margin was comparable in 2007 and 2006.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2007 compared with 2006:
CILCO’s (Illinois Regulated) electric margin decreased by $31 million, or 20%, in 2007 compared with 2006. The
following items had an unfavorable impact on electric margin:
•
The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.
•
The Illinois electric settlement agreement, which reduced electric margin by $7 million.
•
MISO purchased power costs that increased $4 million, because of the March 2007 FERC order.
The following items had a favorable impact on electric margin in 2007 compared with 2006:
•
Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $4 million lower, partly because of customers switching to third party suppliers.
•
Favorable weather conditions, as evidenced by an 18% increase in cooling degree-days, which increased native load electric margin by $2 million.
See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) electric margin in 2007 compared with 2006.
CILCO’s (Illinois Regulated) gas margin increased by $7 million, or 8%, in 2007 compared with 2006, primarily because of favorable weather conditions as evidenced by a 7% increase in heating degree-days, increased industrial sales, and higher transportation volumes.
IP
IP’s electric margin decreased by $21 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:
•
The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.
•
The Illinois electric settlement agreement, which reduced electric margin by $14 million.
•
MISO purchased power costs that increased $12 million, because of the March 2007 FERC order.
The following items had a favorable impact on electric margin in 2007 compared with 2006:
•
Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $13 million lower, partly because of customers switching to third party suppliers.
•
Favorable weather conditions, as evidenced by a 21% increase in cooling degree-days, which increased native load electric margin by $5 million.
•
Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively impacted electric sales and resulted in an estimated net reduction in overall electric margin of $2 million in 2006.
IP’s gas margin was comparable in 2007 and 2006.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $278 million, or 37%, in 2007 compared with 2006. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 74% and 81%, respectively, in 2007 compared with 74% and 84%, respectively, in 2006. See below for explanations of electric margin variances for the Non-rate regulated Generation segment.
Genco
Genco’s electric margin increased by $133 million, or 36%, in 2007 compared with 2006. The following items had a favorable impact on electric margin:
•
Selling power at market-based prices in 2007, compared with selling power at below-market prices in 2006, pursuant to a cost-based power supply agreement that expired on December 31, 2006.
•
Reduced purchased power costs due to the termination of the JDA.
•
Increased power plant availability, due to fewer planned outages in 2007, that reduced purchased power costs. Genco’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 75% and 86%, respectively, in 2007 compared with 66% and 82%, respectively, in 2006.
•
MISO - related revenues that were $12 million higher as a result of the March 2007 FERC order.
•
MISO purchased power costs that were $16 million lower.
•
A reduction of mark-to-market losses on fuel contracts of $6 million.
The following items had an unfavorable impact on electric margin in 2007 compared with 2006:
•
The loss of wholesale margins on sales of power acquired through the JDA, which terminated in 2006.
•
Costs of $30 million pursuant to the Illinois electric settlement agreement.
•
A 4% increase in fuel prices.
CILCO (AERG)
AERG’s electric margin increased by $96 million, or 87%, in 2007 compared with 2006. The following items had a favorable impact on electric margin:
•
Increased revenues due to selling power at market-based prices in 2007 compared with below-market prices in 2006, pursuant to a cost-based power supply agreement, that expired on December 31, 2006.
•
Reduced emission allowance costs of $11 million as more low-sulfur coal was burned in 2007.
•
MISO-related revenues that were $4 million higher as a result of the March 2007 FERC order.
•
MISO purchased power costs that were $7 million lower.
•
Replacement power insurance recoveries of $7 million due to plant maintenance.
The following items had an unfavorable impact on electric margin in 2007 compared with 2006:
•
Costs of $13 million pursuant to the Illinois electric settlement agreement.
•
Reduced plant availability because of an extended plant outage. AERG’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 55% and 61%, respectively, in 2007 compared with 69% and 81%, respectively, in 2006.
•
A 5% increase in fuel prices.
EEI
EEI’s electric margin decreased by $8 million, or 3%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:
•
The lack of emissions allowance sales in 2007, which increased 2006 electric margin by $30 million.
•
A 5% increase in fuel prices.
•
Reduced plant availability related to increased unit outages. EEI’s baseload coal-fired generating plant’s average capacity and equivalent availability factors were each approximately 92% in 2007 compared with 95% in 2006.
The decrease in margin was offset by a 12% increase in market prices at EEI in 2007.
2006 versus
Ameren
Ameren’s electric margin increased by $41 million, or 1%, in 2006 compared with 2005. Factors contributing to an increase in Ameren’s electric margin were as follows:
•
A $162 million, or 67%, increase in margin on interchange sales. The expiration of EEI’s affiliate cost-based power supply contract on December 31, 2005, the expiration of several large Marketing Company power supply contracts in 2006, and an increase in plant availability provided Ameren with additional power to sell in the spot market. The increase in margin on interchange sales from these items was reduced by lower power prices, resulting from declining market prices for natural gas, and the significant impact of hurricanes and coal delivery disruptions on prices in 2005.
•
Plant efficiencies, primarily at CILCO (AERG), as Ameren’s baseload electric generating plants’ average capacity and equivalent availability factors were approximately 80% and 88%, respectively, in 2006 compared with 76% and 86%, respectively, in 2005.
•
The lack of a UE Callaway nuclear plant refueling and maintenance outage in 2006, which resulted in an increased electric margin of $25 million.
•
Capacity upgrades performed during the refueling and maintenance outage in 2005, which increased Callaway’s output and electric margin by $22 million.
•
Organic growth and the movement of industrial customers back to below-market Illinois tariff rates because of the expiration of power contracts with suppliers.
•
Lower purchased power costs at IP.
•
Sales to Noranda, which began receiving power on June 1, 2005, resulting in increased electric margin of $20 million at UE.
•
Increased sales of emission allowances, totaling $17 million, and lower emission allowance costs, totaling $11 million, in 2006 compared with 2005.
Factors contributing to a decrease in Ameren’s electric margin were as follows:
•
Unfavorable weather conditions, as evidenced by a 9% decline in cooling degree-days, which reduced the native load electric margin by $33 million in 2006 compared with 2005.
•
Severe storm-related outages in 2006, which reduced overall electric margin by $9 million as less electricity was sold for native load. This was partially offset by an increase in margin on the sales of this power on the interchange market.
•
An increase in fuel and purchased power costs for native load at UE and Genco due to the expiration of a cost-based power supply contract with EEI.
•
A 12% increase in coal and transportation prices.
•
A $25 million reduction in margin because of the unavailability of UE’s Taum Sauk hydroelectric plant in 2006 compared with 2005.
•
An $11 million reduction in native load margin from UE’s other hydroelectric generation in 2006 compared with 2005.
•
An unscheduled outage in 2006 at UE’s Callaway nuclear plant, which reduced electric margin by an estimated $20 million.
•
Reduced transmission service revenues, primarily due to the elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
Ameren’s gas margin decreased by $24 million, or 6%, in 2006 compared with 2005, primarily because of the following factors:
•
Unfavorable weather conditions, as evidenced by a 9% decrease in heating degree-days, which reduced the gas margin by $15 million in 2006 from 2005. Weather-sensitive residential and commercial gas sales volumes decreased by 8% each, in 2006 compared with 2005.
•
Unrecoverable purchased gas costs, together with unfavorable customer sales mix, totaling $19 million.
Factors contributing to an increase in Ameren’s gas margin were as follows:
•
An IP rate increase effective in May 2005, which added revenues of $6 million in 2006.
•
Increased sales to customers, excluding the impact from weather, of 2%, or $4 million.
Missouri Regulated
UE
UE’s total electric margin increased by $21 million in 2006 compared with 2005. UE’s Missouri Regulated electric margin increased by $9 million in 2006 compared with 2005. The following items had a favorable impact on UE’s electric margin:
•
Sales to Noranda that increased electric margin by $20 million and other organic growth.
•
Increased sales of emission allowances, totaling $30 million.
•
The lack of a scheduled Callaway nuclear plant refueling and maintenance outage in 2006.
•
Capacity upgrades at the Callaway plant performed during the refueling and maintenance outage in 2005.
UE’s other electric margin increased by $12 million as a result of the adoption of Staff Accounting Bulletin 108. See Note 1 - Summary of Significant Accounting Policies, Accounting Changes and Other Matters, to our financial statements under Part II, Item 8, of this report, for further information.
Items that had an unfavorable impact on electric margin in 2006 as compared to 2005 were as follows:
•
Unfavorable weather conditions, which reduced native load electric margin by $11 million, as evidenced by an 8% decline in cooling degree-days in 2006 compared with 2005.
•
Severe storm-related outages in 2006, which reduced electric native load sales and resulted in an estimated net reduction in electric margin of $7 million.
•
Lower margin on nonaffiliated interchange sales in 2006 compared with 2005, which resulted from reduced power prices. The average realized power prices on UE’s interchange sales decreased from $48 per megawatt hour in 2005 to $37 per megawatt hour in 2006. However, the margin on interchange sales benefited from the January 10, 2006, amendment of the JDA. The MoPSC-required and FERC-approved change in the JDA methodology (to basing the allocation of third-party short-term power sales of excess generation on generation output instead of load requirements) resulted in $23 million in incremental margin on interchange sales for UE in 2006 compared with 2005.
•
The transfer of UE’s Illinois service territory in May 2005 to CIPS, which decreased electric margin by an estimated $22 million in 2006 compared with 2005.
•
A 9% increase in coal and related transportation prices.
•
Fees of $4 million levied by FERC in 2006 for prior years’ generation benefits provided to UE’s Osage hydroelectric plant.
•
The unavailability of UE’s Taum Sauk hydroelectric plant.
•
UE’s other hydroelectric generation was lower due to drought-like conditions across the central and southern portions of Missouri.
•
An unscheduled 20-day outage at UE’s Callaway nuclear plant in the second quarter of 2006, which reduced electric margin (maintenance expenses were covered under warranty).
•
MISO Day Two Energy Market costs, which were $6 million higher in 2006, as this market did not begin operating until the second quarter of 2005.
•
The expiration of a cost-based power supply contract with EEI on December 31, 2005.
•
Reduced transmission service revenues of $13 million, primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
UE’s gas margin decreased by $13 million, or 18%, in 2006 compared with 2005. The following items had an unfavorable impact on UE’s gas margin:
•
Mild winter weather conditions that reduced gas margin by $2 million, as evidenced by an 8% decrease in heating degree-days in 2006 compared with 2005.
•
The transfer of UE’s Illinois service territory in May 2005 to CIPS, which reduced gas margin by $4 million.
•
A reduction in gas sales to customers, excluding the impacts from weather.
•
Unrecoverable purchased gas costs totaling $4 million.
Illinois Regulated
Illinois Regulated’s electric margin decreased by $5 million, or 1%, and its gas margin decreased by $8 million, or 3%, in 2006 compared with 2005. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margin increased by $3 million, or 1%, in 2006 compared with 2005. The following items had a favorable impact on electric margin:
•
The transfer to CIPS of UE’s Illinois service territory in May 2005, which increased electric margin by $7 million.
•
Customers, (primarily industrial), who switched back to CIPS from Marketing Company in 2006 because tariff rates were below market rates for power.
•
A decrease in MISO Day Two Energy Market costs of $7 million.
•
Increased miscellaneous revenues of $2 million.
The following items had an unfavorable impact on electric margin in 2006 as compared to 2005:
•
Unfavorable weather conditions, as evidenced by a 9% decrease in cooling degree-days in 2006 compared with 2005, which reduced native load electric margin by $7 million.
•
Severe storm-related outages in 2006, which reduced electric sales and reduced the electric margin by $3 million.
•
Reduced transmission service revenues, primarily due to elimination of interim cost recovery mechanisms, and reduced revenues associated with the MISO Day Two Energy Market.
Due to the expiration of CIPS’ cost-based power supply agreement with EEI in December 2005, pursuant to which CIPS sold its entitlements under the agreement to Marketing Company, both interchange revenues and purchased power expenses decreased by $34 million in 2006 compared with 2005.
CIPS’ gas margin increased by $1 million, or 1%, in 2006, compared with 2005, primarily because the transfer to CIPS of UE’s Illinois service territory in May 2005 added $4 million to gas margin. CIPS’ increase in gas margin was reduced by mild winter weather, as evidenced by a 10% decrease in heating degree-days in 2006 compared with 2005, which reduced gas margin by $3 million.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2006 compared with 2005:
(a)
See Non-rate-regulated Generation under Results of Operations for a detailed explanation of CILCO’s (AERG) change in electric margin in 2006 compared with 2005.
CILCO’s Illinois Regulated electric margin increased by $7 million, or 5%, in 2006 compared with 2005. The following items had a favorable impact on electric margin:
•
Increased native load growth, primarily in the industrial sector.
•
Increased miscellaneous revenues totaling $2 million.
•
A decrease in MISO Day Two Energy Market costs totaling $2 million.
The following items had an unfavorable impact on electric margin in 2006 as compared to 2005:
•
Unfavorable weather conditions, as evidenced by an 18% decrease in cooling degree-days in 2006, which reduced native load electric margin by $7 million.
•
Reduced transmission service revenues, primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
CILCO’s (Illinois Regulated) gas margin decreased by $10 million, or 10%, in 2006 compared with 2005. The following items had an unfavorable impact on gas margin:
•
Mild winter weather conditions in CILCO’s service territory, as evidenced by a 7% decrease in heating degree-days in 2006, which reduced gas margin by $3 million.
•
Lower transportation volumes, together with unfavorable customer sales mix.
IP
IP’s electric margin decreased by $15 million, or 4%, in 2006 compared with 2005. The following items had an unfavorable impact on electric margin:
•
Unfavorable weather conditions, as evidenced by a 10% decrease in cooling degree-days in 2006, which reduced native load electric margin by $9 million.
•
Severe storm-related outages in 2006, which resulted in reduced electric sales, decreasing electric margin by $2 million.
•
Reduced transmission service revenues of $17 million, primarily due to the elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
The following items had a favorable impact on electric margin in 2006 compared with 2005:
•
A net increase in electric margin as a result of customers, (primarily industrial), who switched back to IP because tariff rates were below market rates for power. The increase in revenues more than offset an increase in purchased power costs.
•
Lower transmission expenses included in purchased power costs due, in part, to a $6 million favorable settlement of disputed ancillary charges with MISO.
•
Lower MISO Day Two Energy Market costs totaling $4 million.
•
Increased rental and miscellaneous revenues totaling $5 million.
IP’s gas margin increased by $1 million, or 1%, in 2006 compared with 2005. Factors contributing to an increase in IP’s gas margin were as follows:
•
A rate increase effective in May 2005 that added revenues of $6 million in 2006.
•
Organic growth, primarily in the industrial sector.
The increase in gas margin was reduced by mild winter weather conditions, as evidenced by a 9% decrease in heating degree-days in 2006 compared with 2005, which reduced gas margin by $7 million.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $53 million, or 8%, in 2006 compared with 2005. See below for explanations of electric margin variances for the Non-rate-regulated Generation segment.
Genco
Genco’s electric margin decreased by $103 million, or 22%, in 2006 compared with 2005. The following items had an unfavorable impact on electric margin:
•
A lower wholesale sales margin, as Genco purchased additional power at higher costs to supply Marketing Company after the expiration of the cost-based power supply contract between EEI and its affiliates on December 31, 2005.
•
Lower emission allowance sales, because of a $21 million gain at Genco in the third quarter of 2005, which resulted from the nonmonetary swap of certain earlier vintage-year SO2 emission allowances for later vintage-year allowances.
•
A 9% increase in coal and transportation prices.
•
A lower margin on interchange sales in 2006 compared with 2005, primarily because of lower power prices, and a $23 million reduction in 2006 due to the January 2006 amendment of the JDA among UE, Genco and CIPS discussed above. The average realized power prices on Genco’s interchange sales decreased from $47 per megawatthour in 2005 to $38 per megawatthour in 2006.
•
Higher MISO Day Two Energy Market costs, totaling $12 million in 2006 compared with 2005. The market did not begin operating until the second quarter of 2005.
Genco’s decrease in electric margin was reduced by increased sales to CIPS as a result of the May 2005 transfer of UE’s Illinois service territory to CIPS.
CILCO (AERG)
AERG’s electric margin increased by $22 million, or 25%, in 2006 compared with 2005. The following items had a favorable impact on electric margin:
•
Lower purchased power costs due to improved power plant availability.
•
A decrease in emission allowance utilization expenses of $8 million in 2006.
•
An increase in margin on interchange sales due to improved plant availability. AERG’s electric generating plants’ average capacity and equivalent availability factors were approximately 69% and 81%, respectively, in 2006 compared with 61% and 73%, respectively, in 2005.
AERG’s electric margin was reduced by a 31% increase in coal and transportation prices in 2006 over 2005.
EEI
EEI’s electric margin increased by $194 million in 2006 compared with 2005. The following items had a favorable impact on electric margin:
•
An increase in margin on interchange sales, which resulted from the expiration of an affiliate cost-based power supply agreement on December 31, 2005, and its replacement with an affiliate market-based power supply agreement.
•
Sales of emission allowances.
Other Operations and Maintenance Expenses
2007 versus
Ameren
Ameren’s other operations and maintenance expenses increased $132 million in 2007 compared with 2006. Maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007 added $35 million. Distribution system reliability expenditures increased $49 million and employee benefits and non-Callaway labor costs were higher by $55 million in 2007 compared with 2006. Bad debt expenses increased $25 million in 2007, primarily as a result of the transition to higher electric rates in Illinois. Increases in maintenance at coal-fired power plants and injuries and damages reserves also contributed to higher other operations and maintenance expenses in 2007. We recognized reduced gains on sales of noncore property in 2007 of $4 million as compared to gains of $16 million in 2006. Additionally, other operations and maintenance expenses in 2007 included a payment of $4.5 million made to the IPA as part of the Illinois electric settlement agreement.
Reducing the effect of these items was the reversal in 2007 of an accrual of $15 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. In 2006, we also recognized costs of $25 million related to the December 2005 Taum Sauk plant reservoir breach. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 exceeded the costs associated with an ice storm in January 2007 by $42 million, thereby reducing other operations and maintenance expenses in 2007 compared with 2006.
Variations in other operations and maintenance expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Other operations and maintenance expenses increased in 2007 compared with 2006. Maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in 2007 added $35 million to other operations and maintenance expenses compared with 2006. Higher distribution system reliability expenditures of $34 million, increased non-Callaway related labor costs of $22 million, and insurance premiums of $19 million for replacement power coverage paid to a risk insurance affiliate also increased other operations and maintenance expenses in 2007 compared with 2006. Reducing the effect of these items was the absence in 2007 of costs recorded in 2006 related to the Taum Sauk plant reservoir breach as discussed above. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 exceeded the costs associated with an ice storm in January 2007 by $13 million, thereby reducing other operations and maintenance expenses in 2007 compared with 2006.
Illinois Regulated
Other operations and maintenance expenses increased $15 million in the Illinois Regulated segment in 2007 compared with 2006.
CIPS
Other operations and maintenance expenses increased $11 million in 2007 compared with 2006, primarily because of increased bad debt expenses, higher distribution system reliability expenditures, and increased injuries and damages reserves. The reversal in 2007 of the Illinois Customer Elect electric rate increase phase-in plan accrual of $4 million established in 2006 reduced the effect of these increases. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 were comparable with the costs associated with an ice storm in January 2007.
CILCO (Illinois Regulated)
Other operations and maintenance expenses were comparable between 2007 and 2006, as an increase in bad debt expenses was offset by the reversal of the Illinois Customer Elect electric rate increase phase-in plan accrual of $3 million established in 2006. Costs associated with storms had a minimal impact on CILCO (Illinois Regulated) other operations and maintenance expenses each year.
IP
IP’s other operations and maintenance expenses were comparable between 2007 and 2006. Higher employee benefit costs increased other operations and maintenance expenses in 2007. Bad debt expenses increased $10 million in 2007, primarily as a result of the transition to higher electric rates in Illinois. Offsetting the effect of these items was the reversal in 2007 of the Illinois Customer Elect electric rate increase phase-in plan accrual of $8 million established in 2006 and a reduction of $24 million in storm repair costs between years.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $30 million in the Non-rate-regulated Generation segment in 2007 compared with 2006.
Genco
Genco’s other operations and maintenance expenses increased $10 million in 2007 compared with 2006, primarily because of higher labor costs, the IPA payment of $3 million, and insurance premiums for replacement power coverage paid to a risk insurance affiliate.
CILCORP (Parent Company only)
Other operations and maintenance expenses were comparable between 2007 and 2006. Increased employee benefit costs in 2007 were offset by the absence in 2007 of a write-off that occurred in 2006, of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.
CILCO (AERG)
Other operations and maintenance expenses increased $11 million in 2007 compared with 2006, primarily because of higher power plant maintenance costs due to plant outages and the IPA payment of $1.5 million.
EEI
Other operations and maintenance expenses increased $3 million in 2007 compared with 2006, primarily because of higher power plant maintenance costs.
2006 versus
Ameren
Ameren’s other operations and maintenance expenses increased $69 million in 2006 compared with 2005. We experienced the most damaging storms in the Ameren utilities’ history in our service territory during the summer of 2006, resulting in the loss of power to about 950,000 electric customers and expenses of $28 million. Severe ice storms in the fourth quarter of 2006 resulted in the loss of power to about 520,000 electric customers and expenses of $42 million. Additionally, other operations and maintenance expenses increased because of $25 million in costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant and $15 million of contributions to assist residential customers in association with the Illinois Customer Elect electric rate increase phase-in plan accepted by the ICC in December 2006. In addition, there were higher maintenance expenses at our coal-fired power plants due to the timing of maintenance outages, and an increase in legal fees for environmental issues and general litigation. The effect on other operations and maintenance expenses from transactions related to noncore properties, including the impairment of a Delta Air Lines, Inc. lease in 2005, was comparable between years.
Reducing the unfavorable impact of the above items were lower labor costs and a decrease in bad debt expense of $17 million in 2006. An anticipated increase in uncollectible accounts due to higher natural gas prices was mitigated by mild winter weather. In 2005, a Callaway nuclear plant refueling and maintenance outage resulted in other operations and maintenance expenses of $31 million; there was no refueling and maintenance outage in 2006.
Variations in other operations and maintenance expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2006 and 2005 are discussed below.
Missouri Regulated
UE
Other operations and maintenance expenses increased in 2006 over 2005, primarily because of storm repair
expenditures of $38 million, incremental costs associated with the Taum Sauk plant incident of $25 million, as noted above, and higher maintenance expenses at UE’s coal-fired power plants. Reducing the impact of these unfavorable items were decreased injury and damage expenses, decreased bad debt expenses, lower labor and employee benefit costs, and the lack of a scheduled Callaway refueling and maintenance outage in 2006, which resulted in other operations and maintenance expenses of $31 million in 2005. Additionally, other operations and maintenance expenses decreased $7 million in 2006 as a result of the transfer of UE’s Illinois service territory to CIPS in May 2005.
Illinois Regulated
Other operations and maintenance expenses increased $45 million in 2006 compared with 2005 in the Illinois Regulated segment, as detailed below.
CIPS
Other operations and maintenance expenses increased $13 million in 2006 over 2005, primarily because of storm repair expenditures of $6 million and the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in additional other operations and maintenance expenses of $7 million. Additionally, other operations and maintenance expenses increased because of contributions of $4 million associated with the Illinois Customer Elect electric rate increase phase-in plan in 2006. The negative impact of these items was reduced by lower bad debt expense.
CILCO (Illinois Regulated)
Other operations and maintenance expenses decreased $4 million in 2006 from 2005, primarily because of lower employee benefit costs and reduced bad debt expenses. Reducing the benefit of these items were $3 million of contributions associated with the Illinois Customer Elect electric rate increase phase-in plan and $5 million of storm repair and tree trimming expenditures in 2006.
IP
Other operations and maintenance expenses increased $46 million in 2006 over 2005, primarily because of storm repair expenditures of $24 million and contributions associated with the Illinois Customer Elect electric rate increase phase-in plan of $8 million in 2006, along with higher rental expenses, and higher injury and damage expenses. The negative effect of these items was reduced by lower labor costs and employee benefit costs.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $28 million in 2006 compared with 2005 in the Non-rate-regulated Generation segment, as detailed below.
Genco
Other operations and maintenance expenses increased $13 million in 2006 over 2005, primarily because of higher maintenance expenses resulting from more scheduled power plant maintenance outages in 2006.
CILCO (AERG)
Other operations and maintenance expenses were comparable between 2006 and 2005, as decreased maintenance costs were offset by increased legal and environmental expenses.
CILCORP (Parent Company only) & EEI
Other operations and maintenance expenses increased $8 million at CILCORP (Parent Company only) and $3 million at EEI in 2006 over 2005, primarily because of increased employee benefit costs.
Depreciation and Amortization
2007 versus
Ameren
Ameren’s depreciation and amortization expenses increased $20 million in 2007 over 2006. The increases were primarily because of amortization of a regulatory asset in 2007 at IP, as discussed below, and capital additions in 2006 and 2007. A decrease in depreciation expenses as a result of a MoPSC electric rate order somewhat mitigated that effect. The MoPSC order extended the lives of UE’s Callaway nuclear plant and coal-fired generation plant for purposes of calculating depreciation expense, beginning in June 2007.
Variations in depreciation and amortization expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Depreciation and amortization expenses in 2007 were comparable with 2006. Increased expenses associated with capital additions in 2006 and 2007 were offset by a reduction in depreciation as a result of the MoPSC electric rate order noted above.
Illinois Regulated
Depreciation and amortization expenses increased $25 million in the Illinois Regulated segment in 2007 compared with 2006.
CIPS & CILCO (Illinois Regulated)
Depreciation and amortization expenses were comparable between 2007 and 2006.
IP
Depreciation and amortization expenses, including amortization of regulatory assets on IP’s statement of income, increased $19 million in 2007 compared with 2006, primarily because of the start of amortization in 2007 of a regulatory asset associated with acquisition integration costs, as required by an ICC order, and capital additions.
Non-rate-regulated Generation
Depreciation and amortization expenses were comparable between 2007 and 2006 in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company only), CILCO (AERG) and EEI.
2006 versus
Ameren
Ameren’s depreciation and amortization expenses increased $29 million in 2006 over 2005, primarily because of capital additions.
Variations in depreciation and amortization expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2006 and 2005 were as follows.
Missouri Regulated
UE
Depreciation and amortization expenses increased $25 million in 2006 over 2005. The increases were primarily because of capital additions, which included new steam generators and turbine rotors installed during the refueling and maintenance outage at the Callaway nuclear plant in 2005, as well as CTs purchased in the first quarter of 2006. Additionally, depreciation increased because CTs were transferred to UE from Genco in May 2005. Reducing depreciation expense was the property transfer to CIPS as part of the Illinois service territory transfer in May 2005.
Illinois Regulated
Depreciation and amortization expenses were comparable in the Illinois Regulated segment, CILCO (Illinois Regulated), and IP in 2006 and 2005. Depreciation and amortization expenses increased $3 million at CIPS primarily because of property transferred from UE to CIPS as part of the Illinois service territory transfer in May 2005.
Non-rate-regulated Generation
Depreciation and amortization expenses were comparable in 2006 and 2005 in the Non-rate-regulated Generation segment and for CILCORP (Parent Company only), Genco, CILCO (AERG), and EEI.
Taxes Other Than Income Taxes
2007 versus
Ameren
Ameren’s taxes other than income taxes decreased $10 million in 2007 compared with 2006, primarily because of lower gross receipts and property taxes.
Variations in taxes other than income taxes for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Taxes other than income taxes increased $4 million in 2007 over 2006, primarily because of increased gross receipts taxes.
Illinois Regulated
Taxes other than income taxes decreased $16 million in 2007 compared with 2006 in the Illinois Regulated segment. Taxes other than income taxes decreased $7 million at CIPS, $2 million at CILCO (Illinois Regulated), and $7 million at IP in 2007 compared with 2006, primarily as a result of reduced property taxes and excise taxes.
Non-rate-regulated Generation
Taxes other than income taxes were comparable between 2007 and 2006 for the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company only), CILCO (AERG), and EEI.
2006 versus
Ameren
Ameren’s taxes other than income taxes increased $26 million in 2006 over 2005, primarily as a result of higher gross receipts, and higher excise taxes and property taxes.
Variations in taxes other than income taxes for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2006 and 2005 were as follows.
Missouri Regulated
UE
Taxes other than income taxes were comparable in 2006 and 2005.
Illinois Regulated
In the Illinois Regulated segment, taxes other than income taxes increased $18 million in 2006 compared with 2005. Taxes other than income taxes increased $8 million at CIPS, $5 million at CILCO (Illinois Regulated), and $5 million at IP in 2006 over 2005, primarily as a result of higher property taxes and excise taxes.
Non-rate-regulated Generation
In the Non-rate-regulated Generation segment, taxes other than income taxes increased $7 million in 2006 compared with 2005, primarily because of higher property taxes at Genco. A court decision in the first quarter of 2005 favorably affected taxes that year. Taxes other than income taxes were comparable in 2006 and 2005 at CILCORP (Parent Company only), CILCO (AERG), and EEI.
Other Income and Expenses
2007 versus
Ameren
Miscellaneous income increased $27 million in 2007 compared with 2006, primarily because of increased interest and investment income. Cash balances were higher because of uncertainty regarding the ultimate resolution of legislative and regulatory issues in Illinois. Miscellaneous expense increased $6 million in 2007 compared with 2006, primarily because we made contributions to our charitable trust and because Illinois Regulated made contributions of $5 million for energy efficiency and customer assistance programs as part of the Illinois electric settlement agreement. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
Variations in other income and expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Other income and expenses were comparable in 2007 with 2006.
Illinois Regulated
Other income and expenses increased $6 million in the Illinois Regulated segment in 2007 compared with 2006, primarily because of increased interest income at IP. Other income and expenses were comparable between periods at CIPS and CILCO (Illinois Regulated).
Non-rate-regulated Generation
Other income and expenses were comparable between 2007 and 2006 for the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company only), CILCO (AERG), and EEI.
2006 versus
Ameren
Miscellaneous income increased $21 million in 2006 over 2005, primarily because of $24 million of interest income on a taxable industrial development revenue bond acquired by UE in conjunction with its purchase of a CT in the first quarter of 2006. This amount was offset by an equivalent amount of interest expense on Ameren’s and UE’s statements of income. Miscellaneous expense decreased $8 million, primarily because of decreased donations in 2006 and the write-off of unrecoverable natural gas costs in 2005.
Variations in other income and expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2006 and 2005 were as follows.
Missouri Regulated
UE
Miscellaneous income increased $16 million in 2006 over 2005, primarily as a result of interest income on a taxable industrial development revenue bond acquired by UE in conjunction with its purchase of a CT as noted above. This favorable impact was partially offset by lower capitalization of equity funds used during construction in 2006. In 2005, UE replaced steam generators and turbine rotors at the Callaway nuclear plant. Miscellaneous expense was comparable in 2006 and 2005.
Illinois Regulated
Other income and expenses were comparable for Illinois Regulated, CIPS, CILCO (Illinois Regulated), and IP in 2006 and 2005.
Non-rate-regulated Generation
Other income and expenses were comparable for Non-rate-regulated Generation, Genco, CILCORP (Parent Company only), CILCO (AERG), and EEI in 2006 and 2005.
Interest
2007 versus
Ameren
Interest expense increased $73 million in 2007 compared with 2006, primarily because of increased short-term borrowings, higher interest rates due to reduced credit ratings, and other items noted below. With the adoption of FIN 48 in 2007, we also began to record interest associated with uncertain tax positions as interest expense in 2007 rather than income tax expense. These interest charges were $10 million for 2007. Reducing the effect of the above unfavorable items were maturities of $350 million of long-term debt in the first half of 2007 at Ameren and redemptions/maturities at the Ameren Companies as noted below.
Variations in interest expense for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Interest expense increased $23 million in 2007 over 2006, primarily because of increased short-term borrowings, higher interest rates due to reduced credit ratings, and the issuance of $425 million of senior secured notes in June
2007. Interest expense recorded in conjunction with uncertain tax positions was $3 million in 2007.
Illinois Regulated
Interest expense increased $37 million in the Illinois Regulated segment and increased at CIPS and IP in 2007 compared with 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and the issuance of senior secured notes in 2007 and 2006. IP issued $250 million and $75 million of senior secured notes in November 2007 and June 2006, respectively. CIPS and CILCO (Illinois Regulated) issued $61 million and $96 million of senior secured notes, respectively, in June 2006. Reducing the effect of the above items was the maturity of $50 million of first mortgage bonds at CILCO (Illinois Regulated) in January 2007 and payments made on IP’s note payable to IP SPT in 2007 and 2006.
Non-rate-regulated Generation
Interest expense increased $4 million in the Non-rate-regulated Generation segment in 2007 compared with 2006.
CILCORP (Parent Company only) & CILCO (AERG)
Interest expense increased $3 million at CILCORP (Parent Company only) and $5 million at CILCO (AERG) in 2007 over 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
Genco
Interest expense decreased $5 million in 2007 compared with 2006, primarily because of reduced intercompany borrowings. Partially reducing this benefit was increased interest expense of $3 million recorded in conjunction with uncertain tax positions in 2007.
EEI
Interest expense was comparable in 2007 and 2006.
2006 versus
Ameren
Ameren’s interest expense increased $49 million in 2006 over 2005, primarily because of items noted below for the Ameren, CILCORP and CILCO business segments and for each of the Ameren Companies individually.
Missouri Regulated
UE
Interest expense increased $55 million in 2006 over 2005. UE issued $300 million of senior secured notes in July 2005 and $260 million of senior secured notes in December 2005. It also increased its short-term borrowings, partly in connection with the purchase of CTs in the first quarter of 2006. Interest expense of $24 million was recognized on UE’s capital lease associated with one of these CTs. This amount was offset by an equivalent amount of interest income on industrial revenue bonds in Ameren’s and UE’s statements of income.
Illinois Regulated
In the Illinois Regulated segment, interest expense increased $9 million in 2006 compared with 2005, primarily because of the issuance of $75 million of senior secured notes in June 2006 and increased money pool borrowings at IP. Interest expense at CIPS and CILCO (Illinois Regulated) was comparable in 2006 and 2005.
Non-rate-regulated Generation
In the Non-rate-regulated Generation segment, interest expense decreased $16 million in 2006 compared with 2005. Interest expense decreased $13 million at Genco resulting from the maturity of $225 million of its senior notes in 2005. Interest expense at CILCORP (Parent Company only), CILCO (AERG), and EEI was comparable in 2006 and 2005.
Income Taxes
2007 versus
Ameren
Ameren’s effective tax rate increased between 2007 and 2006.
Variations in effective tax rates for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
The effective tax rate decreased in 2007 from 2006, primarily because of the implementation of changes ordered by the MoPSC in UE’s 2007 electric rate order, which reduced the net amortization of property-related regulatory assets and liabilities in 2007 compared to 2006, decreases in reserves for uncertain tax positions in 2007 compared to increases in 2006, and increased production activity deductions in 2007 compared to 2006.
Illinois Regulated
The effective tax rate decreased in the Illinois Regulated segment in 2007 compared with 2006, because of the items detailed below.
CIPS
The effective tax rate increased, primarily because of higher reserves for uncertain tax positions in 2007 compared to 2006, unfavorable net amortization of property-related regulatory assets and liabilities in 2007 compared to favorable net amortization of property-related regulatory assets and liabilities in 2006, lower permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions, and other
miscellaneous items, offset by the increased impact of the amortization of investment tax credit, and other items on lower pretax book income.
CILCO (Illinois Regulated)
The effective tax rate decreased, primarily because of an increase in the permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions, along with favorable net amortization of the property-related regulatory assets and liabilities, and increased impact of the amortization of investment tax credit on lower pretax book income.
IP
The effective tax rate decreased, primarily because of favorable net amortization of property-related regulatory assets and liabilities in 2007 compared to unfavorable net amortization of property-related regulatory assets and liabilities in 2006.
Non-rate-regulated Generation
The effective tax rate increased in the Non-rate-regulated Generation segment in 2007 compared with 2006, because of items detailed below.
Genco
The effective tax rate increased, primarily because of lower decreases in reserves for uncertain tax positions in 2007 compared to 2006, and decreased production activity deductions in 2007 compared to 2006.
CILCO (AERG)
The effective tax rate increased in 2007, primarily because of higher reserves for uncertain tax positions in 2007 compared to 2006 and decreased impact of amortization of investment tax credit on higher pretax book income, offset by increased production activity deductions in 2007 compared to 2006, and differences between the book and tax treatment of the sales of noncore properties in 2006.
CILCORP (Parent Company only)
The effective tax rate decreased, primarily because of a change in the permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions.
EEI
The effective tax rate decreased, primarily because of increased production activity deductions.
2006 versus
Ameren
Ameren’s effective tax rate decreased in 2006 from 2005, primarily because of differences between the book and tax treatment of the sales of noncore properties, as well as the items discussed below.
Variations in effective tax rates for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2006 and 2005 were as follows.
Missouri Regulated
UE
The effective tax rate increased in 2006 over the prior year, primarily because of an increase in reserves for uncertain tax positions in 2006 compared to a decrease in 2005, and lower unfavorable net amortization of property-related regulatory assets and liabilities in 2006 compared to 2005.
Illinois Regulated
The effective tax rate decreased in 2006 from 2005 at Illinois Regulated, primarily because of the items detailed below.
CIPS
The effective tax rate decreased from the prior year, primarily because of favorable net amortization of property-related regulatory assets and liabilities and larger decreases in reserves for uncertain tax positions in 2006 compared to 2005, offset by lower permanent benefits for SFAS No. 106-2, as it relates to Medicare Part D provisions.
CILCO (Illinois Regulated)
The effective tax rate increased in 2006 over 2005, primarily because of lower permanent benefits related to company-owned life insurance and SFAS No. 106-2, as it relates to Medicare Part D provisions.
IP
The effective tax rate was comparable in 2006 and 2005.
Non-rate-regulated Generation
The effective tax rate decreased in 2006 compared with 2005 at Non-rate-regulated Generation, primarily because of the items detailed below.
Genco
The effective tax rate decreased in 2006 from 2005, primarily because of the resolution of uncertain tax positions in 2006 based on favorable developments with taxing authorities, and increased production activity deductions.
CILCO (AERG)
The effective tax rate decreased in 2006 from 2005, primarily because of the resolution of uncertain tax positions in 2006 based on favorable developments with taxing authorities compared to an increase in reserves for uncertain tax positions in 2005, as well as the difference between the book and tax treatment of the sales of noncore properties in 2006.
CILCORP (Parent Company only)
The effective tax rate decreased from the prior year, primarily because of a change in the permanent benefit of SFAS No. 106-2, as it relates to Medicare Part D provisions.
EEI
The effective tax rate was comparable in 2006 and 2005.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely principally on power sales to Marketing Company, which sold power to CIPS, CILCO and IP via the September 2006 Illinois power procurement auction and via financial contracts that were part of the Illinois electric settlement agreement. Marketing Company is also selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool or other short-term borrowings from affiliates or commercial paper to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at December 31, 2007, for Ameren, Genco, CILCORP, and CILCO. The Ameren Companies may reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies will incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures not funded with operating cash flows are expected to be funded primarily with debt. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a discussion of the Illinois electric settlement agreement, which among other things, will change the process for power procurement in Illinois and affect future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during 2007, and it will result in further credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for most of these refunds and credits from Illinois power generators, including Genco and AERG.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Cash Flows from Operating Activities
2007 versus
Ameren’s cash from operating activities decreased in 2007, as compared with 2006. This was primarily because of an increase in working capital investment as the collection of higher electric rates from Illinois electric customers lagged payments for power purchases, and past-due accounts increased because of the higher rates. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $88 million: $211 million of customer refunds, credits, and program funding, minus related reimbursements from nonaffiliated Illinois generators of $123 million. As of the end of 2007, $34 million was due from nonaffiliated generators. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a complete discussion of the Illinois electric settlement agreement. Other factors also reduced cash flow: increased interest payments as a result of lower credit ratings and increased debt. In addition, cash spent for fuel inventory increased because UE increased its inventory, and AERG experienced increased inventory as a result of an extended plant outage. Also reducing operating cash flows was a $25 million increase in pension and postretirement benefit contributions. In 2007, a $120 million decrease in income taxes paid (net of refunds) benefited cash flows from operations in 2007. Increases in electric and gas margins of $296 million and $15 million, respectively, also benefited operating cash flows, but were reduced by higher operations and maintenance expenses, as discussed in Results of Operations.
At UE, cash from operating activities decreased in 2007, compared with 2006, primarily because of an increase in accounts receivable caused by higher prices for interchange power sales, colder weather in December 2007 than in December 2006, and increased electric rates. Further reducing cash flows in 2007 was an increase in interest payments and other operations and maintenance expenditures, including $35 million for the Callaway nuclear plant refueling and maintenance outage. In addition, UE increased its fuel inventory. Compared with 2006, cash flows from operations in 2007 benefited from an increase in margin, as discussed in Results of Operations, a decrease in cash paid for Taum Sauk incident-related costs (net of insurance recoveries) of $60 million, and a decrease in income tax payments (net of refunds) of $86 million.
At CIPS, cash from operating activities decreased in 2007, compared with 2006. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $31 million, including $74 million of customer refunds, credits, and program funding, and related reimbursements from nonaffiliated Illinois generators of $43 million. As of the end of 2007, $13 million was due from nonaffiliated generators. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a complete discussion of the Illinois electric settlement agreement. Cash from operations was further reduced by a decrease in electric margins and higher expenses, as discussed in Results of Operations. In addition, there was an increase in working capital investment, as the collection of higher electric rates from customers lagged payments for power purchases, and past-due customer accounts increased because of higher rates. Income tax payments (net of refunds) decreased $44 million, benefiting cash flows from operations.
Genco’s cash from operating activities increased in 2007 compared with 2006, primarily because electric margins were up, as discussed in Results of Operations, and because cash spent for fuel inventory was down. In 2006, large cash outlays were made to replenish coal inventory after delivery disruptions caused by train derailments. Reducing these increases in cash from operating activities was an increase in income tax payments (net of refunds) of $27 million.
Cash from operating activities decreased for CILCORP and CILCO in 2007, compared with 2006. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $17 million: $41 million of customer refunds, credits, and program funding, minus related reimbursements from nonaffiliated Illinois generators of $24 million. As of the end of 2007, $7 million was due from nonaffiliated generators. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, past-due customer accounts increased due to higher rates, and inventory levels increased at AERG due to an extended plant outage. In addition, income tax payments (net of refunds) increased $16 million for CILCORP and $15 million for CILCO. Increased electric and gas margins, as discussed in Results of Operations, benefited cash flows from operating activities.
IP’s cash from operating activities decreased in 2007, compared with 2006. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $40 million: $96 million of customer refunds, credits, and program funding, minus related reimbursements from nonaffiliated Illinois generators of $56 million. As of the end of 2007, $14 million was due from nonaffiliated generators. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a complete discussion of the Illinois electric settlement agreement. Further reducing cash from operating activities compared to the prior year was a reduction in electric margins, as discussed in Results of Operations, and a $13 million increase in pension and postretirement benefit contributions. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past-due customer accounts increased because of higher rates. Income tax payments (net of refunds) increased by $15 million, further reducing cash flows from operations.
2006 versus
Ameren’s cash from operations increased in 2006, compared with 2005. As discussed in Results of Operations, electric margins increased by $41 million, while gas margins decreased by $24 million. Benefiting operating cash flows in 2006 was an $84 million decrease in pension and postretirement benefit contributions. IP also collected higher-than-normal trade receivables in 2006 because of the especially cold December 2005 weather during the winter heating season. The cash impact from trade receivables was more significant in 2006 because we had higher gas prices and colder December 2005 weather. Negative impacts on operating cash flow include a $216 million increase in income tax payments, expenditures of $59 million (including a $10 million FERC fine) associated with the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility in December 2005, and $37 million of other operations and maintenance expenses due to severe storms. Most of the Taum Sauk expenditures were pending recovery from insurance carriers at the end of 2006. In addition, there was an increase in cash used during 2006 for payment of 2005 costs, including $9 million for other operations and maintenance and $14 million for annual incentive compensation. These expenses were higher in 2006 than they were in 2005, because of increased 2005 earnings relative to performance targets. The cash benefit from reduced natural gas inventories as a result of lower prices was offset by increased volume of coal inventory purchases, because of the coal supply delivery issues experienced in 2005. See Note 13 - Commitments and Contingencies - Pumped-storage Hydroelectric Facility Breach to our financial statements under Part II, Item 8, of this report for more information regarding the Taum Sauk incident.
At UE, cash from operating activities increased in 2006. Overall margins were higher in 2006 than in 2005. Other operations and maintenance expenses were comparable with the previous year’s, despite $59 million (including $10 million for a FERC fine) spent due to the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility as discussed above for Ameren, and $24 million spent due to severe storms. Pension and postretirement benefit contributions were $61 million less than in the prior year. Income tax payments increased $51 million, and interest payments increased $40 million because of increased outstanding debt. Cash used for coal purchases increased in 2006 to alleviate the coal supply delivery issues experienced in 2005. Cash used for working capital increased, largely because of storm-related costs.
At CIPS, cash from operating activities decreased from the prior year. The negative cash effect of higher other operations and maintenance expenses was reduced by a small increase in electric and gas margins, as discussed in Results of Operations. Income tax payments increased $55 million in 2006 compared with 2005. Reducing this use of cash was a decrease in pension and postretirement benefit contributions of $11 million in 2006 compared with 2005, and an increase in collections of trade receivables as a result of colder December 2005 weather and higher gas prices than in the year-ago period.
Genco’s cash from operating activities in 2006 decreased compared with the 2005 period, primarily because of lower operating margins, as discussed in Results of Operations, and increases in coal inventory. Income tax payments decreased by $17 million in 2006, pension and postretirement benefit payments decreased $9 million, and interest payments were lower because there was less debt outstanding.
Cash from operating activities increased for CILCORP and CILCO in 2006 compared with 2005, primarily because of higher electric margins, as discussed in Results of Operations, and an increase in collections of trade receivables as a result of colder December 2005 weather and higher gas prices than in 2004. In addition, income tax payments decreased $25 million for CILCORP and $17 million for CILCO. An increase in coal deliveries at CILCO’s subsidiary, AERG, negatively affected cash.
IP’s cash from operations increased in 2006, compared with 2005. Benefiting 2006 cash flows were the collection of higher-than-normal trade receivables caused by cold December 2005 weather, as discussed above for Ameren, and a $1 million decrease in pension and postretirement benefit payments. These increases were reduced by lower electric margins and higher other operations and maintenance expenses, including $9 million related to severe storms, net income tax refunds of $13 million in 2006 compared with $22 million in 2005, and cash used in 2006 for payment of 2005 costs, as discussed above for Ameren, including an increase of $7 million in other operations and maintenance expenses, and an increase of $3 million in incentive compensation.
Pension Funding
Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. In May 2007, the MoPSC issued an electric rate order that allows UE to recover through customer rates the pension expense it incurred under GAAP. Consequently, Ameren expects to fund its pension plans at a level equal to the total pension expense. Based on Ameren’s assumptions at December 31, 2007, and reflecting this pension funding policy, Ameren expects to make annual voluntary contributions of $40 million to $65 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 65%, 8%, 11%, 5% and 11%, respectively. These amounts are estimates; the numbers may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. See Note 9 - Retirement Benefits to our financial statements under Part II, Item 8, of this report for additional information.
Cash Flows from Investing Activities
2007 versus
Ameren used more cash for investing activities in 2007 than in 2006. Net cash used for capital expenditures increased in 2007 as a result of power plant scrubber installation projects, other upgrades at various power plants, and reliability improvements of the transmission and distribution systems, but this increase was reduced by the absence in 2007 of CT acquisitions that occurred in 2006. The $43 million decrease in 2007 of proceeds from sales of noncore properties also increased net cash used in investing activities. An $18 million decrease in emission allowance purchases benefited cash flows from investing activities, while cash received in 2007 for emission allowance sales was $66 million less than in the prior year, because remaining allowances are expected to be retained for environmental compliance needs.
UE’s cash used in investing activities decreased in 2007, compared with 2006, principally because of the $292 million expended for CT purchases in 2006 that was not spent in 2007. Otherwise, capital expenditures increased $135 million because of storm repair costs, a power plant scrubber installation project, and other upgrades at various power plants. Other impacts on cash used in investing activities were the absence of sales of noncore properties in 2007 compared with a $13 million sale in 2006, and the 2006 receipt of $67 million in proceeds from an intercompany note related to the transfer of UE’s Illinois territory to CIPS. Additionally, nuclear fuel expenditures increased $29 million in 2007 over 2006 because of a refueling outage, and sales of emission allowances decreased $35 million because remaining allowances are being retained for environmental compliance needs.
CIPS’ cash used in investing activities decreased in 2007, compared with 2006. CIPS’ investing cash flow was positively affected by a $3 million increase in proceeds from
CIPS’ note receivable from Genco in 2007 compared with 2006 and the lack of a 2006 $17 million expenditure to repurchase its own outstanding bond. Capital expenditures were $3 million lower in 2007 than in 2006.
Genco had an increase in net cash used in investing activities for 2007, compared with 2006. This increase was due primarily to a $106 million increase in capital expenditures related to a scrubber project at one of its power plants and various other plant upgrades. Emission allowance purchases decreased by $6 million.
CILCORP’s and CILCO’s cash used in investing activities increased in 2007, compared with 2006. Cash flow used in investing activities increased as a result of a $135 million increase in capital expenditures, primarily due to a power plant scrubber project and other plant upgrades at AERG. The absence in 2007 of $11 million of proceeds received in 2006 from the sale of leveraged leases, and (for CILCORP only) the absence in 2007 of a 2006 note receivable payment from Resources Company in the amount of $71 million related to the 2005 transfer of leveraged leases from CILCORP to Resources Company, contributed to the increase in cash used in investing activities in 2007. The net year-over-year reduction of $84 million and $82 million in money pool advances for CILCO and CILCORP, respectively, and a $12 million reduction of emission allowance purchases benefited cash flows from investing activities in 2007.
IP’s net use of cash in investing activities for 2007 was comparable with 2006.
See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a further discussion of future environmental capital investment estimates.
2006 versus
Ameren’s increase in cash used in investing activities was primarily due to UE’s 2006 purchases of a 640-megawatt CT facility from affiliates of NRG Energy Inc. and 510-megawatt and 340-megawatt CT facilities from subsidiaries of Aquila Inc., for a total of $292 million; increased nuclear fuel expenditures of $22 million; and $96 million of capital expenditures during 2006 related to the severe storms. The CT purchases were intended to meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining the timing of future baseload generating capacity additions. Emission allowance purchases decreased $50 million in 2006 compared with 2005, while emission allowance sales increased $49 million. The sale of noncore properties in 2006 provided a $56 million benefit to Ameren’s cash from investing activities.
UE’s cash used in investing activities decreased in 2006, compared with 2005, principally because of a decrease in capital expenditures at the Callaway nuclear plant. This is due to UE spending $221 million for planned upgrades during a scheduled refueling outage in 2005. In addition, in 2006 UE received $67 million from CIPS as repayment of an intercompany note. The cash effect of the $292 million in CT purchases discussed above was more than the prior-year effect of the $237 million purchase of two CTs from Genco and the purchase of CT equipment from Development Company for $25 million. UE’s capital expenditures related to the 2006 severe storms were $47 million. In 2006, UE had a $13 million gain on the sale of a noncore property, and a $35 million increase in sales of emission allowances.
CIPS’ cash used in investing activities increased in 2006, compared with 2005. Capital expenditures increased $18 million. Also negatively affecting CIPS’ investing cash flow was an $18 million reduction in proceeds from CIPS’ note receivable from Genco in 2006. In addition, CIPS paid $17 million to repurchase its own outstanding bond. The bond remains outstanding, and CIPS is currently the holder and debtor. The increased capital expenditures resulted partly from CIPS’ expansion of its service territory because of its acquisition of UE’s Illinois utility operations in May 2005. In addition, $16 million was expended as a result of storms. CIPS’ remaining capital expenditures were for projects to improve the reliability of its electric and gas transmission and distribution systems.
Genco had a net use of cash in investing activities for 2006, compared with a net source of cash for 2005. This was due primarily to the 2005 sale of two CTs to UE for $241 million. Purchases of emission allowances were $45 million less in 2006 than in 2005. Capital expenditures increased $9 million for 2006 compared with 2005.
CILCORP’s cash used in investing activities decreased, and CILCO’s increased in 2006, compared with 2005. Capital expenditures increased $12 million for CILCORP and CILCO, and net money pool advances decreased for each company by $42 million. CILCORP’s cash from investing activities further benefited from the repayment of Resources Company’s note for $71 million, which originated from the 2005 transfer of leveraged leases from CILCORP to Resources Company. In addition, a subsidiary of CILCORP and CILCO generated cash from investing activities of $11 million in 2006, from the sale of its remaining leveraged lease investments. Emission allowance purchases were $9 million less in 2006 than in 2005.
IP had a net use of cash in investing activities for 2006, compared with a net source of cash for 2005, primarily because of the absence in 2006 of the 2005 repayments for advances made to the money pool in prior-periods. In addition, capital expenditures increased $47 million over the year-ago period, which included $27 million as a result of severe storms, and increased expenditures to maintain the reliability of IP’s electric and gas transmission and distribution systems.
Intercompany Transfer of Illinois Service Territory
On May 2, 2005, UE completed the transfer of its Illinois-based electric and natural gas service territory to CIPS, at a net book value of $133 million. UE transferred 50% of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount
of $67 million and 50% of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. The remaining principal balance of $61 million under the note was repaid in full by CIPS in June 2006.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2007, 2006, and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
Includes intercompany eliminations.
Ameren’s 2007 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $101 million toward a scrubber at one of its power plants, and incurred storm damage expenditures of $56 million. IP incurred storm damage-related expenditures of $24 million. At Genco and AERG there were cash outlays of $102 million and $76 million, respectively, for scrubber projects. The scrubbers are necessary to comply with environmental regulations. AERG also made expenditures for a boiler upgrade of $45 million. Other capital expenditures were principally to maintain, upgrade and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP as well as various plant upgrades.
Ameren’s 2006 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE purchased three CTs totaling $292 million. In addition, UE spent $40 million toward a scrubber at one of its power plants, and incurred storm damage expenditures of $47 million. CIPS and IP incurred storm damage-related expenditures of $16 million and $27 million, respectively. At Genco and AERG there was a cash outlay of $24 million and $11 million, respectively, for scrubber projects. Genco also made expenditures for a boiler upgrade of $16 million. Other capital expenditures were principally to maintain, upgrade and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP.
Ameren’s 2005 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE’s capital expenditures for 2005 principally consisted of $221 million for steam generators, low pressure rotor replacements, and other upgrades during the 2005 refueling and maintenance outage at its Callaway nuclear plant. UE also incurred expenditures of $65 million for three CTs at its Venice plant, $60 million for numerous projects at its generating plants, and $45 million for various upgrades to its transmission and distribution system. In addition, UE incurred expenditures of $237 million for CTs purchased from Genco, as discussed above. CILCORP’s and CILCO’s capital expenditures included $29 million for ongoing generation plant projects to improve flexibility in future fuel supply for power generation. In addition, CILCO, CIPS, and IP incurred expenditures to maintain, upgrade and expand the reliability of their electric and gas transmission and distribution systems.
The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2008 through 2012, including construction expenditures, capitalized interest and allowance for funds used during construction (except for Genco, which has no allowance for funds used during construction), and estimated expenditures for compliance with environmental standards:
(a)
Includes amounts for nonregistrant Ameren subsidiaries.
UE’s estimated capital expenditures include transmission, distribution and generation-related activities, as well as expenditures for compliance with new environmental regulations discussed below.
CIPS’, CILCO’s, and IP’s estimated capital expenditures are primarily for electric and gas transmission and distribution-related activities. Genco’s estimated capital expenditures are primarily for compliance with environmental regulations and upgrades to existing coal and gas-fired generating facilities. CILCO (AERG)’s estimate includes capital expenditures primarily for compliance with environmental regulations at AERG’s generating facilities, as well as generation-related activities.
We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.
Environmental Capital Expenditures
Ameren, UE, Genco, AERG and EEI will incur significant costs in future years to comply with EPA and state regulations regarding SO2 and NOx emissions (the Clean Air
Interstate Rule) and mercury emissions (the Clean Air Mercury Rule) from coal-fired power plants.
In May 2005, the EPA issued final regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule) from coal-fired power plants. The rules require significant reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. States have finalized rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule. Illinois has finalized rules to implement the federal Clean Air Interstate Rule program that will reduce the number of NOx allowances automatically allocated to Genco’s, AERG’s and EEI’s plants. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution control equipment. Current plans include the installation of scrubbers for SO2 reduction and selective catalytic reduction (SCR) systems for NOx reduction at certain coal-fired plants in Illinois.
Missouri rules, which substantially follow the federal regulations, became effective in April 2007. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. Current plans include the installation of scrubbers for SO2 reduction and co-benefit reduction of mercury and pollution control equipment designed to reduce mercury emissions at certain coal-fired plants in Missouri.
Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. In 2009, Genco, AERG and EEI will begin putting into service equipment designed to reduce mercury emissions.
In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that effectively vacated the federal Clean Air Mercury rule. The court ruled that the EPA erred in the method used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The Court’s decision is subject to appeal and it is uncertain how the EPA will respond. At this time, we are unable to determine the impact that this action would have on our estimated expenditures for compliance with environmental rules, our results of operations, financial position, or liquidity.
The table below presents estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air Mercury Rule through 2017 and related state implementation plans. The estimates described below could change, depending upon additional federal or state requirements, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with the proposed rules, thereby deferring capital investment.
(a)
UE’s expenditures are expected to be recoverable in rates over time.
Illinois and Missouri must also develop attainment plans to meet the federal eight-hour ozone ambient standard, the federal fine particulate ambient standard, and the Clean Air Visibility rule. Both states have filed ozone attainment plans for the St. Louis area. The state attainment plans for fine particulate matter must be submitted to the EPA by April 2008. The plans for the Clean Air Visibility rule were submitted in December 2007. The costs in the table above assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet these new standards in the St. Louis region. Should Missouri develop an alternative plan to comply with these standards, the cost impact could be material to UE, but we expect these costs to be recoverable from ratepayers. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for ozone and fine particulate matter. At this time, we are unable to determine the impact that state actions would have on our results of operations, financial position, or liquidity.
The impact that future initiatives related to greenhouse gas emissions and global warming may have on us is unknown and therefore not included in the estimated environmental expenditures. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, or liquidity.
See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a further discussion of environmental matters.
Cash Flows from Financing Activities
2007 versus
Ameren had an increase of $556 million in its net cash from financing activities in 2007, compared to 2006. Positive effects on cash included a net increase of $441 million in net short-term debt proceeds in 2007 over 2006, and a
$442 million increase in the issuance of long-term debt. These increased proceeds were used to fund a $324 million increase in redemptions, repurchases, and maturities of long-term debt and to fund the working capital needs of UE, CIPS, CILCO and IP.
UE had a net source of cash from financing activities in 2007, compared with a net use of cash in 2006. The primary reasons for the change include a $380 million capital contribution from Ameren and the issuance of $424 million of long-term debt in 2007. The proceeds were used to repay short-term debt and to fund working capital and capital expenditures. Other net uses of cash in 2007 included the repayment of a note Ameren issued in 2006 and an $18 million increase in dividend payments.
CIPS had a net source of cash from financing activities in 2007, compared with a net use of cash in 2006. This was primarily the result of an increase of $55 million in net short-term debt proceeds in 2007 over 2006, and a $10 million decrease in dividend payments. Cash was also positively affected in 2007 by a $20 million decrease in redemptions, repurchases, and maturities of long-term debt and the absence in 2007 of the 2006 payments of $67 million on an intercompany note with UE. Cash flows in 2006 benefited from $61 million in proceeds from long-term debt issuances that did not recur in 2007.
Genco had a net increase in cash used in financing activities for 2007 over 2006, principally because of a $125 million decrease in capital contributions received from Ameren. Cash benefited in 2007 by a $100 million increase in net proceeds from short-term debt.
CILCORP had a net source of cash from financing activities in 2007, compared with a net use of cash in 2006. CILCO’s cash provided by financing activities increased in 2007, compared with 2006. Net money pool repayments decreased $154 million at CILCORP and $161 million at CILCO. A net increase in short-term debt of $90 million at CILCORP and $15 million at CILCO in 2007 resulted in a positive effect on cash. In 2007, CILCORP and CILCO did not issue any dividends on common stock; in 2006 CILCORP issued $50 million and CILCO $65 million. As a result, cash flows from financing activities benefited in 2007 as compared to 2006. Additionally, in 2006 a note payable to Ameren was repaid, which resulted in a net use of cash of $113 million at CILCORP. Note payable repayments were only $71 million in 2007. These positive effects on cash were reduced by the lack of proceeds from the issuance of long-term debt in 2007 compared with $96 million at both CILCORP and CILCO in 2006.
IP had an increase in its net cash provided by financing activities in 2007 compared with 2006. This was primarily the result of an increase in proceeds from short-term debt and a $175 million increase from the issuance of long-term debt. The proceeds from the 2007 long-term debt issuance were used to repay borrowings under the Ameren utility money pool and under the 2007 credit facility. Other net uses of cash included $61 million of common stock dividends in 2007.
2006 versus
Ameren had a net source of cash from financing activities in 2006, compared with a net use of cash in 2005. Positive effects on cash included a net increase of $419 million in net short-term debt proceeds in 2006, compared with net repayments of $224 million of short-term debt in 2005, and a $454 million decrease in long-term debt redemptions, repurchases and maturities. Negative effects on cash included a $411 million reduction in long-term debt proceeds from the year-ago period, and a $358 million reduction in proceeds from the issuance of common stock. The reduction in common stock proceeds was due to the issuance of 7.4 million shares in the 2005 period related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units.
UE had a net use of cash for financing activities in 2006, compared with a net source of cash in 2005. The absence of long-term debt issuances in 2006, compared with $643 million of long-term debt issuances in 2005, was the primary reason for the change. This negative effect on cash flow was reduced by net changes in short-term debt that resulted in a $154 million positive effect on cash in 2006, compared with a $295 million negative effect on cash in 2005. In addition, dividend payments decreased $31 million in the 2006 period from 2005, and net money pool borrowings increased $79 million. Cash from financing activities in 2006 was used principally to fund CT acquisitions.
CIPS’ cash used in financing activities decreased in 2006, compared with 2005, principally because of the issuance of $61 million of long-term debt that was used with other available corporate funds to repay CIPS’ outstanding balance on the intercompany note payable to UE. That note was originally issued as 50% of the consideration for UE’s Illinois service territory, which was transferred to CIPS in 2005. Cash was also positively affected by a $64 million net decrease in money pool repayments and borrowings of $35 million under the 2006 $500 million credit facility in 2006. A $15 million increase in dividends to Ameren negatively affected CIPS’ cash from financing activities in 2006.
Genco had a net decrease in cash used in financing activities for 2006, compared with 2005, principally because of $200 million of capital contributions received in 2006 from Ameren. These capital contributions were made to reduce Genco’s money pool borrowings. In 2005, Genco used the $241 million from the sale of CTs to UE along with other funds to retire $225 million of maturing debt and to make principal payments on intercompany notes with CIPS and Ameren. Reducing these positive effects on cash was a $25 million increase in dividend payments in 2006.
CILCORP had a net use of cash in 2006, compared with a net source of cash in 2005. CILCO’s cash provided by financing activities decreased in 2006. Net money pool repayments increased $142 million at CILCORP and $145 million at CILCO. CILCORP’s net repayments of $113 million on its note payable to Ameren reduced its
financing cash flow by $227 million, because 2005 included net borrowings on this note that provided CILCORP with cash. Positive effects on cash flow included long-term debt issuances that generated $96 million in 2006, compared with no long-term debt issuances in 2005. The proceeds from this debt were used to redeem $21 million of long-term debt and to reduce money pool borrowings. In addition, CILCORP borrowed $215 million and CILCO (and CILCO’s subsidiary AERG) borrowed $165 million under the 2006 $500 million credit facility, net of repayments. In 2006, CILCORP used cash of $33 million for redemptions, repurchases and maturities of long-term debt, compared with $101 million in the 2005 period. CILCO’s cash used for redemptions, repurchases and maturities of long-term debt was comparable in the two years. These positive effects on cash in 2006 were partially offset by the absence in 2006 of a $102 million capital contribution received in 2005 from Ameren, which was made to reduce CILCO’s short-term debt. Also contributing to CILCORP’s and CILCO’s increase in cash used in financing activities for 2006 were increased common stock dividends of $20 million at CILCORP and $45 million at CILCO.
IP had a net source of cash from financing activities in 2006, compared with a net use of cash in 2005. This was partly because of lower redemptions and repurchases of long-term debt of $70 million in 2006. More debt was repaid in 2005 to improve IP’s credit profile. Other positive effects on cash from financing activities included the absence in 2006 of $76 million of common stock dividend payments made in 2005, net borrowings of $75 million on the 2006 $500 million credit facility, and the issuance of $75 million of long-term debt in 2006 compared with no long-term debt proceeds in 2005. The $75 million was used to reduce money pool borrowings.
Short-term Borrowings and Liquidity
Short-term borrowings typically consist of drawings under committed bank credit facilities and commercial paper issuances. See Note 4 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.
The following table presents the various committed bank credit facilities of the Ameren Companies and AERG, and their availability as of December 31, 2007:
(a)
Ameren Companies may access this credit facility through intercompany borrowing arrangements.
(b)
See Note 4 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for discussion of the amendment of this facility.
(c)
The maximum amount available to each borrower at December 31, 2007, including for issuance of letters of credit, was limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $75 million, IP - $150 million and AERG - $200 million. In July 2007, CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of December 31, 2007, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility. See Note 4 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for a discussion of this credit facility.
(d)
The maximum amount available to each borrower at December 31, 2007, including for the issuance of letters of credit, was limited as follows: CILCORP - $125 million, CILCO - $75 million, IP - $200 million and AERG - $100 million. CIPS and CILCO have the option of permanently reducing their ability to borrow under the 2006 $500 million credit facility and shifting such capacity, up to the same limits, to the 2007 $500 million credit facility. In July 2007, CILCO shifted $75 million of its sublimit under the 2006 $500 million credit facility to this facility.
Ameren can directly borrow under the $1.15 billion facility, as amended, up to the entire amount of the facility. UE can directly borrow under this facility up to $500 million on a 364-day basis. Genco can directly borrow under this facility up to $150 million on a 364-day basis. The amended facility will terminate on July 14, 2010, with respect to Ameren. The termination date for UE and Genco is July 10, 2008, subject to the annual 364-day renewal provisions of the facility. This facility was also available for use, subject to applicable regulatory short-term borrowing authorizations, by EEI or other Ameren non-state-regulated subsidiaries through direct short-term borrowings from Ameren and by most of Ameren’s non-rate-regulated subsidiaries, including, but not limited to, Ameren Services, Resources Company, Genco, AERG, Marketing Company and AFS, through a non-state-regulated subsidiary money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. In addition, a unilateral borrowing agreement among Ameren, IP, and Ameren Services enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding external short-
term borrowings by IP, may not exceed $500 million, pursuant to authorization from the ICC. IP is not currently borrowing under the unilateral borrowing agreement.
Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement.
In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At December 31, 2007, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had $355 million, $185 million, $26 million, $2 million, $6 million, $6 million and $6 million, respectively, of cash and cash equivalents.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2006, FERC issued an order authorizing these utility subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion, CIPS - $250 million, and CILCO - $250 million. The authorization was effective as of April 1, 2006, and terminates on March 31, 2008. An application for renewal of this authorization through March 31, 2010, is pending with FERC. IP has unlimited short-term debt authorization from FERC.
Genco is authorized by a March 2006 FERC order to have up to $300 million of short-term debt outstanding at any time. In the application to FERC for renewal authorization referred to above, Genco has requested to increase its short-term debt authorization to $500 million. AERG and EEI have unlimited short-term debt authorization from FERC.
The issuance of short-term unsecured debt securities by Ameren and CILCORP is not subject to approval by any regulatory body.
The Ameren Companies continually evaluate the adequacy and appropriateness of their credit arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.
Long-term Debt and Equity
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt and preferred stock (net of any issuance discounts and including any redemption premiums) for the years 2007, 2006 and 2005 for the Ameren Companies and EEI. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.
(a)
Amount is net of discount.
(b)
Ameren’s and UE’s long-term debt increased $240 million during 2006 as a result of the leasing transaction related to UE’s purchase of a 640-megawatt CT facility located in Audrain County, Missouri. No capital was raised as a result of UE’s assumption of the lease obligations.
(c)
Shares issued upon settlement of the stock purchase contracts, which were a component of the adjustable conversion-rate equity security units issued in March 2002.
(d)
Amount is less than $1 million.
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of December 31, 2007:
In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus.
Ameren is also currently selling newly issued shares of its common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including subsidiary plans that are now merged into the Ameren 401(k) plan), Ameren issued 1.7 million, ($91 million) shares of common stock in 2007, 1.9 million ($96 million) in 2006, and 2.1 million ($109 million) in 2005.
Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
See Note 4 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for a discussion of the covenants and provisions contained in our bank credit facilities and applicable cross-default provisions.
Also see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a discussion of covenants and provisions
contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At December 31, 2007, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events would increase our cost of capital or adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $527 million, or $2.54 per share, in 2007, $522 million, or $2.54 per share, in 2006, and $511 million, or $2.54 per share, in 2005. This resulted in a payout rate based on net income of 85% in 2007, 95% in 2006, and 84% in 2005. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 48% in 2007, 41% in 2006 and 41% in 2005.
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues, including Ameren’s historical earnings and cash flow, projected earnings, projected cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics, impacts of regulatory orders or legislation and overall business considerations. On February 8, 2008, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on March 31, 2008, to shareholders of record on March 5, 2008.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends. UE would be restricted as to dividend payments on its common and preferred stock if it were to extend or defer interest payments on its subordinated debentures. CIPS’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit it from making any dividend payments on common stock if debt service coverage ratios are below a defined threshold. CILCORP has common and preferred stock dividend payment restrictions if leverage ratio and interest coverage ratio thresholds are not met, or if CILCORP’s senior long-term debt does not have the ratings described in its indenture. CILCO has restrictions in its articles of incorporation on dividend payments on common stock relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock and amounts to be set aside for any sinking fund retirement of its 5.85% Series preferred stock. At December 31, 2007, except as described below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these conditions existed at the Ameren Companies, and as a result, they were allowed to pay dividends. The ICC requires IP to have a dividend policy comparable to that of Ameren’s other Illinois utilities and consistent with achieving and maintaining a common equity-to-total-capitalization ratio between 50% and 60%.
The 2007 $500 million credit facility and the 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to common and preferred stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured credit rating to below investment-grade, causing it to be subject to this dividend payment limitation. As of December 31, 2007, AERG was in compliance with the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities and therefore able to pay dividends. The other borrowers thereunder are not currently limited in their dividend payments by this provision of the 2007 or 2006 $500 million credit facilities.
The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents.
(a)
CILCO paid to CILCORP dividends of $- million, $65 million and $20 million for the years ended December 31, 2007, 2006 and 2005, respectively.
Certain of the Ameren Companies have issued preferred stock on which they are obligated to make preferred dividend payments. Each company’s board of directors considers the declaration of the preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 8 - Stockholder Rights Plan and Preferred Stock to our financial statements under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2007. See Note 9 - Retirement Benefits to our financial statements under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.
(a)
Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(b)
Excludes fair market value adjustments of long-term debt of $55 million for CILCORP and $20 million for IP.
(c)
Excludes unamortized discount of $6 million at UE, $1 million at CIPS, $1 million at Genco, and $4 million at IP.
(d)
The weighted average variable rate debt has been calculated using the interest rate as of December 31, 2007.
(e)
Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $1 million annual obligation for these items is included in the Less than 1 Year, 1 - 3 Years, and 3 - 5 Years columns. Amounts for After 5 Years are not included in the total amount because that period is indefinite.
(f)
See Other Obligations within Note 13 - Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items represented herein.
(g)
Represents parent company only.
The Ameren Companies adopted the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes” on January 1, 2007. As of December 31, 2007, the amounts of unrecognized tax benefits under the provisions of FIN 48 were $116 million, $26 million, $- million, $40 million, $19 million, $19 million and
$- million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. It is reasonably possible to expect that the settlement of an unrecognized tax benefit will result in an underpayment or overpayment of tax and related interest. However, there is a high degree of uncertainty with respect to the timing of cash payments or receipts associated with unrecognized tax benefits. The amount and timing of certain payments is not reliably estimable or determinable at this time. See Note 11 - Income Taxes for information regarding the Ameren Companies’ unrecognized tax benefits and related liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2007, none of the Ameren Companies had any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of
business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
Credit Ratings
The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:
During March and April of 2007, Moody’s, S&P, and Fitch downgraded various credit ratings of certain of the Ameren Companies. Depending on the specific credit rating agency action and the specific legal entities affected, the downgrade of these credit ratings was a result of the actions of various Illinois state legislators, including consideration of forms of legislation that would have rolled back and frozen the electric rates of CIPS, CILCO and IP. In the case of UE, this downgrade was prompted by higher costs, lower financial metrics, and a continued challenging regulatory environment in Missouri.
On June 8, 2007, Fitch changed the rating outlook at UE to negative due to the combined effect of the receipt of less than expected rate relief and a sizable capital expenditure program.
On August 1, 2007, Fitch changed the rating outlook at Ameren to stable. In addition, Fitch revised the rating watch on CIPS, CILCORP, CILCO and IP to positive. The positive watch followed the announcement of the Illinois electric settlement agreement. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 of this report for further discussion of the Illinois electric settlement agreement.
On August 29, 2007, S&P issued a research update in response to the Illinois electric settlement agreement. The outlook on the ratings of Ameren, UE and Genco was changed to stable. The outlook on the ratings of CIPS, CILCORP, CILCO, and IP was upgraded to positive. On September 6, 2007, S&P upgraded its senior secured debt ratings of UE, CIPS, and CILCO from “BBB-” to “BBB” as a result of changes in its first mortgage bond rating methodology.
On August 29, 2007, Moody’s changed the rating outlook at Ameren and Genco to stable. The rating outlook of CIPS, CILCORP, CILCO, and IP was upgraded to positive. These actions were prompted by the Illinois electric settlement agreement. Moody’s stated that “the settlement significantly reduces the likelihood of a rate freeze being enacted in Illinois and provides the foundation for a potentially improving political and regulatory environment for investor-owned-utilities in the state.”
On February 12, 2008, Moody’s affirmed the ratings of Ameren and Genco but changed their rating outlook to negative from stable. Moody’s placed the long-term credit ratings of UE under review for possible downgrade and affirmed UE’s commercial paper rating. In addition, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and maintained a positive rating outlook on these four companies. According to Moody’s, the review of UE’s ratings was prompted by declining cash flow coverage metrics, increased operating costs, higher capital expenditures for environmental compliance and transmission and distribution system investment, and significant regulatory lag in the recovery of these costs. Moody’s stated that the negative outlook on the credit rating of Genco reflected Genco’s “position as a predominantly coal generating company that is likely to be seriously affected by more stringent environmental regulations, including a potential cap or tax on carbon emissions.” The negative outlook on the ratings of Ameren, according to Moody’s, reflects the factors that impacted its subsidiaries, UE and Genco.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made as of the end of 2007 were $56 million, $5 million, $8 million, $14 million, $14 million, and $21 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively, resulting from our reduced issuer and senior unsecured debt ratings. At December 31, 2007, a reduction to sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”), could have resulted in Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $176 million, $65 million, $13 million, $43 million, $29 million, $29 million, and $12 million,
respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization. See Quantitative and Qualitative Disclosures about Market Risk - Interest Rate Risk under Part II, Item 7A, for information on credit rating changes with respect to insured tax-exempt auction-rate bonds.
OUTLOOK
Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2008 and beyond.
Revenues
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The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. With rising costs, including fuel and related transportation, purchased power, labor, material, depreciation and financing costs coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until requests to increase rates to recover such costs are granted by state regulators. Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary. UE expects to file its next electric rate case in Missouri during the second quarter of 2008. The Ameren Illinois Utilities filed delivery service rate cases with the ICC in November 2007 due to inadequate recovery of costs and low returns on equity of less than 5% experienced in 2007 and expected in 2008. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million, and IP - $139 million). The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 51% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates. In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease, and IP - $56 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 51% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until the end of September 2008 to render a decision in these rate cases.
•
In current and future rate cases, UE, CIPS, CILCO and IP will also seek cost recovery mechanisms from their state regulators to reduce regulatory lag. In their electric and natural gas delivery service rate cases filed in November 2007, the Ameren Illinois Utilities requested ICC approval to implement rate adjustment mechanisms for bad debt expenses, electric infrastructure investments, and the decoupling of natural gas revenues from sales volumes. In July 2005, a law was enacted that enables the MoPSC to put in place fuel and purchased power and environmental cost recovery mechanisms for Missouri’s utilities. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006. Rules for the environmental cost recovery mechanism were approved by the MoPSC in February 2008 and will be effective once published in the Missouri Register. UE will not be able to use these cost recovery mechanisms until authorized by the MoPSC as part of a rate case proceeding. The MoPSC denied UE the use of a fuel and purchased power cost recovery mechanism in its 2007 rate order. UE plans to request use of a fuel and purchased power cost recovery mechanism and, potentially an environmental cost recovery mechanism, in its next electric rate case filing.
•
Average residential electric rates for CIPS, CILCO and IP increased significantly following the expiration of a rate freeze at the end of 2006. Electric rates rose because of the increased cost of power purchased on behalf of the Ameren Illinois Utilities’ customers and an increase in electric delivery service rates. Due to the magnitude of these increases, the Illinois electric settlement agreement reached in 2007 provides approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement will come from electric generators in Illinois and certain Illinois electric utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following contributions remain to be made as of December 31, 2007:
(a)
Estimated.
To fund these contributions, the Ameren Illinois Utilities, Genco and AERG will need to increase their
respective borrowings.
•
As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It will be replaced with a new power procurement process to be led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary power and energy requirements primarily through a request-for-proposal process, subject to ICC review and
approval. The ICC approved the proposed 2008 power procurement plans of the Ameren Illinois Utilities in December 2007. Existing supply contracts from the September 2006 reverse auction remain in place. The Ameren Illinois Utilities’ power procurement costs are passed directly to its customers. The impact of the new procurement process in Illinois is uncertain.
•
Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock-in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements during the period June 1, 2008 to December 31, 2012, at then relevant market prices. These financial contracts do not include capacity, are not load-following products and do not involve the physical delivery of energy.
•
The MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service with new electric rates effective June 4, 2007. This order included provisions to extend UE’s Callaway nuclear plant and fossil generation plant lives and to change the income tax method associated with the cost of property removals. Such provisions are expected to decrease Ameren’s and UE’s expenses by $58 million annually. The MoPSC also approved a stipulation and agreement authorizing an increase in UE’s annual natural gas delivery revenues of $6 million, effective April 1, 2007. UE agreed not to file a natural gas delivery rate case before March 15, 2010.
•
Volatile power prices in the Midwest affect the amount of revenues Ameren, UE, Genco, CILCO (through AERG) and EEI can generate by marketing power into the wholesale and spot markets and influence the cost of power purchased in the spot markets.
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The availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. Genco and AERG are seeking to raise the equivalent availability and capacity factors of their power plants over the long-term through greater investments and a process improvement program. The Non-rate-regulated Generation segment expects to generate 33 million megawatthours of power in 2008 (Genco - 18 million, AERG - 7 million, EEI - 8 million), 31 million megawatthours in 2009 (Genco - 15 million, AERG - 8 million, EEI - 8 million) and 33 million megawatthours in 2010 (Genco - 18 million, AERG - 7 million, EEI - 8 million).
•
All but 5 million megawatthours of Genco and AERG’s pre-2006 wholesale and retail electric power supply agreements expired during 2006. In 2007, 1 million megawatthours of these agreements, which had an average embedded selling price of $35 per megawatthour, expired. Another 2 million contracted megawatthours will expire in late 2008, which have an average embedded selling price of $33 per megawatthour. These agreements are being replaced with market-based sales.
•
The marketing strategy for Non-rate-regulated Generation is to optimize generation output in a low risk manner to minimize earnings and cash flow volatility, while capitalizing on its low-cost generation fleet to provide solid, sustainable returns. Through a mix of physical and financial sales contracts, including contracts resulting from the Illinois 2006 power procurement auction and the Illinois electric settlement agreement, Marketing Company sold as of December 31, 2007, approximately 86% of Non-rate-regulated Generation’s expected 2008 generation at an average price of $50 per megawatthour (fiscal year 2009 - 60%, at an average price of $52 per megawatthour; fiscal year 2010 - 45%, at an average price of $54 per megawatthour).
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The future development of ancillary services and capacity markets in MISO could increase the electric margins of UE, Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider’s system. In February 2008, FERC conditionally accepted the ancillary services market tariff proposed by MISO. We expect Non-rate-regulated Generation’s ancillary services market revenues to increase to $15 million in 2008 from $5 million realized in 2007. Ancillary services market revenues are allocated to Genco and AERG based on their generation in accordance with their power supply agreements with Marketing Company.
•
We expect MISO will begin development of a capacity market once its ancillary services market is in place. A capacity market allows participants to purchase or sell capacity products that meet reliability requirements. MISO is currently in the process of developing a centralized regional wholesale ancillary services market, which is expected to begin during 2008. We expect capacity and energy prices to strengthen from current levels because of improving market liquidity and decreasing reserve margins in MISO. Non-rate-regulated Generation’s capacity revenues are expected to increase to approximately $40 million in 2008 from $25 million in 2007. EEI receives payment for 100% of its capacity sales under its power supply agreement with Marketing Company. Capacity revenues are allocated to Genco and AERG based on their generation in accordance with their power supply agreements with Marketing Company.
•
We expect continued economic growth in our service territory and market area to benefit energy demand in 2008 and beyond, but higher energy prices could result in reduced demand from customers, especially in Illinois. Future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could also result in reduced demand for our electric generation and our electric and gas transmission and distribution services.
Fuel and Purchased Power
•
In 2007, 84% of Ameren’s electric generation (UE - 76%, Genco - 96%, AERG - 99%, EEI - 100%) was supplied by coal-fired power plants. About 94% of the coal used by these plants (UE - 97%, Genco - 88%,
AERG - 92%, EEI - 100%) was delivered by railroads from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather, and derailments. As of December 31, 2007, coal inventories for UE, Genco, AERG and EEI were adequate, and in excess of historical levels, but below targeted levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
•
Ameren’s fuel costs (including transportation) are expected to increase in 2008 and beyond. Fuel costs for both Missouri Regulated and Non-rate-regulated Generation are expected to increase approximately 35% from 2007 to 2010. As of December 31, 2007, approximately 94%, 86% and 54% of Missouri Regulated’s estimated fuel costs for 2008, 2009 and 2010, respectively, were priced-hedged. Approximately 98%, 72% and 16% of Non-rate-regulated Generation’s estimated fuel costs for 2008, 2009 and 2010, respectively, were price-hedged. See Item 7A
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, are not part of the following discussion.
Our risk management objective is to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
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long-term and short-term variable-rate debt;
•
fixed-rate debt;
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commercial paper; and
•
auction-rate long-term debt.
We manage our interest rate exposure by controlling the amount of these instruments we have within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.
The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at December 31, 2007:
(a)
Calculations are based on an effective tax rate of 38%.
(b)
Less than $1 million.
The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.
Insured Tax-exempt Auction Rate Bonds
Our tax-exempt environmental improvement and pollution control revenue-auction-rate bonds issued for the benefit of UE, CIPS, CILCO and IP through governmental authorities are insured by “monoline” bond insurers. See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of the tax-exempt environmental improvement and pollution control revenue bonds issued for the benefit of UE, CIPS, CILCO and IP. Monoline bond insurers guarantee the timely repayment of bond principal and interest when an issuer defaults; as a result, such securities typically receive the highest investment-grade ratings from the credit rating agencies, which reflect the credit ratings of the monoline bond insurers. UE has an aggregate of $437 million principal amount of insured tax-exempt auction-rate bonds ($229 million insured by XL Capital Ltd., $208 million insured by MBIA Inc.). CIPS has $35 million principal amount of insured tax-exempt auction-
rate bonds insured by XL Capital Ltd. CILCO has $19 million principal amount of insured tax-exempt auction-rate bonds insured by Financial Guaranty Insurance Company. IP has an aggregate of $337 million principal amount of insured tax-exempt auction-rate bonds ($150 million insured by MBIA Inc., $187 million insured by Ambac Financial Group, Inc.). Our insured tax-exempt auction-rate bonds bear interest at rates determined pursuant to auctions conducted every seven or 35 days, depending on the particular series of securities. As a result of developments in the capital markets with respect to residential mortgage-backed securities and collateralized debt obligations, the credit rating agencies have placed some of the monoline bond insurers on review for a possible downgrade or have actually downgraded their credit ratings due to their insuring of such securities. As a result, since December 2007, the insured tax-exempt bonds that are guaranteed by the monoline bond insurers have similarly been placed on review for possible downgrade or have been downgraded. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
As a result of these actions by the credit rating agencies with respect to monoline bond insurers and a lack of liquidity in the auction rate market, we believe the interest rates on certain of our insured tax-exempt auction rate bonds are higher than they would have been in the absence of such actions. It is possible that the credit rating agencies may continue to take steps to further downgrade the credit ratings of the monoline bond insurers as well as our tax-exempt bonds insured by such insurers and any such further negative actions could result in higher interest rates on our insured tax-exempt auction rate bonds. Downgrades of the monoline bond insurers also increase the possibility of a “failed auction,” where there are not sufficient clearing bids in an auction to set the interest rate. A “failed auction” would result in the interest rates resetting to maximum interest rates ranging up to 18%, depending upon the series of bonds, until the next scheduled auction date at which time another attempt at a successful auction will be made.
Between February 12 and 20, we experienced “failed auctions” with respect to a portion of our tax-exempt auction rate bonds. According to press reports, many other series of tax-exempt auction rate securities similarly experienced “failed auctions.”
We are evaluating various options available to us, including refinancing with other instruments, to mitigate the effects of the ratings downgrades on the monoline insurers and the effects of these on the interest rates of our securities. Certain of these options would require approvals from state regulators and could result in higher expense.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.
Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2007, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, CIPS, Genco, AERG, IP, AFS, and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At December 31, 2007, UE’s, CIPS’, Genco’s, CILCO’s, IP’s, AFS’, and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties related to interchange or wholesale purchases and sales was less than $1 million, net of collateral (2006 - less than $1 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $63 million at December 31, 2007 (2006 - $35 million).
The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois electric settlement agreement, which will provide $488 million in rate relief over a four-year period to certain electric customers of the Ameren Illinois Utilities. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Union Electric Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Central Illinois Public Service Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Ameren Energy Generating Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Energy Generating Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of CILCORP Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of CILCORP Inc. and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Central Illinois Light Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Light Company and its subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Illinois Power Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Illinois Power Company and its subsidiary at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2008
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
CILCORP INC. (Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS December 31,
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries 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 on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.
•
UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, it also operated those businesses in Illinois. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and gas service to a 24,000-square-mile area located in central and eastern Missouri. This area has an estimated population of 3 million and includes the Greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.
•
CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1902. It supplies electric and gas utility service to portions of central, west central and southern Illinois having an estimated population of 1 million in an area of 20,500 square miles. CIPS supplies electric service to 400,000 customers and natural gas service to 190,000 customers.
•
Genco, or Ameren Energy Generating Company, operates a non-rate-regulated electric generation business in Illinois and Missouri. Genco was incorporated in Illinois in March 2000. Genco owns 2,549 megawatts of coal-fired electric generating capacity and 1,666 megawatts of natural gas and oil-fired electric generating capacity.
•
CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business, and a rate-regulated natural gas transmission and distribution business in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and gas utility service to portions of central and east central Illinois in areas of 3,700 and 4,500 square miles, respectively, with a population of 1 million. CILCO supplies electric service to 210,000 customers and natural gas service to 213,000 customers. AERG, a non-rate-regulated wholly owned subsidiary of CILCO, owns 1,074 megawatts of coal-fired electric generating capacity and 55 megawatts of natural gas and oil-fired electric generating capacity. CILCORP was incorporated in Illinois in 1985.
•
IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. IP was incorporated in 1923 in Illinois. It supplies electric and gas utility service to portions of central, east central and southern Illinois, serving a population of 1.4 million in an area of 15,000 square miles, contiguous to our other service territories. IP supplies electric service to 626,000 customers and natural gas service to 427,000 customers, including most of the Illinois portion of the Greater St. Louis area.
Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which during 2007 was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes, while UE for 2007 reported EEI under the equity method. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren.
The following table presents summarized financial information of EEI (in millions).
The financial statements of the Ameren Companies (except CIPS) are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries as applicable. All significant intercompany
transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, the NRC, and FERC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” UE, CIPS, CILCO and IP defer certain costs pursuant to actions of our rate regulators. These companies are currently recovering such costs in rates charged to customers. See Note 2 - Rate and Regulatory Matters for further information.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. The allowance is based on the application of a historical write-off factor to the amount of outstanding receivables, including unbilled revenue, and a review for collectibility of certain accounts over 90 days past due.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
Consists of coal, oil, paint, propane, and tire chips.
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, is also added for our rate-regulated assets. Interest during construction is added for non-rate-regulated assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage value, are charged to accumulated depreciation. Asset removal costs incurred by our non-rate-regulated operations that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 - Property and Plant, Net for further information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis. The provision for depreciation for the Ameren Companies in 2007, 2006 and 2005 generally ranged from 3% to 4% of the average depreciable cost. Due to the Missouri electric rate order that became effective in June 2007, UE’s annual depreciation expense will be reduced by $53 million. Genco’s annual depreciation expense will decrease by $12 million according to a depreciation study completed in September 2007.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, as is the
utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The following table presents the allowance for funds used during construction rates that were utilized during 2007, 2006 and 2005:
Goodwill and Intangible Assets
Goodwill. As of December 31, 2007, Ameren, CILCORP and IP had goodwill of $831 million, $542 million and $214 million, respectively. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. We evaluate goodwill for impairment in the fourth quarter of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren’s and IP’s goodwill relates to the acquisitions of IP and an additional 20% ownership interest in EEI in 2004, and Ameren’s and CILCORP’s goodwill relates to the acquisitions of CILCORP and Medina Valley in 2003.
There were no changes in the carrying amount of goodwill at any of the Ameren Companies for the period from January 1, 2007, to December 31, 2007.
Intangible Assets. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of the following:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Includes fair market value adjustments recorded in connection with Ameren’s acquisition of CILCORP.
(c)
Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations, except at UE where usage of emission allowances is deferred as a regulatory liability.
The following table presents the net book value of emission allowances consumed or (sold) for Ameren, UE, Genco, CILCORP and CILCO (AERG) and recognized in earnings during the years ended December 31, 2007, 2006 and 2005.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Includes allowances consumed that were recorded through purchase accounting.
Impairment of Long-lived Assets
We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize the amount of the impairment by estimating the fair value of the assets and recording a provision for loss.
Investments
Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Investments are considered to be impaired when a decline in fair value below the cost basis is estimated to be other than temporary. If the decline is determined to be other than temporary, the cost basis of the security is written down to fair value. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which we believe would be recovered in electric rates paid by UE’s customers. Accordingly, any impairment would likely be recorded as a regulatory asset on Ameren’s and UE’s Consolidated Balance
Sheets. Ameren and UE consider, among other factors, general market conditions, the duration and the extent to which the security’s fair value has been less than cost, and UE’s intent and ability to hold the investment. See Note 15 - Fair Value of Financial Instruments for disclosure of the fair value and unrealized gains and losses of UE’s investments.
Environmental Costs
Environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and that the amount of the liability can be reasonably estimated. Estimated environmental expenditures are regularly reviewed and updated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Unamortized Debt Discount, Premium, and Expense
Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.
Revenue
Operating Revenues
UE, CIPS, Genco, CILCO and IP record operating revenue for electric or gas service when it is delivered to customers. We accrue an estimate of electric and gas revenues for service rendered but unbilled at the end of each accounting period.
Trading Activities
We present the revenues and costs associated with certain energy derivative contracts designated as trading on a net basis in Operating Revenues - Electric and Other.
Fuel and Gas Costs
In UE’s, CIPS’, CILCO’s and IP’s Missouri and Illinois retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses.
UE’s cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and that cost is charged to expense.
Stock-based Compensation
In accounting for stock-based compensation, Ameren measures the cost of employee services received in exchange for an award of equity instruments by the grant-date fair value of the award over the requisite service period.
See Note 10 - Stock-based Compensation for further information.
Excise Taxes
Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the years ended 2007, 2006 and 2005:
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and tax return purposes. These deferred tax assets and liabilities are determined by statutory tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded due to decreases in the statutory rate, were credited to a regulatory liability. A regulatory asset has been established to recognize the probable future recovery in rates of future income taxes resulting principally from the reversal of allowance for funds used during construction, that is, equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of SFAS No. 109.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; they are being amortized over the useful lives of the related properties. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 11 - Income Taxes.
UE, CIPS, Genco, CILCORP, CILCO, and IP are parties to a tax sharing agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax sharing agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.
Minority Interest and Preferred Dividends of Subsidiaries
For the years ended December 31, 2007, 2006, and 2005, Ameren had minority interest expense related to EEI of $27 million, $27 million and $3 million, respectively, and preferred dividends of subsidiaries of $11 million, $11 million, and $13 million, respectively.
Earnings Per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2007, 2006, and 2005. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 35,545 shares in 2007, 38,438 shares in 2006, and 65,917 shares in 2005.
Accounting Changes and Other Matters
Staff Accounting Bulletin No. 108, Considering the Effects of Prior-Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108)
In September 2006, the SEC staff issued SAB 108, which provides interpretive guidance on how registrants should quantify misstatements when evaluating the materiality of financial statement errors. SAB 108 requires public companies to use a dual approach to assess the quantitative effects of financial misstatements. The dual approach includes both an income statement-focused assessment and a balance sheet-focused assessment. SAB 108 also provides transition accounting and disclosure guidance for situations in which a material error existed in prior-period financial statements, allowing companies to restate prior-period financial statements or to recognize the cumulative effect of initially applying SAB 108 through an adjustment to beginning retained earnings in the year of adoption. SAB 108 was effective as of December 31, 2006.
Prior to 2000, we concluded that UE’s unbilled revenue was understated and CIPS’ unbilled revenue was overstated by a similar amount. We previously concluded that these differences were immaterial to the financial statements of UE and CIPS for all years subsequent to 2000. In connection with our application of SAB 108, we recorded a decrease to CIPS’ unbilled revenue of $12 million as an adjustment to retained earnings. Additionally, we concluded the UE unbilled revenue difference was immaterial to its 2006 financial statements. Accordingly, we recorded an increase to UE’s unbilled revenue of $12 million in the fourth quarter of 2006 as an increase in operating revenues. The adoption of SAB 108 had no impact on Ameren’s consolidated results of operations, financial position, or liquidity.
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of SFAS No. 109 (FIN 48)
FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, Ameren may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition of income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties on income taxes, and accounting for income taxes in interim periods. FIN 48 requires expanded disclosures. The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. See Note 11 - Income Taxes for additional FIN 48 discussion.
SFAS No. 157, Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. SFAS No. 157 clarifies that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. This standard is effective as of the beginning of our 2008 fiscal year for financial assets and liabilities and as of the beginning of our 2009 fiscal year for nonfinancial assets and liabilities, except those already reported at fair value on a recurring basis. The impact of the adoption of SFAS No. 157 for financial assets and liabilities at January 1, 2008, was not material. The impact of the adoption of SFAS No. 157 for nonfinancial assets and liabilities is not expected to be material.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of SFAS No. 115
In February 2007, the FASB issued SFAS No. 159, which permits companies to choose to measure at fair value many financial instruments and certain assets and liabilities that are not currently required to be measured at fair value on an instrument-by-instrument basis. Entities electing the fair value option will be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. SFAS No. 159 was effective as of the beginning of our 2008 fiscal year. We did not elect the fair value option for any of our eligible financial instruments or other items.
FSP FIN 39-1, Amendment of FASB Interpretation No. 39
In April 2007, the FASB issued FSP FIN 39-1, effective for us as of the beginning of our 2008 fiscal year. FSP FIN 39-1 permits companies to offset fair value
amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. We are currently evaluating whether we will elect to apply the accounting policies permitted under this pronouncement. The adoption of FSP FIN 39-1 will have no impact on net income, and we do not expect that the impact will be material to our financial position.
SFAS No. 141(Revised 2007), Business Combinations
In December 2007, the FASB issued SFAS No. 141(R), which replaces SFAS No. 141. SFAS No. 141(R) applies to all transactions in which an entity obtains control of one or more businesses and combinations without the transfer of consideration. SFAS 141(R) requires the acquiring entity in a business combination to recognize assets acquired and liabilities assumed in the transaction at fair value; it requires certain contingent assets and liabilities acquired be recognized at their fair values on the acquisition date; and it requires expensing of acquisition-related costs as incurred, among other provisions. SFAS 141(R) will be effective for us as of the beginning of our 2009 fiscal year. It will apply prospectively to business combinations completed on or after that date.
SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51
In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for minority interests, which will be recharacterized as noncontrolling interests. Under the provisions of SFAS 160, noncontrolling interests will be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control will be accounted for as equity transactions; net income attributable to the noncontrolling interest will be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, will be recorded at fair value with any gain or loss recognized in earnings. SFAS 160 will be effective for us as of the beginning of our 2009 fiscal year. It will apply prospectively, except for the presentation and disclosure requirements, for which it will apply retroactively. This standard will be applicable to the minority interest in EEI, as it is 80% owned by Ameren Corporation.
Asset Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement Obligations, and FIN 47, Accounting for Conditional Asset Retirement Obligations - an Interpretation of FASB Statement No. 143, require us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments in AROs based on changes in estimated fair value. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing or amount of cash flows associated with AROs affect our estimates of fair value. Upon adoption of SFAS No. 143 and FIN 47, Ameren, UE, Genco, CILCORP, and CILCO recorded AROs for retirement costs associated with UE’s Callaway nuclear plant decommissioning costs, asbestos removal, ash ponds, and river structures. In addition, Ameren, UE, CIPS, and IP recorded AROs for the disposal of certain transformers.
Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 - Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2007 and 2006:
(a)
Ameren amounts do not equal total due to AROs at EEI.
(b)
The nuclear decommissioning trust fund assets of $307 million and $285 million as of December 31, 2007 and 2006, respectively, are restricted for decommissioning of the Callaway nuclear plant.
(c)
Substantially all accretion expense was recorded as an increase to regulatory assets.
(d)
Less than $1 million.
(e)
UE, Genco and CILCO changed estimates related to retirement costs for their ash ponds. Additionally, UE changed estimates related to its Callaway nuclear plant decommissioning costs.
Variable-interest Entities
According to FIN 46R, “Variable-interest Entities,” an entity is considered a variable-interest entity (VIE) if it does not have sufficient equity to finance its activities without assistance from variable interest holders, or if its equity investors lack any of the following characteristics of a controlling financial interest: control through voting rights, the obligation to absorb expected losses, or the right to receive expected residual returns. We have determined that the following significant VIEs were held by the Ameren Companies at December 31, 2007:
•
Tolling agreement. CILCO has a variable interest in Medina Valley through a tolling agreement to purchase steam, chilled water, and electricity. We have concluded that CILCO is not the primary beneficiary of Medina Valley. Accordingly, CILCO does not consolidate Medina Valley. The maximum exposure to loss as a result of this variable interest in the tolling agreement is not material.
•
Leveraged lease and affordable housing partnership investments. Ameren and UE have investments in affordable housing and low-income real estate development partnership arrangements that are variable interests. Ameren also has an investment in a leveraged lease. We have concluded that Ameren and UE are not primary beneficiaries of any of the VIEs related to these investments. The maximum exposure to loss as a result of these variable interests is limited to the investments in these arrangements. At December 31, 2007, Ameren and UE had investments in affordable housing and low-income real estate development partnerships of $100 million and $15 million, respectively. At December 31, 2007, Ameren had a net investment in a leveraged lease of $9 million.
•
IP SPT. IP has a variable interest in IP SPT, which was established in 1998 to issue TFNs. IP has indemnified and is liable to IP SPT if IP does not bill the applicable charges to its customers on behalf of IP SPT or if it does not remit the collections to IP SPT; however, the note holders are considered the primary beneficiaries of this special-purpose trust. Accordingly, Ameren and IP do not consolidate IP SPT.
NOTE 2 -
RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.
Missouri
Electric
With the expiration of an electric rate moratorium that provided for no changes in UE’s electric rates before July 1, 2006, UE filed in July 2006 a request with the MoPSC for an average increase in electric rates of 17.7%, or $361 million, based on a requested return on equity of 12.0%. This rate increase filing was based on a test year ended June 30, 2006, and was updated for known and measurable items through January 1, 2007.
In May 2007, the MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service based on a return on equity of 10.2% and a capital structure of 52% common equity. New electric rates became effective June 4, 2007. The MoPSC order also included the following significant provisions:
•
Acceptance without rate adjustment of the expiration of UE’s cost-based power supply contract with EEI, which expired in December 2005.
•
Allowance of the full cost of certain CTs purchased or built in the past few years to be included in UE’s rate base.
•
Establishment of a regulatory tracking mechanism, through the use of a regulatory liability account, for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts. These deferred amounts will be addressed as part of UE’s next rate case. The MoPSC allowed an annual base level of SO2 emission allowance sales of up to $5 million, which UE can recognize in its statement of income.
•
Approval of a regulatory tracking mechanism for pension and postretirement benefit costs.
•
Change of income tax method associated with the cost of property removal, net of salvage, to the normalization method of accounting, which reduced income tax expense in the calculation of UE’s electric rates and in financial reporting.
•
Establishment of off-system sales base level of $230 million used in determining UE’s revenue requirement.
•
Extension of UE’s Callaway nuclear plant and fossil generation plant lives used in calculating depreciation expense for electric rates and financial reporting purposes.
•
MoPSC staff directed to review a possible loss in capacity sales as a result of the breach of the upper reservoir of the Taum Sauk pumped-storage hydroelectric facility. The review is still pending.
•
Establishment of a requirement to fund low-income energy assistance and energy conservation programs; half of such funding will be recoverable through rates to customers.
•
Denial of UE’s request to implement a fuel and purchased power cost recovery mechanism.
In June 2007, the MoPSC denied UE’s and other intervenors’ applications for a rehearing with respect to certain aspects of the MoPSC rate order. In July 2007, UE appealed certain aspects of the MoPSC decision, principally the 10.2% return on equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both parties in the electric rate case, also appealed certain aspects of the MoPSC decision to the
Circuit Court of Cole County. In December 2007, the Circuit Court of Cole County sustained the MoPSC rate order in all respects. In January 2008, UE and the other parties appealed the Circuit Court of Cole County’s decision to the Court of Appeals for the Western District of Missouri.
Gas
In March 2007, the MoPSC approved a stipulation and agreement that resolved a July 2006 request by UE to increase annual natural gas delivery revenues by $11 million. The stipulation and agreement authorized an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. Other principal provisions of the stipulation and agreement include:
•
UE’s agreement to not file a natural gas delivery rate case before March 15, 2010. This agreement did not prevent UE from filing to recover infrastructure replacement costs through an ISRS during this three-year rate moratorium. The return on equity to be used by UE for purposes of an ISRS tariff filing is 10.0%.
•
Authorization for UE to transition from four PGA rates to a single PGA rate for all its gas customers.
In February 2008, the MoPSC approved UE’s petition requesting the establishment of an ISRS to recover annual revenues of $1 million effective March 29, 2008.
Cost Recovery Mechanisms
A 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. Rules for the environmental cost recovery mechanism were approved by the MoPSC in February 2008 and will be effective once published in the Missouri Register. UE will not be able to use the cost recovery mechanisms until so authorized by the MoPSC as part of a rate case proceeding.
Taum Sauk
In June 2007, the MoPSC opened an investigation of the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility in December 2005. In December 2007, the MoPSC issued an order receiving the MoPSC staff report on the Taum Sauk incident. The order, which did not require UE to implement any of the staff recommendations, noted that UE voluntarily agreed to implement almost all of the recommendations, and it closed the investigation. See Note 13 - Commitments and Contingencies for additional information.
January 2007 Ice Storm Cost Recovery
UE submitted a filing to the MoPSC in November 2007 requesting that operations and maintenance expenses UE incurred as a result of a severe ice storm in January 2007 be deferred as a regulatory asset and, if approved, be amortized over five years beginning with the effective date of electric rates approved in UE’s next rate proceeding. UE incurred approximately $25 million of operations and maintenance expenses in the first quarter of 2007 as a result of the January storm. In January 2008, the MoPSC staff recommended that the MoPSC grant UE’s request with the amortization to commence on January 15, 2007. The MoPSC is expected to issue an order on UE’s filing in 2008. If approved by the MoPSC, this would only provide UE approval to defer the expenses incurred as a regulatory asset. The appropriate amount to be amortized would be decided in UE’s next rate proceeding.
Illinois
Electric
New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased on behalf of Ameren Illinois Utilities’ customers in the September 2006 auction in accordance with a January 2006 ICC order. These new electric rates were expected to raise average annual residential rates overall in 2007 by 40% to 55% over 2006 rates. The average annual residential rate overall increase for electric heat customers was expected to be 60% to 80% over 2006 rates.
Due to the magnitude of these rate increases, various legislators supported legislation that would have reduced and frozen CIPS, CILCO and IP electric rates at the levels in effect prior to January 2, 2007, and would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. In July 2007, an agreement was reached among key stakeholders in Illinois to avoid such legislation and address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement, which includes a comprehensive rate relief and customer assistance program, were set forth in a letter dated July 24, 2007, to the leaders of the Illinois General Assembly and the Illinois attorney general. They also appear in a release and settlement agreement with the Illinois attorney general, in funding agreements among the parties contributing to the rate relief and assistance programs, and in legislation that became effective on August 28, 2007. The following discussion of the Illinois electric settlement agreement includes its impact on future power procurement for the Ameren Illinois Utilities and other significant regulatory and related legal matters that affect our Illinois electric operations.
Illinois Electric Settlement Agreement
The Illinois electric settlement agreement was the result of many months of negotiations among leaders of the Illinois
House of Representatives and Senate, the office of the Illinois attorney general, Ameren, on behalf of its affiliates, including Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon Corporation (Exelon), on behalf of Exelon Generation Company LLC, Commonwealth Edison Company (Commonwealth Edison), Exelon’s Illinois electric utility subsidiary, Dynegy Holdings Inc., Midwest Generation, LLC, and MidAmerican Energy Company. The Illinois electric settlement agreement provides approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco, and $28 million from AERG. Below is a summary of the total customer relief and assistance to be provided to the customers of the Ameren Illinois Utilities, the Ameren Illinois Utilities’, Genco’s and AERG’s portion of the funding that has been or is expected to be disbursed, and the earnings per share impact as a result of the program and agreement.
(a)
Includes a $4.5 million contribution in 2007 towards funding of a newly created IPA.
(b)
Includes $3 million for forgiveness of outstanding customer late payment fees.
(c)
Excludes $3 million for forgiveness of outstanding customer late payment fees.
(d)
Estimated.
The Ameren Illinois Utilities, Genco and AERG will recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding shown in the above table. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, of $82 million, $12 million, $7 million, $15 million, $33 million, and $15 million, respectively, under the terms of the Illinois electric settlement agreement including the forgiveness of $3 million of outstanding customer late payments during the year ended December 31, 2007.
Other electric generators and utilities in Illinois agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the Generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities send a bill, due in 30 days, to the Generators and utilities for their proportionate share of that month’s rate relief and assistance. If any escrow funds have been provided by the Generators, these funds will be drawn prior to seeking reimbursement from the Generators. At December 31, 2007, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $34 million, $13 million, $7 million and $14 million, respectively.
The Illinois electric settlement agreement preserves existing rates and rate structures. The Ameren Illinois Utilities retain the right to file new electric delivery service rate cases with the ICC at the respective utility’s discretion. See Electric and Natural Gas Delivery Service Rate Cases below for information on pending electric delivery service rate increase requests filed by the Ameren Illinois Utilities. The Illinois electric settlement agreement provides that if legislation is enacted in Illinois before August 1, 2011, freezing or reducing retail electric rates, or imposing or authorizing a new tax, special assessment, or fee on the generation of electricity then the remaining commitments under the Illinois electric settlement agreement would expire, and any funds set aside in support of the commitments would be refunded to the utilities and Generators.
As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It will be replaced with a new power procurement process to be led by the IPA, beginning in 2009. In 2008, Illinois utilities will contract for necessary power and energy requirements primarily through a request-for-proposal process, subject to ICC review and approval. The ICC approved the proposed 2008 power procurement plans of the Ameren Illinois Utilities in December 2007. Existing supply contracts from the September 2006 reverse auction remain in place. In the September 2006 auction, the Ameren Illinois Utilities procured power to serve the electric load needs of fixed price residential and small commercial customers with one-third of the supply contracts expiring in May 2008, one-third expiring in May 2009 and one-third expiring in May 2010.
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock-in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. These financial contracts became effective on August 28, 2007, when legislation in connection with the Illinois electric settlement agreement became law. Below are
the contracted volumes and prices per megawatthour.
The financial contracts provide that if any one of the following events occurs during their term, the Ameren Illinois Utilities and Marketing Company will meet as soon as practicable, but no later than 30 days after the date such event occurs, to identify and discuss its effect on the terms and conditions of, and prices under the financial contracts: (a) a state tax on electric generation; (b) a state or federal tax on and/or regulation of greenhouse gas emissions (e.g., a carbon tax); or (c) enactment of an Illinois law that eliminates retail electric supplier choice for the residential and small commercial customers of the Ameren Illinois Utilities. The financial contracts also provide that if any one of these events occurs, the parties to the financial contracts will negotiate to determine in a commercially reasonable manner whether the affected terms, conditions and prices can be revised so as to preserve the economic benefits of the financial contracts for all parties and, if so, to revise the financial contracts accordingly. In the event the parties to the financial contracts are not able to agree on such revisions, Marketing Company may terminate the financial contracts by written notice no earlier than 60 days and no later than 90 days after such event occurs, with the termination being effective when notice is given. Under the terms of the Illinois electric settlement agreement, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.
Beginning in June 2009, power procurement will be accomplished primarily through competitive requests for proposals to supply power and energy needs of the utility instead of the full requirements, load-following supply contracts previously procured through the reverse auction. The new power procurement process would require the IPA to develop an annual Procurement Plan (the Plan) for the Ameren Illinois Utilities and Commonwealth Edison. Each Plan would govern a utility’s procurement of power to meet the expected load requirements that are not met by preexisting contracts or generation facilities. Subject to ICC approval, the Ameren Illinois Utilities would be allowed to lease or invest in generation facilities. The objective of each Plan would be to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability for the utilities’ eligible retail customers. The new power procurement process provides that each Plan be submitted to the ICC for initial approval; if it is approved, the final design and implementation of a Plan would be overseen by an independent procurement administrator selected by the IPA and a procurement monitor selected by the ICC. The IPA has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009. Winning proposals will be selected on the basis of price, compared for reasonableness to benchmarks developed by the procurement administrator and procurement monitor, and approved by the ICC.
The power procurement process provides for the subject electric utility in Illinois to file proposed tariffs with the ICC, which will be designed to pass through to customers the costs of procuring electric power supply with no markup by the utility, plus any reasonable costs that the utility incurs in arranging and providing for the supply of electric power. All such procurement costs will be deemed to have been prudently incurred and will be recoverable through rates.
The Illinois electric settlement agreement provides that the Ameren Illinois Utilities have a right to maintain membership in a FERC-approved regional transmission organization of their choice for a period of at least 15 years.
The Illinois electric settlement agreement also includes a commitment to energy conservation programs designed to reduce energy consumption through increased energy efficiency and demand response. In addition, 2% of the Illinois utilities’ electricity is to be procured from renewable sources beginning June 1, 2008, with that percentage increasing in subsequent years, subject to limits on customer rate impacts. The provision for full and timely recovery of the cost of these commitments is also included in the Illinois electric settlement agreement.
Pursuant to the Illinois electric settlement agreement, all previously pending litigation and regulatory actions by the office of the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the alleged electric space heating marketing practices of the Ameren Illinois Utilities have been withdrawn with prejudice. These withdrawn litigation and regulatory actions included those filed by the office of the attorney general with FERC, the ICC, the U.S. Court of Appeals for the District of Columbia Circuit, the Circuit Court of the First Judicial Circuit Jackson County, Illinois, and the Appellate Court of Illinois, Second Judicial Circuit.
Finally, the Illinois electric settlement agreement establishes the authority to obtain accelerated review by the ICC of a merger or combination of the three Ameren Illinois Utilities, if it is requested in the future.
Appeals of 2006 ICC Procurement Order
The Illinois attorney general, CUB, and ELPC appealed to Illinois district appellate courts the ICC’s denial of rehearing requests with respect to its January 2006 order, which approved the power procurement auction and related tariffs. In August 2006, the Supreme Court of Illinois ordered that the appeals be consolidated in the appellate court for the Second Judicial Circuit in Illinois. The Illinois attorney general’s appeal was withdrawn as part of the Illinois electric
settlement agreement. In September 2007, the Ameren Illinois Utilities filed a motion to dismiss the appeals of CUB and ELPC, which was granted in October 2007. No further appeals have been filed.
Power Procurement Auction Lawsuits
Ameren, CIPS, CILCO, IP, Commonwealth Edison and its parent company, Exelon, and 15 other electricity suppliers, including Marketing Company, which are selling power to the Illinois utilities pursuant to contracts entered into as a result of the September 2006 power procurement auction, were named as defendants in two similar lawsuits. Plaintiffs were filed in the Circuit Court of Cook County, Illinois in March 2007, seeking class action status to represent all customers who purchased electric service from Commonwealth Edison Company or the Ameren Illinois Utilities. Both lawsuits alleged, among other things, that the Illinois utilities and the power suppliers illegally manipulated prices in the September 2006 power procurement auction. Plaintiffs sought actual and punitive damages. In December 2007, the U.S. District Court for the Northern District of Illinois granted the defendants’ motion to dismiss the lawsuits, and the time to appeal this court decision has expired.
Redesigned Rates
In late 2007, the ICC issued an order, as amended, authorizing redesigned electric rates for CIPS, CILCO and IP that was implemented January 1, 2008. These rates were designed to allow utilities to recover their full costs while reducing seasonal fluctuations for residential customers who use large amounts of electricity. The redesigned rates will not change total annual revenues collected by the Ameren Illinois Utilities in 2008 and subsequent years.
Electric and Natural Gas Delivery Service Rate Cases
CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million, and IP - $139 million). The Ameren Illinois Utilities pledged in 2007 to keep overall residential electric bill increase to less than 10% for each utility in their next rate filings. These filings are consistent with that pledge. Accordingly, the requested rate increase for IP residential customers is to be capped at the 10% increase level in the first year of the increase, even if the final authorized rate increase exceeds that amount. This rate increase limit could result in approximately $30 million of the requested increase not being phased in until the second year. The amount of CIPS’ and CILCO’s requested increases did not require inclusion of similar limits, as they were within the scope of the pledge. The electric rate increase requests are based on an 11% return on equity, a capital structure composed of 51% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates.
CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests are based on an 11% return on equity, a capital structure composed of 51% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion, and a test year ended December 31, 2006, with certain prospective updates.
In their filings, the Ameren Illinois Utilities have also requested that the ICC approve to implement mechanisms that would permit the reconciliation and adjustment of actual bad debt expenses to those established in rates set by the ICC for electric and gas customers. The filings also seek a more timely recovery of investments in existing electric distribution plant. Because general rate adjustment proceedings require up to 11 months in Illinois, these mechanisms would allow current revenues to better match current costs. In addition, the Ameren Illinois Utilities are seeking approval of a revenue decoupling rate adjustment mechanism as a part of their natural gas delivery service rate change requests. This mechanism would separate each utility’s fixed cost recovery from the volume of gas it sells by providing a periodic true-up of revenues. The periodic true-up would result in adjustments to a utility’s ICC-approved tariffs based on increases or decreases in demand for natural gas.
The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by the end of September 2008. The Ameren Illinois Utilities cannot predict the level of any delivery service rate change the ICC may approve, when any rate change may go into effect, whether any rate adjustment mechanism discussed above will be approved, or whether any rate increase eventually approved will be sufficient for the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the increase goes into effect.
Electric and Natural Gas Energy Efficiency Plans
In November 2007, the Ameren Illinois Utilities filed an electric energy efficiency and demand response plan with the ICC. The plan is designed to reduce electricity usage by specific targeted amounts set forth in the Illinois electric settlement agreement. The Ameren Illinois Utilities’ spending limit under this plan for the 2008, 2009 and 2010 program years is $14 million, $29 million and $45 million, respectively. In February 2008, the ICC issued an order approving the Ameren Illinois Utilities’ energy efficiency and demand response plan, as well as the cost recovery mechanism by which the program costs will be recovered.
In February 2008, the Ameren Illinois Utilities filed a natural gas energy efficiency plan with the ICC. The plan was filed as part of the November 2007 natural gas delivery service rate cases. The Ameren Illinois Utilities proposed to offer natural gas energy efficiency programs in conjunction with a revenue decoupling rate adjustment mechanism. The
natural gas energy efficiency plan includes annual reduction targets in energy usage as well as proposed funding levels for 2009, 2010, and 2011 of $4 million, $5 million and $6 million, respectively. The ICC is expected to issue an order on the Ameren Illinois Utilities’ filing by September 2008.
Federal
Regional Transmission Organization
UE, CIPS, CILCO and IP are transmission-owning members of MISO, which is a FERC-regulated RTO that provides transmission tariff administration services for electric transmission systems. In early 2004, UE received authorization from the MoPSC to participate in MISO for a five-year period, with further participation subject to approvals by the MoPSC. The MoPSC required UE to file a study evaluating the costs and benefits of its participation in MISO prior to the end of the five-year period. The MoPSC also directed UE to enter into a service agreement for MISO to provide transmission service to UE’s bundled retail customers. The service agreement’s primary function was to ensure that the MoPSC continued to set the transmission component of UE’s rates to serve its bundled retail load. In particular, the service agreement provided that UE would not pay MISO for transmission service to UE’s bundled retail customers. FERC approved the service agreement in the form that was acceptable to the MoPSC.
Due to recent changes to MISO’s allocation of transmission revenues to transmission owners, UE believed it should receive incremental annual transmission revenues of $60 million as of February 2008 based on its service agreement with MISO. Numerous transmission owners in MISO, along with MISO itself as the tariff administrator, filed with FERC in December 2007 requesting changes to the MISO tariff to prevent UE from collecting these additional transmission revenues. In December 2007, UE filed a protest to these proposed MISO tariff changes as unauthorized and improper in light of the MoPSC’s requirement for the service agreement between UE and MISO discussed above. In February 2008, FERC issued an order accepting the MISO tariff changes proposed by MISO and transmission owners in MISO. UE intends to request FERC for a rehearing of its order.
As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s filing noted that there were a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement discussed above. If some of these uncertainties are ultimately resolved in a manner adverse to UE, it could call into question whether it is cost-effective for UE to remain in MISO. UE has advised MISO of its intent to withdraw from MISO as of December 31, 2008, in order to preserve the option to withdraw based on the outcome of the pending MoPSC proceeding. It is uncertain when or how the MoPSC will rule on UE’s MISO cost-benefit study or, if UE were to withdraw from MISO, what the effect of such a withdrawal would be on UE.
Seams Elimination Cost Adjustment
Pursuant to a series of FERC orders, FERC put Seams Elimination Cost Adjustment (SECA) charges into effect on December 1, 2004, subject to refund and hearing procedures. The SECA charges were a transition mechanism in place for 16 months from December 1, 2004, to March 31, 2006, to compensate transmission owners in the MISO and PJM for revenues lost when FERC eliminated the regional through-and-out rates previously applicable to transactions crossing the border between the MISO and PJM. The SECA charge was a nonbypassable surcharge payable by load-serving entities in proportion to the benefit they realized from the elimination of the regional through-and-out rates as of December 1, 2004. The MISO transmission owners (including UE, CIPS, CILCO and IP) and the PJM transmission owners filed their proposed SECA charges in November 2004 as compliance filings pursuant to FERC order. A FERC administrative law judge issued an initial decision in August 2006, recommending that FERC reject both of the SECA compliance filings (the filing for SECA charges made by the transmission owners in the MISO and the filing for SECA charges made by the transmission owners in PJM). There is no scheduled date for FERC to act on the initial decision. Both before and after the initial decision, various parties (including UE, CIPS, CILCO and IP as part of the group of MISO transmission owners) filed numerous bilateral or multiparty settlements. FERC has approved many of the settlements. FERC has rejected none of the settlements but a number have been pending for some time. Neither the MISO transmission owners, including UE, CIPS, CILCO and IP, nor the PJM transmission owners have been able to settle with all parties. During the transition period of December 1, 2004 to March 31, 2006, Ameren, UE, CIPS, and IP received net revenues from the SECA charge of $10 million, $3 million, $1 million, and $6 million, respectively. CILCO’s net SECA charges were less than $1 million. Until FERC acts on the pending settlements and issues a final order on the initial decision, we cannot predict the ultimate impact of the SECA proceedings on UE’s, CIPS’, CILCO’s and IP’s costs and revenues.
FERC Order - MISO Charges
In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit, an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants, retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance pending completion of the continuing proceedings at FERC regarding the allocation of these costs. Other MISO participants also filed appeals. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintain that MISO is required to reallocate certain of
MISO’s operational costs among MISO market participants resulting in refunds to UE, CIPS, CILCO, and IP. This request and those of other parties are pending.
UE Power Purchase Agreement with Entergy Arkansas, Inc.
In July 2007, as a consequence of a series of orders issued by FERC addressing a complaint filed by the Louisiana Public Service Commission against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged unjust and unreasonable cost allocations, Entergy commenced billing UE for additional charges under a 165-megawatt power purchase agreement. The additional charges to UE were $12 million in 2007. Additional amounts are expected during the remainder of the term of the power purchase agreement, which expires effective August 25, 2009. Although UE was not a party to FERC proceedings that gave rise to these additional charges, UE intervened in August 2007 in a related FERC proceeding to challenge the additional charges. UE is unable to predict whether FERC will grant any relief.
Leveraged Leases
With the acquisition of CILCORP and the merger with CIPSCO, Ameren acquired interests in certain assets that were financed as leveraged leases. By orders issued pursuant to PUHCA 1935, the SEC determined that certain nonutility interests and investments of CILCORP, CIPSCO and their subsidiaries, including investments in several leveraged leases, which primarily consisted of lease interests in commercial real estate properties and equipment, were not retainable by Ameren. The SEC orders required that Ameren cause its subsidiaries to sell or otherwise dispose of the nonretainable interests. All leveraged leases held by CILCORP and its subsidiaries that were required to be divested by an SEC order were sold by the end of 2006. CILCORP no longer owns any leveraged lease assets. With respect to the leveraged lease asset subject to a SEC divestiture order held by CIPSCO, the lessee of the asset declared bankruptcy and the value of the investment was written off by Ameren in 2005. CIPSCO had two other leveraged lease assets that were not subject to an SEC divestiture order. One of those lease investments was sold in 2007, and one is still owned by CIPSCO.
In 2007, the overall net gain before taxes from the sale of leveraged lease assets recognized by Ameren was $4 million. In 2006, the overall net gains (losses) before taxes from the sale of all leveraged lease assets recognized by Ameren, CILCORP and CILCO were $3 million, ($7 million), and ($11 million), respectively.
Hydroelectric License Renewal
On March 30, 2007, FERC granted a new 40-year license for UE’s Osage hydroelectric plant and approved a settlement agreement among UE, the U.S. Department of the Interior and various state agencies that was submitted in May 2005 in support of the license renewal.
Regulatory Assets and Liabilities
In accordance with SFAS No. 71, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators and are currently recovering such costs in rates charged to customers. The following table presents our regulatory assets and regulatory liabilities at December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
See Note 9 - Retirement Benefits for additional information.
(c)
These assets do not earn a return.
(d)
Amount represents SFAS No. 109 deferred tax asset. See Note 11 - Income Taxes for amortization period.
(e)
Represents recoverable costs for AROs at our rate-regulated operations. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.
(f)
Represents UE’s Callaway nuclear plant operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant’s current operating license through 2024.
(g)
Represents losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
(h)
Represents the recoverable portion of accrued environmental site liabilities, primarily collected from electric and gas customers through ICC-approved cost recovery riders in Illinois.
(i)
Represents reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. Pursuant to the ICC order approving Ameren’s acquisition of IP, these costs are recoverable in rates through 2010.
(j)
Represents a portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP at September 30, 2004. This portion is being amortized over the remaining life of the related debt beginning upon the expiration of the electric rate freeze in Illinois on January 1, 2007.
(k)
Represents deferral of SFAS No. 133 natural gas-related derivative mark-to-market gains.
(l)
Represents a regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order.
(m)
Represents Y2K expenses being amortized over six years starting in 2002, in conjunction with the 2002 settlement of UE’s Missouri electric rate case, and a DOE decommissioning assessment was amortized over 14 years through 2007. In addition, this amount at December 31, 2006, included the portion of merger-related expenses applicable to the Missouri retail jurisdiction, which were amortized through 2007 based on a MoPSC order.
(n)
Represents unamortized portion of investment tax credit and federal excise taxes. See Note 11 - Income Taxes for amortization period.
(o)
Represents estimated funds collected for the eventual dismantling and removing plant from service, net of salvage value, upon retirement related to our rate-regulated operations. See discussion in Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.
(p)
Represents the deferral of gains on emission allowance vintage swaps UE entered into during 2005.
(q)
Represents a regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level of such costs built into electric rates effective June 4, 2007, as approved in a MoPSC order.
(r)
Represents financial contracts entered into by the Ameren Illinois Utilities with Marketing Company, as part of the Illinois electric settlement agreement. See Note 2 - Rate and Regulatory Matters for additional information.
UE, CIPS, CILCO and IP continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered through future revenues.
NOTE 3 -
PROPERTY AND PLANT, NET
The following table presents property and plant, net for each of the Ameren Companies at December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(b)
Includes CILCO (Illinois Regulated) and CILCO (AERG) with adjustments due to purchase accounting.
In March 2006, following the receipt of all required regulatory approvals, UE completed the purchase of a 640-megawatt CT facility located in Audrain County, Missouri, at a price of $115 million 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 UE assumed NRG’s obligations under the lease. The lease will expire on December 1, 2023.
Also in March 2006, following the receipt of all required regulatory approvals, UE completed the purchase from subsidiaries of Aquila Inc., of the 510-megawatt Goose Creek CT facility in Piatt County, Illinois, at a price of $106 million, and the 340-megawatt Raccoon Creek CT facility located in Clay County, Illinois, at a price of $71 million.
NOTE 4 -
CREDIT FACILITIES AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under $2.15 billion of committed bank credit facilities, and commercial paper issuances.
The following table summarizes the borrowing activity and relevant interest rates under the $1.15 billion credit facility described below for the years ended December 31, 2007 and 2006, respectively, and includes issuances under commercial paper programs and letters of credit at Ameren, UE, and Genco supported by this credit facility:
(a)
Includes issuances under commercial paper programs of $80 million at Ameren and UE supported by this facility as of December 31, 2007.
The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit facility described below for the years ended December 31, 2007 and 2006, respectively:
(a)
Amount is less than $1 million
The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit facility described below for the year ended December 31, 2007:
At December 31, 2007, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of the three facilities shown above, in the amounts of $1.15 billion, $500 million, and $500 million maturing in July 2010, January 2010, and January 2010, respectively.
Ameren can directly borrow under the $1.15 billion facility, as amended, up to the entire amount of the facility. UE can directly borrow under this facility up to $500 million on a 364-day basis. Genco can directly borrow under this facility up to $150 million on a 364-day basis. The amended facility will terminate on July 14, 2010, with respect to Ameren. The termination date for UE and Genco is July 10, 2008, subject to the annual 364-day renewal provisions of the facility.
Under the $1.15 billion credit facility, the principal amount of each revolving loan will be due and payable no later than the final maturity of the facility in the case of Ameren and the last day of the then-applicable 364-day period in the case of UE and Genco. Swingline loans will be made on same-day notice and will mature five business days after they are made.
Ameren, UE and Genco will use the proceeds of any borrowings under the facility for general corporate purposes, including for working capital, commercial paper liquidity support, and to fund loans under the Ameren money pool arrangements.
CIPS, CILCORP, CILCO, IP and AERG are parties to a $500 million multiyear, senior secured credit facility expiring in 2010 (the 2006 $500 million credit facility).
CIPS, CILCORP, CILCO, IP and AERG are parties to another $500 million multiyear, senior secured credit facility (the 2007 $500 million credit facility), also expiring in January 2010.
The obligations of each borrower under the 2006 $500 million credit facility and the 2007 $500 million credit facility are several and not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower under the 2006 $500 million credit facility, including for issuance of letters of credit on its behalf, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $75 million, IP - $150 million and AERG - $200 million. Each of the companies has drawn various loans under this credit facility. Under the 2007 $500 million credit facility, the maximum amount available to each borrower, including for issuance of letters of credit on its behalf, is limited as follows: CILCORP - $125 million, CILCO - $75 million, IP - $200 million and AERG - $100 million. CIPS and CILCO have the option of permanently reducing their borrowing authority under the 2006 $500 million credit facility and shifting, in one or more transactions, such capacity to the 2007 $500 million credit facility up to the same limits. The total borrowing authority of CIPS and CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility cannot at any time exceed $135 million and $150 million, respectively, in the aggregate. Until either CIPS or CILCO elects to increase its borrowing capacity under the 2007 $500 million credit facility and issue first mortgage bonds as security for its obligations thereunder, as described below, it will not be considered a borrower under the 2007 $500 million credit facility and will not be subject to the covenants thereof (except as a subsidiary of a borrower). The borrowing companies will use the proceeds of any borrowings for working capital and other general corporate purposes; however, a portion of the borrowings by AERG may be limited to financing or refinancing the development, management and operation of any of its projects or assets. The 2006 and 2007 $500 million credit facilities will terminate on January 14, 2010.
The obligations of CIPS, CILCO and IP under the 2006 $500 million facility are secured by the issuance of mortgage bonds by each such utility under its respective mortgage indenture in the amounts of $135 million, $75 million and $150 million, respectively. The obligations of CILCO and IP under the 2007 $500 million credit facility are secured by the issuance of mortgage bonds in the amounts of $75 million and $200 million, respectively. If CIPS or CILCO elect to transfer borrowing authority from the 2006 $500 million credit facility to the 2007 $500 million credit facility, that company must retire an appropriate amount of first mortgage bonds issued with respect to the 2006 $500 million credit facility and issue new bonds in an equal amount to secure its obligations under the 2007 $500 million credit facility. In July 2007, CILCO permanently reduced its $150 million of borrowing authority under the 2006 $500 million credit facility by $75 million and shifted that amount of capacity to the 2007 $500 million credit facility. CILCO is now considered a borrower under both credit facilities and is subject to the covenants of both. The obligations of CILCORP under both the 2006 $500 million credit facility and the 2007 $500 million credit facility are secured by a pledge of the common stock of CILCO. The obligations of AERG under both the 2006 $500 million credit facility and the 2007 $500 million credit facility are secured by a mortgage and security interest in its E.D. Edwards and Duck Creek power plants and related licenses, permits, and similar rights.
The $1.15 billion credit facility is used to support the commercial paper programs of Ameren and UE. Access to the $1.15 billion credit facility, the 2006 $500 million credit facility, and the 2007 $500 million credit facility for the Ameren Companies is subject to reduction as borrowings are made by affiliates. Ameren and UE are currently limited in their access to the commercial paper market as a result of downgrades in their short-term credit ratings.
Indebtedness Provisions and Other Covenants
The Ameren Companies’ bank credit facilities contain provisions that, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion credit facility contains provisions that limit total indebtedness of each of Ameren, UE and Genco to 65% of total consolidated capitalization pursuant to a calculation defined in the facility. Exceeding these debt levels would result in a default under the $1.15 billion credit facility.
The $1.15 billion credit facility also contains provisions for default, including cross-defaults, with respect to a borrower. Defaults can result from an event of default under any other facility covering indebtedness of that borrower or certain of its subsidiaries in excess of $50 million in the aggregate. The obligations of Ameren, UE and Genco under the facility are several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS, CILCORP, CILCO, AERG and IP are not considered subsidiaries for purposes of the cross-default or other provisions.
Under the $1.15 billion credit facility, restrictions apply limiting investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries by Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries are excluded for purposes of determining compliance with the 65% total consolidated indebtedness to total consolidated capitalization financial covenant in the facility.
Both the 2006 $500 million credit facility and the 2007 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG, limit the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. Events of default under these facilities apply separately to each borrower (and, except in the case of CILCORP, to their subsidiaries), and an event of default under these facilities does not constitute an event of default under the $1.15 billion credit facility and vice versa. In addition, if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below-investment-grade credit rating by either Moody’s or S&P, then each such borrower will be limited to capital stock dividend payments of $10 million per year while such below-investment-grade credit rating is in effect. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured long-term debt credit rating to below investment-grade, causing it to be subject to this dividend payment limitation. No similar restriction applies to AERG, which is currently not rated by Moody’s or S&P, if its debt-to-operating cash flow ratio, as set forth in these facilities, is less than or equal to a 3.0 to 1.0 ratio. As of December 31, 2007, AERG was in compliance with this test in the 2006 $500 million credit facility and the 2007 $500 million credit facility. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2006 $500 million or 2007 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG would be limited by dividend restrictions at CILCORP.
The 2007 $500 million credit facility and the 2006 $500 million credit facility also limit the amount of other secured indebtedness issuable by each borrower. For CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other debt secured by the pledge of CILCO common stock is limited (a) under the 2007 $500 million credit facility to $425 million (in addition to the principal amount of CILCORP’s outstanding senior notes and senior bonds and its obligations under the 2006 $500 million credit facility) and (b) under the 2006 $500 million credit facility to $500 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds and amounts drawn on the 2007 $500 million credit facility). For AERG, other debt secured on an equal basis with its obligations under the facilities is limited to $100 million by the 2007 $500 million credit facility (excluding amounts drawn by AERG under the 2006 $500 million credit facility) and $200 million by the 2006 $500 million credit facility. The limitations on other secured debt at CILCORP and AERG in the 2007 $500 million credit facility are subject to adjustment based on the borrowing sublimits of these entities under this facility or under the 2006 $500 million credit facility. In addition, the 2007 $500 million credit facility and the 2006 $500 million credit facility prohibit CILCO from issuing any preferred stock if, after giving effect to such issuance, the aggregate liquidation value of all CILCO preferred stock issued after February 9, 2007, and July 14, 2006, respectively, would exceed $50 million.
The 2007 $500 million credit facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures (that is, they agree to forgo the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture) in the following amounts (subject to, in the case of CIPS and CILCO, their then current borrowing sublimits under the facility and similar provisions in the 2006 facility): CIPS, prior to December 31, 2007 - $50 million, on and after December 31, 2007, but prior to December 31, 2008 - $100 million, on and after December 31, 2008, but prior to December 31, 2009 - $150 million, on and after December 31, 2009 - $200 million; CILCO, prior to December 31, 2007 - $25 million, on and after December 31, 2007, but prior to December 31, 2008 - $50 million, on and after December 31, 2008, but prior to December 31, 2009 - $75 million, on and after December 31, 2009 - $150 million; and IP, prior to December 31, 2008 - $100 million, on and after December 31, 2008, but prior to December 31, 2009 - $200 million, on and after December 31, 2009 - $350 million.
The 2006 $500 million credit facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures in the following amounts: CIPS, prior to December 31, 2007 - $50 million, on and after December 31, 2007, but prior to December 31, 2008 - $100 million, on and after December 31, 2008 - $150 million; CILCO - $25 million; and IP - $100 million.
Pursuant to a waiver dated November 16, 2007, CIPS was granted relief from complying with the covenant contained in the 2006 and 2007 credit agreements requiring CIPS to reserve future bonding capacity under its mortgage indenture as discussed above. The waiver is scheduled to expire on March 31, 2008.
As of December 31, 2007, the ratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility for Ameren, UE and Genco were 52%, 47% and 46%, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2006 $500 million credit facility and the 2007 $500 million credit facility, were 54%, 58%, 45%, 49% and 39%, respectively.
None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At December 31, 2007, the Ameren Companies were in compliance with their credit facility provisions and covenants.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for operation and administration of the money pool agreements.
Utility
Through the utility money pool, the pool participants may access the committed credit facilities. CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. Although UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. Ameren Services administers the utility money pool and tracks internal and external funds separately. Ameren and AERG may participate in the utility money pool only as lenders. Internal funds are surplus funds contributed to the utility money pool from participants. The primary source of external funds for the utility money pool is the 2006 $500 million and the 2007 $500 million credit facilities. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent that the pool participants have surplus funds or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. CIPS, CILCO and IP rely on the utility money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2007, was 5.80% (2006 - 5.03%).
Non-state-regulated Subsidiaries
Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any time is reduced by borrowings from Ameren made by its subsidiaries and is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. At December 31, 2007, $409 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The non-state-regulated subsidiary money pool was established to coordinate and to provide for short-term cash and working capital requirements of Ameren’s non-state-regulated activities. It is administered by Ameren Services. Borrowers receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. These rates are based on the cost of funds used for money pool advances. Ameren and CILCORP are authorized to act only as lenders to the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2007 was 5.14% (2006 - 4.65%).
See Note 12 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the years ended December 31, 2007, 2006, and 2005.
In addition, a unilateral borrowing agreement exists between Ameren, IP, and Ameren Services, which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million, pursuant to authorization from the ICC. IP is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for operation and administration of the agreements.
NOTE 5 -
LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2007 and 2006:
(a)
At December 31, 2007, most property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued. Substantially all of the long-term debt issued by UE, CIPS (excluding the tax-exempt debt), CILCO and IP is secured by a lien on substantially all of its property and franchises.
(b)
These notes are collaterally secured by first mortgage bonds issued by UE, CIPS, CILCO, or IP, respectively, and will remain secured at each company until the following series are no longer outstanding with respect to that company: UE - 6.75% Series due 2008 and 5.45% Series due 2028 (callable in October 2008 at 102% of par declining to 101% of par in October 2009 and 100% of par in October 2010); CIPS - 7.61% Series 1997-2 due 2017 (callable in June 2007 at 103.81% of par declining annually thereafter to 100% of par in June 2012); CILCO - 7.50% Series due 2007, 6.20% Series 1992B due 2012 (currently callable at 100% of par) and 5.90% Series 1993 due 2023 (currently callable at 100% of par); IP - 7.50% Series due 2009 and all IP pollution control revenue bonds.
(c)
Environmental improvement or pollution control series secured by first mortgage bonds. In addition, all of the series except UE’s 5.45% series, CILCO’s 6.20% Series 1992B, and 5.90% Series 1993 bonds are backed by an insurance guarantee policy.
(d)
Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. As of December 31, 2007, the interest rates on these securities were being set through an auction-rate mode. Maximum interest rates could range up to 18% depending upon the series of bonds. The average interest rates for the years 2007 and 2006 were as follows:
CIPS’ Series B-1 had a fixed interest rate until November 2006.
(e)
Under the terms of the subordinated debentures, UE may, under certain circumstances, defer the payment of interest for up to five years. Upon the election to defer interest payments, UE dividend payments to Ameren are prohibited. UE has not elected to defer any interest payments.
(f)
Variable-rate tax-exempt pollution control indebtedness that was converted to long-term fixed rates.
(g)
CILCORP’s long-term debt is secured by a pledge of the common stock of CILCO.
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2007:
(a)
Excludes unamortized discount and premium of $6 million, $1 million, $1 million, and $4 million at UE, CIPS, Genco, and IP, respectively.
(b)
Excludes $55 million related to CILCORP’s long-term debt fair market value adjustments.
(c)
Excludes $20 million related to IP’s long-term debt fair market value adjustments and includes $32 million for TFN overfunding.
All of the Ameren Companies expect to fund maturities of long-term debt, short-term debt and contractual obligations through a combination of cash flow from operations and external financing. See Note 4 - Credit Facilities and Liquidity for a discussion of external financing availability.
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for Ameren Companies that have authorized amounts as of December 31, 2007:
Ameren
In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren and its subsidiary trusts covering the offering from time to time of up to $2 billion of various types of securities, including long-term debt, trust preferred securities, and equity securities.
Ameren’s acquisitions of CILCORP and IP resulted in fair value adjustments to long-term debt of $111 million and $195 million, respectively. The fair value adjustments are being amortized to interest expense over the remaining life or to the expected redemption date of each debt issuance. As of December 31, 2007, the remaining unamortized balance of the fair market value adjustments for CILCORP and IP were $55 million and $20 million, respectively.
The following table presents the amortization of the CILCORP and IP fair value adjustments for the succeeding five years:
(a)
Amount is less than $1 million.
In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. Ameren is also selling newly issued shares of common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including subsidiary-related plans that are now merged into the Ameren 401(k) plan), Ameren issued 1.7 million, 1.9 million, and 2.1 million shares of common stock in 2007, 2006, and 2005, respectively, which were valued at $91 million, $96 million, and $109 million for the respective years.
In December 2006, Ameren terminated interest rate swap transactions that were entered into in March 2002 to effectively convert its 5.70% fixed-rate notes to variable rate.
In February 2007, $100 million of Ameren’s 5.70% notes matured and were retired.
In May 2007, $250 million of Ameren’s senior notes matured and were retired.
UE
In March 2006, following the receipt of all required regulatory approvals, UE completed the purchase of a 640-megawatt CT facility located in Audrain County, Missouri. As 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 UE assumed NRG’s obligations under the lease. UE as the lessee is responsible for rental payments under the lease in an amount sufficient to service the debt of a taxable industrial development revenue bond (principal amount of $240 million outstanding as of December 31, 2007) issued to NRG by Audrain County in exchange for title to the NRG CT facility. As part of this
acquisition, UE acquired the bond from NRG. Because rental payments are equal to debt service on the bond, there is no net cash expense relating to this lease. No capital was initially raised in the leasing transaction, and no capital was raised as a result of UE’s assumption of NRG’s lease obligations.
In June 2007, UE issued, pursuant to its October 2005 SEC Form S-3 shelf registration statement, $425 million of 6.40% senior secured notes due June 15, 2017, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2007. UE received net proceeds of $421 million, which were used to repay short-term debt.
In connection with UE’s June 2007 issuance of $425 million of senior secured notes, UE agreed, for so long as those senior secured notes are outstanding, that it will not, prior to June 15, 2012, optionally redeem, purchase or otherwise retire in full its outstanding first mortgage bonds not subject to release provisions, thus causing a first mortgage bond release date to occur. Such release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness ranking equally with any other outstanding senior unsecured indebtedness of UE. UE further agreed that the interest rate for these $425 million of senior secured notes will be subject to an increase of up to a maximum of 2.00% if such release date occurs between June 15, 2012, and June 15, 2017 (the maturity date of the $425 million senior secured notes), and if Moody’s or S&P downgrades the rating assigned to these senior secured notes below investment grade as a result of the release within 30 days of such release (subject to extension if and for so long as the rating for such senior secured notes is under consideration for possible downgrade). Any interest rate increase on these senior secured notes will take effect on the first day of the interest period during which such rating downgrade requires an increase in the interest rate.
CIPS
In June 2006, CIPS issued and sold, pursuant to an effective SEC Form S-3 registration statement, $61 million of 6.70% senior secured notes due June 15, 2036, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2006. These notes are secured by first mortgage bonds, which are subject to fallaway provisions, as defined in the related financing agreements. CIPS received net proceeds of $60 million, which were used, along with other funds, to repay in full CIPS’ intercompany note payable to UE.
Also in June 2006, $20 million of CIPS’ 7.05% first mortgage bonds matured and were retired.
In December 2006, CIPS repurchased all $17 million of its Series B-1 Illinois Finance Authority bonds pursuant to a mandatory tender. Interest payments are being made monthly by CIPS. The receivable for this repurchased bond is in Other Current Assets on CIPS’ balance sheet.
See Note 4 - Credit Facilities and Liquidity regarding CIPS agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under the mortgage. As a result of restrictions in the 2007 and 2006 $500 million credit facilities, CIPS can only issue first mortgage bonds based upon retired bond capacity of $3 million and/or to refinance first mortgage bonds currently outstanding.
CILCORP
As discussed above, in conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was increased to fair value by $111 million. Amortization related to fair value adjustments was $6 million, $6 million, and $7 million for the years ended December 31, 2007, 2006, and 2005, respectively, and costs related to repayments were $- million, $2 million, and $8 million for the years ended December 31, 2007, 2006, and 2005, respectively. These amounts were included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.
In March 2006, CILCORP repurchased $2 million in principal amount of its 9.375% senior bonds due 2029, and in April 2006, CILCORP repurchased an additional $7 million in principal amount of these bonds.
See Note 4 - Credit Facilities and Liquidity regarding CILCORP’s pledge of the common stock of CILCO as security for its obligations under the 2006 $500 million credit facility and the 2007 $500 million credit facility.
CILCO
In each of July 2007, July 2006, and July 2005, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. These redemptions satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for each year.
In January 2007, $50 million of CILCO’s 7.50% first mortgage bonds matured and were retired.
In June 2006, CILCO issued and sold, with registration rights in a private placement, $54 million of 6.20% senior secured notes due June 15, 2016, and $42 million of 6.70% senior secured notes due June 15, 2036, both with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2006. These notes are secured by first mortgage bonds, which are subject to fallaway provisions as defined in the related financing agreements. CILCO received total net proceeds of $94 million, which were used to reduce short-term money pool borrowings and, in July 2006, to redeem CILCO’s $20 million 7.73% secured medium-term notes due 2025. CILCO exchanged the outstanding unregistered senior secured notes for registered secured notes on November 16, 2006.
See Note 4 - Credit Facilities and Liquidity regarding CILCO’s agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage and regarding the mortgage and security interest in its power plants issued
by AERG as security for its obligations under the 2006 $500 million credit facility and the 2007 $500 million credit facility.
IP
As discussed above, in conjunction with Ameren’s acquisition of IP, IP’s long-term debt was increased to fair value by $195 million. Amortization related to fair value adjustments was $12 million, $13 million, and $16 million for the years ended December 31, 2007, 2006, and 2005, respectively, and was included in interest expense in the consolidated statements of income of Ameren and IP.
In June 2006, IP issued and sold, with registration rights in a private placement, $75 million of 6.25% senior secured notes due June 15, 2016, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2006. These notes are secured by mortgage bonds, which are subject to fallaway provisions as defined in the related financing agreements. IP received net proceeds of $74 million, which were used to reduce short-term money pool borrowings. IP exchanged the outstanding unregistered senior secured notes for registered secured notes on November 16, 2006.
In November 2007, IP issued and sold, with registration rights in a private placement, $250 million of 6.125% senior secured notes due November 15, 2017, with interest payable semi-annually on May 15 and November 15 of each year, beginning May 15, 2008. These notes are secured by mortgage bonds, which are subject to fallaway provisions as defined in the related financing agreements. IP received net proceeds of $248 million, which were used to repay short-term debt.
See Note 4 - Credit Facilities and Liquidity regarding IP’s agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.
In December 1998, the IP SPT issued $864 million of TFNs, as allowed under the Illinois Electric Utility Transition Funding Law. In accordance with the Transitional Funding Securitization Financing Agreement, IP must designate a portion of the cash received from customer billings to fund payment of the TFNs. The amounts received are remitted to the IP SPT and are restricted for the sole purpose of paying down the TFNs. Due to the adoption of FIN No. 46R and resulting deconsolidation of IP SPT, restricted cash associated with amounts collected is netted against the current portion of IP’s long-term debt payable to IP SPT on IP’s December 31, 2007 and 2006, consolidated balance sheets.
Indenture Provisions and Other Covenants
UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended December 31, 2007, at an assumed interest and dividend rate of 7%.
(a)
Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)
Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by these companies. Amount of bonds issuable based on either meeting required coverage ratios or unfunded property additions, whichever is more restrictive. In addition to these tests, UE, CIPS, CILCO and IP have the ability to issue bonds based upon retired bond capacity of $15 million, $3 million, $175 million and $664 million, respectively, for which no earnings coverage test is required. See Note 4 - Credit Facilities and Liquidity for additional information.
(c)
Coverage required on the annual interest charges on all long-term debt (CIPS only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance.
(d)
In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all mortgage bonds outstanding and to be issued. For the 12 months ended December 31, 2007, CILCO had earnings equivalent to at least 42% of the principal amount of all mortgage bonds outstanding.
(e)
See Note 4 - Credit Facilities and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility.
UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.8 billion of free and unrestricted retained earnings at December 31, 2007.
The IP SPT TFNs contain restrictions that prohibit IP LLC from making any loan or advance to, or certain investments in, any other person. Also, as long as the TFNs are outstanding, the IP SPT shall not, directly or indirectly,
pay any dividend or make any distribution (by reduction of capital or otherwise) to any owner of a beneficial interest in the IP SPT.
Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended December 31, 2007:
(a)
Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt-to-capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters.
(b)
Ratio excludes amounts payable under Genco’s intercompany note to CIPS and must be met for both the prior four fiscal quarters and for the succeeding four six-month periods.
(c)
CILCORP must maintain the required interest coverage ratio and debt-to-capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than to its direct or indirect subsidiaries.
Genco’s ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. In the event CILCORP is not in compliance with these tests, CILCORP may make payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At December 31, 2007, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were B+, Ba2, and BB+, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.
In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2007, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
NOTE 6 -
OTHER INCOME AND EXPENSES
The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
NOTE 7 -
DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, and emission allowances. Price fluctuations in natural gas, fuel, and electricity cause any of the following:
•
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•
market values of fuel and natural gas inventories or purchased power that differ from the cost of those commodities in inventory; or
•
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements.
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and sales exceptions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.
Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the
income statement in the period in which the change occurred. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty.
Cash Flow Hedges
Our risk management processes identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The mark-to-market value of cash flow hedges will continue to fluctuate with changes in market prices up to contract expiration.
We monitor and value derivative positions daily as part of our risk management processes. We use published sources for pricing when possible to mark positions to market. We rely on modeled valuations only when no other method exists.
The following table presents the pretax net gain (loss) for the years ended December 31, 2007, 2006 and 2005, of power hedges included in Operating Revenues - Electric. This pretax net gain (loss) represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions being delivered or settled:
The following table presents the carrying value of all derivative instruments and the amount of pretax net gains on derivative instruments in Accumulated OCI for cash flow hedges as of December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including $15 million in 2008.
(c)
Includes a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at December 31, 2007 was $3 million.
(d)
Includes a loss associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with future debt issuances. The cumulative gain and loss on the interest rate swaps will be amortized over a 10-year period that begins when the debt is issued. The carrying value at December 31, 2007 was $(5) million.
(e)
Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2011.
(f)
Current amounts of $2 million at CIPS, $1 million at CILCO, and $2 million at IP were recorded in Other Current Liabilities at December 31, 2007.
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments being accounted for as cash flow hedges at the Ameren Illinois Utilities and Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the swap are eliminated. See Note 2 - Rate and Regulatory Matters for additional information on these financial contracts.
Other Derivatives
The following table represents the net change in market value for the years ended December 31, 2007, 2006 and 2005, of option and swap transactions used to manage our positions in SO2 allowances, coal, heating oil, and power. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The net change in the market value of power options is recorded in Operating Revenues - Electric, while the net changes in the market value of coal, heating oil, and SO2 options and swaps is recorded as Operating Expenses - Fuel.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Through the market allocation process, UE, CIPS, Genco, CILCO and IP have been granted FTRs associated with the MISO Day Two Energy Market. Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois portion of the market. The FTRs are intended to hedge electric transmission congestion charges related to our delivery of electricity. Depending on the congestion on the electric transmission grid and prices at various points on such grid, FTRs could result in either charges or credits. We use complex grid modeling tools to determine which FTRs we wish to nominate in the FTR allocation process. There is a risk that we may incorrectly model the amount of FTRs we need, and there is the potential that some of the FTR hedges could be ineffective. FTRs are considered derivatives. As of December 31, 2007, the net value of FTRs held by the Ameren Companies was determined to be immaterial.
NOTE 8 -
STOCKHOLDER RIGHTS PLAN AND PREFERRED STOCK
Stockholder Rights Plan
Ameren’s board of directors has adopted a share purchase rights plan designed to assure stockholders of fair and equal treatment in the event of a proposed takeover. The rights are exercisable only if a person or group acquires 15% or more of Ameren’s outstanding common stock or announces a tender offer that would result in ownership by a person or group of 15% or more of the Ameren common stock. Each right will entitle the holder to purchase one one-hundredth of a newly issued preferred share at an exercise price of $180. If a person or group acquires 15% or more of Ameren’s outstanding common stock, each right will entitle its holder (other than such person or members of such group) to purchase, at the right’s then-current exercise price, a number of Ameren’s common shares having a market value of twice such price. In addition, if Ameren is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of Ameren’s outstanding common stock, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price. The acquiring person or group will not be entitled to exercise these rights. These rights expire in October 2008. One right will accompany each new share of Ameren common stock prior to such expiration date.
Preferred Stock
All classes of UE’s, CIPS’, CILCO’s and IP’s preferred stock are entitled to cumulative dividends and have voting rights. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding. CIPS has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding. UE has 7.5 million shares authorized of $1 par value preference stock and CILCO has 2 million shares authorized of no par value preference stock, with no such preference stock outstanding. IP has 5 million shares authorized of no par value serial preferred stock and 5 million shares authorized of no par value preference stock, with no such serial preferred stock and preference stock outstanding. No shares of preference stock have been issued by any of the Ameren Companies.
The following table presents the outstanding preferred stock of UE, CIPS, CILCO and IP that is not subject to mandatory redemption. The preferred stock is entitled to cumulative dividends and is redeemable, at the option of the issuer, at the prices presented as of December 31, 2007 and 2006:
(a)
In the event of voluntary liquidation, $105.50.
(b)
Declining to $100 per share in 2012.
(c)
Ameren purchased 662,924 shares of IP’s preferred stock on September 30, 2004.
The following table presents the outstanding preferred stock of CILCO that is subject to mandatory redemption. The preferred stock is entitled to cumulative dividends and is redeemable, at a determinable price on a fixed date or dates, at the prices presented as of December 31, 2007 and 2006, respectively:
(a)
Beginning July 1, 2003, this preferred stock became redeemable, at the option of CILCO, at $100 per share. A mandatory redemption fund was established on July 1, 2003. The fund provides for the redemption of 11,000 shares for $1.1 million on July 1 of each year through July 1, 2007. On July 1, 2008, the remaining shares outstanding will be retired for $16.5 million.
(b)
In the event of voluntary or involuntary liquidation, the stockholder receives $100 per share plus accrued dividends.
NOTE 9 -
RETIREMENT BENEFITS
We offer defined benefit and postretirement benefit plans covering substantially all employees of UE, CIPS, CILCORP, CILCO, IP, EEI and Ameren Services and certain employees of Resources Company and its subsidiaries, including Genco. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans.
We adopted the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R),” effective December 31, 2006. SFAS No. 158 requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, as an asset or liability in their balance sheets and to recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. Upon adoption, Ameren recorded the unfunded obligation of its defined benefit and postretirement benefit plans. The unfunded obligation is the difference between the projected benefit obligation for defined benefit plans or accumulated postretirement benefit obligation for postretirement benefit plans and each plan’s assets. Ameren’s adoption of SFAS No. 158 resulted in increases (decreases) to Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s accrued pension and other postretirement benefits of $406 million, $234 million, $95 million, $36 million, ($51) million, $55 million and ($8) million, respectively. UE, CIPS and CILCO recorded regulatory assets of $270 million, $108 million and $63 million, respectively, based on the expected recovery of these costs from ratepayers. The adoption of SFAS No. 158 had no material impact on accumulated other comprehensive income at Ameren. CILCORP and IP recognized gains in accumulated other comprehensive income of $29 million and $5 million, respectively, net of taxes, as a result of SFAS No. 158 obligations being reduced from those previously recognized. Genco and CILCO recorded a charge to accumulated other comprehensive income of $25 million and $2 million, respectively, net of taxes.
Investment Strategy and Return on Asset Assumption
The primary objective of the Ameren retirement plan and postretirement benefit plans is to provide eligible employees with pension and postretirement health care benefits. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to earn the highest possible return on plan assets consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. In May 2007, the MoPSC issued an electric rate order for UE that allows UE to recover through customer rates pension expense incurred under GAAP. Ameren expects to fund its pension plans at a level equal to the pension expense. Based on Ameren’s assumptions at December 31, 2007, and reflecting this pension funding policy, Ameren expects annual contributions of $40 million to $65 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 65%, 8%, 11%, 5% and 11%, respectively. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the benefit liability recorded in the balance sheets of each of the Ameren Companies as of December 31, 2007:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The following table presents the funded status of our pension and postretirement benefit plans for the years ended December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
Excludes amounts paid from company funds.
(c)
Not applicable.
None of the plan assets are expected to be returned to Ameren during 2008.
Downgrades of subprime U.S. mortgage-related assets have resulted in a decline in the fair value of subprime-related investments. The Ameren Companies have assessed their investments held in trusts related to Ameren’s pension and postretirement benefit plans and determined that direct exposure to subprime mortgages was not material.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2007 and 2006:
Ameren’s current reconciliation of funded status shows certain amounts that will be recognized as a benefit cost in future years. The unrecognized loss in postretirement benefits is largely a result of declining discount rates over the past several years, higher than expected increases in medical costs, and market losses on plan assets.
The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts and to our postretirement plans during 2007 and 2006.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Ameren determines the discount rate assumptions by utilizing an interest rate yield curve to make judgments pursuant to EITF No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of Postretirement Benefit Plans Other Than Pensions.” The yield curve is based on the yields of more than 500 high-quality, noncallable corporate bonds with maturities between zero and 30 years. A theoretical spot-rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of the Ameren pension plan and postretirement plans and to develop a single-point discount rate matching the plans’ payout structure.
In determining the current year market-related asset value, the prior year market-related value of assets is adjusted by contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years.
The following table presents our target allocations for 2008 and our pension and postretirement plan asset categories as of December 31, 2007 and 2006:
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans during 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2008 are:
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, are as follows:
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2007, 2006 and 2005:
(a)
The Ameren Companies will utilize an expected return on plan assets of 8.25% in 2008.
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren plan covered all eligible employees of the Ameren Companies at December 31, 2007, with the exception of CIPS employees represented by IBEW Local 702 who were covered by a separate 401(k) plan until February 1, 2008. The CIPS-related 401(k) plan was merged into the Ameren plan effective February 1, 2008. The plans allowed employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren and CIPS matched a percentage of the employee contributions up to certain limits. Ameren’s matching contributions to the 401(k) plan totaled $21 million, $19 million and $18 million in 2007, 2006 and 2005, respectively. CIPS’ matching contributions to the CIPS-related 401(k) plan were less than $1 million annually in 2007, 2006 and 2005.
The following table presents the portion of the 401(k) matching contribution to the Ameren plan for each of the Ameren Companies for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 10 -
STOCK-BASED COMPENSATION
Ameren’s long-term incentive plan for eligible employees, called the Long-term Incentive Plan of 1998 (1998 Plan), was replaced prospectively by the 2006 Omnibus Incentive Compensation Plan (2006 Plan) effective May 2, 2006. The 2006 Plan provides for a maximum of 4 million common shares to be available for grant to eligible employees and directors. No new awards may be granted under the 1998 Plan; however, previously granted awards continue to vest or to be exercisable in accordance with their
original terms and conditions. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.
A summary of nonvested shares as of December 31, 2007, and changes during the year ended December 31, 2007, under the 1998 Plan and the 2006 Plan is presented below:
(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in February 2007 under the 2006 Plan.
(b)
Share units vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.
Ameren recorded compensation expense of $18 million, $11 million, and $6 million for the years ended December 31, 2007, 2006, and 2005, respectively, and a related tax benefit of $7 million, $4 million, and $2 million for the years ended December 31, 2007, 2006, and 2005, respectively. As of December 31, 2007, total compensation cost of $20 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of three years.
Performance Share Units
A share unit will vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has achieved certain performance goals and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit will vary from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. If a share unit vests, Ameren will issue the related shares to the employee two years after vesting, but dividends on the shares will be paid to the employee at the same time they are paid to other shareholders.
The fair value of each share unit awarded in February 2007 under the 2006 Plan was determined to be $59.60, based on Ameren’s closing common share price of $53.99 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 4.735%, dividend yields of 2.3% to 5.2% for the peer group, volatility of 12.91% to 18.33% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.
The fair value of each share unit awarded in February 2006 under the 1998 Plan was determined to be $56.07, based on Ameren’s closing common share price of $50.69 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 4.65%, dividend yields of 2.3% to 4.6% for the peer group, volatility of 13.87% to 22.45% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period. The fair value of each share unit granted in May 2006 under the 2006 Plan was determined to be $56.07, according to assumptions similar to those applied to the February 2006 grant.
Restricted Stock
Restricted stock awards in Ameren common stock were granted under the 1998 Plan from 2001 to 2005. Restricted shares have the potential to vest over a seven-year period from the date of grant if the company achieves certain performance levels. An accelerated vesting provision included in this plan reduces the vesting period from seven years to three years if the earnings growth rate exceeds a prescribed level. During 2005, 154,086 restricted stock awards were granted. The weighted-average fair value for restricted stock awards granted was $51.21 per share in 2005. We record compensation expense over the vesting period.
Stock Options
Ameren
Options in Ameren common stock were granted under the 1998 Plan at a price not less than the fair-market value of the common shares at the date of grant. Granted options vest over a period of five years, beginning at the date of grant, and they permit accelerated exercising upon the occurrence of certain events, including retirement. There have not been any stock options granted since December 31, 2000. Outstanding options of 89,987 at December 31, 2007, expire on various dates through 2010. There is no expense
from stock options for the years ended December 31, 2007 and 2006, as all options granted were fully vested.
NOTE 11 -
INCOME TAXES
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2007, 2006 and 2005:
(a)
Permanent items are treated differently for book and tax purposes and primarily include Internal Revenue Section 199 production activity deductions for Ameren, UE, Genco, CILCORP and CILCO, company-owned life insurance for Ameren, CILCORP and CILCO, SFAS No. 106-2 Medicare Part D for Ameren, UE, CILCORP and CILCO and employee stock ownership plan dividends for Ameren.
(b)
Primarily includes low-income housing and other tax credits for Ameren, UE, CIPS, CILCORP, Genco and IP.
(c)
The 2006 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from tax benefits from permanent effects of company owned life insurance ($1 million), the Section 199 deduction ($1 million), plant-related depreciation differences ($2 million), investment tax credit amortization ($1 million), adjustments to reserves for uncertain tax positions ($6 million), reconciliation of tax return to accrual ($2 million), leveraged leases ($1 million) and state tax impact of $1 million. The 2005 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from tax benefits from plant-related depreciation differences ($2 million), low-income housing credits ($1 million), and investment tax credit amortization ($1 million) that were partially offset by prior-period tax matters ($1 million).
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Includes $61 million, $21 million, $8 million, $17 million, $7 million, and $13 million as current assets recorded in the consolidated balance sheet for Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $7 million as current liabilities recorded in the consolidated balance sheet for Genco.
(c)
Includes $30 million, $17 million, $7 million, $8 million, $7 million and $6 million as current assets recorded in the consolidated balance sheet for Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $5 million as current liabilities recorded in the consolidated balance sheet for Genco.
Ameren, Genco, CILCORP and IP have Illinois net operating loss carryforwards of $91 million, $8 million, $59 million, and $21 million, respectively. These will begin to expire in 2016.
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of SFAS No. 109 (FIN 48)
On January 1, 2007, the Ameren Companies adopted the provisions of FIN 48, which addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. The amounts of unrecognized tax benefits as of January 1, 2007, were $155 million, $58 million, $15 million, $36 million, $18 million, $18 million, and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP, respectively. These unrecognized tax benefits, if recognized, would have had the following impacts on the respective company’s tax rate: Ameren - $20 million, UE - $6 million, CIPS - less than $1 million, Genco - less than $1 million, CILCORP - less than $1 million, CILCO - less than $1 million, and IP - none.
A reconciliation of the change in the unrecognized tax benefit balance from January 1, 2007 to December 31, 2007, is as follows:
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest and penalties accrued on tax liabilities on a gross basis as interest expense or miscellaneous expense in the statements of income. Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis. As of January 1, 2007, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had recorded liabilities of $12 million, $5 million, less than $1 million, $4 million, $1 million, less than $1 million, and less than $1 million, respectively, for the payment of interest with respect to unrecognized tax benefits and no amount for penalties with respect to unrecognized tax benefits.
A reconciliation of the change in the accrued interest balance from January 1, 2007 to December 31, 2007, is as follows:
As of December 31, 2007, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.
The Ameren Companies are no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for years before 2002. The Ameren Companies are currently under federal income tax return examination for years 2002 through 2005. State income tax returns are generally subject to examination for a period of three years after filing. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies also do not now have material state income tax issues under examination, administrative appeals, or litigation.
It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to decrease by $28 million, $14 million, less than $1 million, $10 million, $4 million, $4 million and less than $ million, respectively; however, the Ameren Companies do not believe such decreases would be material to their results of operations.
NOTE 12 -
RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. Below are the material related party agreements.
Illinois Electric Settlement Agreement
See Note 2 - Rate and Regulatory Matters and Note 13 - Commitments and Contingencies for information on the Illinois electric settlement agreement reached in July 2007 and reflected in legislation, enacted on August 28, 2007, that addresses electric rate increases and the future power procurement process in Illinois. As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make contributions of $150 million as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At December 31, 2007, CIPS, CILCO, and IP had receivable balances from Genco for reimbursement of customer rate relief of $2 million, $1 million, and $3 million, respectively. Also at December 31, 2007, CIPS, CILCO, and IP had receivable balances from AERG for reimbursement of customer rate relief of $1 million, $1 million, and $1 million, respectively. In addition, as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock in energy prices for a portion of their around-the-clock power requirements from 2008 to 2012 at relevant market prices. These financial contracts became effective on August 28, 2007. See also Note 7 - Derivative Financial Instruments for additional information on the financial contracts.
Electric Power Supply Agreements
The following table presents the amount of gigawatthour sales under related party electric power supply agreements for the years ended December 31, 2007, 2006, and 2005:
(a)
These agreements expired or terminated on December 31, 2006.
(b)
In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into new power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and all the associated energy commencing on January 1, 2007.
(c)
In accordance with a January 2006 ICC order, an auction was held in September 2006 to procure power for CIPS, CILCO and IP after their previous power supply contracts expired on December 31, 2006. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide a portion of the power requirements of their customers.
Under two electric power supply agreements, which expired or terminated December 31, 2006, Genco was obliged to supply power to Marketing Company. Marketing Company, in turn, was obliged to supply to CIPS all of the
energy and capacity CIPS needed to offer service for resale to its native load customers at ICC-regulated rates and to fulfill its other obligations under all applicable federal and state tariffs or contracts. Any power not used by CIPS was sold by Marketing Company under various long-term wholesale and retail contracts.
In October 2003, AERG entered into an electric power supply agreement to supply CILCO with sufficient power to meet its native load requirements. Also, a bilateral power supply agreement was entered into between AERG and Marketing Company: AERG agreed to sell excess power to Marketing Company for sales outside the CILCO control area, and Marketing Company agreed to sell power to AERG to fulfill CILCO’s native load requirements. These agreements expired at the end of 2006.
In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco agreed to sell and Marketing Company to purchase all of the capacity available from Genco’s generation fleet and all the associated energy. The Genco PSA provides that Marketing Company shall pay, for each megawatthour of associated energy delivered by Genco and purchased by Marketing Company during the month of delivery, an “energy charge.” The “energy charge” is calculated by taking Marketing Company’s gross revenues with respect to power purchased from Genco and AERG in a particular month and subtracting the monthly capacity charge assessed on Marketing Company by Genco and AERG pursuant to the Genco PSA and the AERG PSA (as defined below), respectively. This produces the monthly net revenues. From the monthly net revenues, all administrative and general, transmission, purchased power, and other expenses are subtracted (excluding those expenses that do not support in whole or in part the gross revenue associated with Genco’s generation pursuant to the Genco PSA or AERG’s generation pursuant to the AERG PSA). This amount is then divided by the total number of megawatthours generated by Genco and AERG to determine the per megawatthour “energy charge.” The Genco PSA also provides that Marketing Company shall pay a “monthly capacity charge.” The formula for determining the “monthly capacity charge” is based on the monthly fixed cost of operating the generation fleet of Genco and AERG.
Also in December 2006, AERG and Marketing Company entered into a power supply agreement (AERG PSA) whereby AERG agreed to sell and Marketing Company to purchase all of the capacity available from AERG’s generation fleet and all the associated energy. The calculations of the energy charge and the monthly capacity charge under this agreement are substantively identical to those described above with respect to the Genco PSA. Both the Genco PSA and the AERG PSA commenced 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 by providing the other party with no less than six months advance written notice.
In accordance with a January 2006 ICC order, an auction was held in September 2006 to procure power for CIPS, CILCO and IP beginning January 1, 2007. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for residential and small commercial customers (less than one megawatt of demand) as follows:
(a)
Before impact to Ameren Illinois Utilities’ load due to customer switching.
Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for large commercial and industrial customers (one megawatt of demand or higher) as follows. Nearly all of these customers switched to other suppliers as a result of the auction price.
(a)
Before impact to Ameren Illinois Utilities’ load due to customer switching.
See Note 2 - Rate and Regulatory Matters for a discussion of changes in the Illinois power procurement process as a result of the Illinois electric settlement agreement.
UE, CIPS, IP and a nonaffiliated company were parties to a power supply agreement with EEI to purchase and sell capacity and energy. This agreement expired on December 31, 2005. Under a separate agreement that also expired on December 31, 2005, CIPS resold its entitlements under the agreement with EEI to Marketing Company. Marketing Company and certain nonaffiliated companies were also parties to a power supply agreement with a subsidiary of EEI, to purchase capacity and energy. This agreement was terminated effective December 31, 2005. In December 2005, Marketing Company entered into a power supply agreement with EEI, effective January 2006, whereby EEI sells 100% of its capacity and energy to Marketing Company. This agreement expires on December 31, 2015.
UE had a 150-megawatt power supply agreement with Marketing Company that expired May 31, 2005. Power supplied by Marketing Company to UE through this agreement was obtained from Genco.
In December 2004, Marketing Company and IP entered into an agency agreement that authorized Marketing Company, on behalf of IP, to sell or purchase, as necessary, electric energy and capacity in the wholesale market for 2005 and 2006.
Interconnection and Transmission Agreements
UE, CIPS and IP are parties to an interconnection agreement for the use of their respective transmission lines and other facilities for the distribution of power. In addition, CILCO and IP, and CILCO and CIPS, are parties to similar interconnection agreements. These agreements have no contractual expiration date, but may be terminated by any party with three years’ notice.
Joint Dispatch Agreement
Prior to December 31, 2006, UE and Genco jointly dispatched electric generation under a joint dispatch agreement among UE, CIPS and Genco. UE and Genco had the option to serve their load requirements from their own generation first, and then each could give its affiliates access to any available generation at incremental cost. Any excess generation not used by UE or Genco to serve load requirements was sold to third parties on a short-term basis. To allocate power costs between UE and Genco, an intercompany sale was recorded by the company sourcing the power to the other company. In January 2006, the allocation methodology in the JDA for margins on short-term sales of excess generation to third parties between UE and Genco was modified, and in July 2006, UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement of the JDA. They agreed to terminate it on December 31, 2006.
The following table presents the amount of gigawatthour sales under the JDA.
The following table presents the short-term power sales margins under the JDA for UE and Genco.
Support Services Agreements
Costs of support services provided by Ameren Services, AFS, and Ameren Energy Inc., until December 31, 2007, to their affiliates, including wages, employee benefits, professional services, and other expenses are based on, or are an allocation of, actual costs incurred.
Executory Tolling, Gas Sales, and Transportation Agreements
Under an executory tolling agreement, CILCO purchases steam, chilled water, and electricity from Medina Valley. In connection with this agreement, Medina Valley purchases gas to fuel its generating facility from AFS under a fuel supply and services agreement.
Under a gas transportation agreement, Genco acquires gas transportation service from UE for its Columbia, Missouri, CTs. This agreement expires in February 2016.
Transitional Funding Securitization Financing Agreement
See Note 1 - Summary of Significant Accounting Policies for further information.
Money Pools
See Note 5 - Long-term Debt and Equity Financings for discussion of affiliate borrowing arrangements.
Intercompany Promissory Notes
On May 1, 2005, Genco and CIPS amended the maturity date and interest rate of the subordinated note payable to CIPS. The note payable to CIPS was issued in conjunction with the transfer of CIPS’ electric generating assets and related liabilities to Genco. Genco issued to CIPS an amended and restated subordinated promissory note in the principal amount of $249 million with an interest rate of 7.125% per year, a five-year amortization schedule, and a maturity date of May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $10 million, $12 million, and $15 million for the years ended December 31, 2007, 2006, and 2005, respectively.
Also on May 1, 2005, the remaining principal balance under Genco’s note payable to Ameren of $34 million was repaid. Genco recorded interest expense of $1 million from this note payable to Ameren for the year ended December 31, 2005.
On May 2, 2005, CIPS issued to UE a subordinated promissory note in the principal amount of $67 million as consideration for 50% of UE’s Illinois-based utility assets transferred to CIPS on that date. The note bore interest of 4.70% per year and had a five-year amortization schedule and a maturity date of May 2, 2010. In June 2006, CIPS repaid in full the remaining balance under this note. UE and CIPS recorded interest income and expense, respectively, of $1 million and $2 million for the years ended December 31, 2006 and 2005, respectively.
CILCORP had outstanding borrowings directly from Ameren of $2 million and $73 million at December 31, 2007 and 2006, respectively. The average interest rate on these borrowings was 5.14% for the year ended December 31, 2007 (2006 - 4.65%). CILCORP recorded interest expense of $- million, $7 million, and $6 million for these borrowings for the years ended December 31, 2007, 2006 and 2005 respectively.
Operating Leases
Under an operating lease agreement, Genco leased certain CTs at a Joppa, Illinois, site to its former parent, Development Company, for an initial term of 15 years, expiring September 30, 2015. Genco recorded operating revenues from the lease agreement of $11 million, $11 million, and $10 million for the three years ended December 31, 2007, 2006, and 2005, respectively. Under an electric power supply agreement with Marketing Company,
Development Company supplied the capacity and energy from these leased units to Marketing Company, which in turn supplied the energy to Genco. By mutual agreement of the parties, this lease agreement and power supply agreement was terminated in February 2008, when an internal reorganization merged Development Company into Resources Company.
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the years ended December 31, 2007, 2006 and 2005. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 - Credit Facilities and Liquidity.
(a)
Amounts represent CILCORP and CILCO activity.
(b)
Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
(c)
Not applicable.
(d)
Amount less than $1 million.
NOTE 13 -
COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental 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 these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2007. The property coverage and the nuclear liability coverage were renewed on October 1, 2007 and January 1, 2008, respectively.
(a)
Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b)
Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $15 million per year.
(c)
Limit of liability for each incident under Price-Anderson. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d)
Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e)
Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.
(f)
Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 12 - Related Party Transactions for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.
After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.
Leases
The following table presents our lease obligations at December 31, 2007:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
See Note 5 - Long-term Debt and Equity Financings for further discussion. See also Properties under Part I, Item 2 of this report for further information.
(c)
Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $1 million annual obligation for these items is included in the Less than 1 Year, 1-3 Years, and 3-5 Years columns. Amounts for After 5 Years are not included in the total amount because that period is indefinite.
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. We also have capital leases relating to UE’s Peno Creek and Audrain County CT facilities. See Note 5 - Long-term Debt and Equity Financings for additional information on the Audrain County lease. The following table presents total rental expense, included in other operations and maintenance expenses, for the years ended December 31, 2007, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Other Obligations
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, and nuclear fuel. We also have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. The following table presents the total estimated fuel, power, and natural gas commitments at December 31, 2007. In addition, the following table presents in the Other column heavy forgings contracts, meter reading contracts and an Ameren tax credit obligation. Ameren’s tax credit obligation is a $75 million note payable issued for an investment in a low-income real estate development partnership to acquire New Markets Tax Credits. This note payable
was netted against the related investment in Other Assets at December 31, 2007, as Ameren has a legally enforceable right to offset under FIN 39.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Commitments for natural gas and nuclear fuel are until 2031 and 2020, respectively.
(c)
At December 31, 2007, less than $1 million of electric capacity contracts were executed for the Ameren Illinois Utilities with approximately 23% of the capacity resources dedicated to CIPS, 7% to CILCO, and 70% to IP. These capacity purchases were made to serve real-time pricing customers (one megawatt of demand or higher). The majority of the electric capacity for the Illinois utilities was obtained through the Illinois power procurement auction. See below for additional information.
(d)
Commitments for natural gas purchases for CILCO and IP include projected natural gas purchases pursuant to a 20-year supply contract beginning in April 2011. Purchases under this contract will be passed through to utility customers under the PGA.
Commencing January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who did not purchase electric supply from third-party suppliers in the Illinois reverse power procurement auction held in September 2006. As part of the Illinois electric settlement agreement, the reverse auction used for power procurement was discontinued and replaced with a new power procurement process to be led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary power and energy requirements not already supplied through the September 2006 auction contracts, primary through a request-for-proposal process, subject to ICC review and approval. Existing supply contracts from the September 2006 auction remain in place. See Note 2 - Rate and Regulatory Matters for additional information.
CIPS, CILCO and IP entered into power supply contracts with winning bidders of the Illinois power procurement auction held in September 2006. The power supply contracts stipulate terms of 17 months, 29 months, and 41 months to serve the electric load requirements of fixed-price residential and small commercial customers (with less than one megawatt of demand) commencing January 1, 2007. CIPS, CILCO and IP obtained 17-month-term electric power supply contracts with winning bidders in the auction to serve the load requirements of commercial and industrial fixed-price customers (with one megawatt or greater demand) commencing January 1, 2007. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve the load of customers at an all-inclusive fixed price.
Through the Illinois auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads for residential and small commercial customers (less than one megawatt of demand) as follows:
(a)
Represents peak forecast load for CIPS, CILCO and IP. Actual load could be different if customers elect not to purchase power pursuant to the power procurement auction but instead to receive power from a different supplier. Load could also be affected by weather, among other things.
Through the Illinois auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads for large commercial and industrial customers (one megawatt of demand or higher) as follows:
(a)
Actual load could be different because of weather, among other things.
The Illinois electric settlement agreement provides approximately $1 billion of funding over a four-year period that commenced in 2007 for rate relief for certain electric customers in Illinois. Funding for the settlement will come from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following contributions remain to be made at December 31, 2007:
(a)
Estimated.
Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock-in energy prices for 400 to 1,000 megawatts annually of their around-the-
clock power requirements from 2008 to 2012. See Note 2 - Rate and Regulatory Matters for additional information.
At this time, UE does not expect to require new baseload generation capacity until 2018 to 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. During the second quarter of 2007, UE entered into a commitment to purchase heavy forgings needed to construct a nuclear plant. This commitment does not mean a decision has been made to build a nuclear plant. The purpose of the purchase commitment was to secure access to heavy forgings, which are long-lead-time materials, in the event that UE decides to build a nuclear plant. As of December 31, 2007, UE’s commitments to purchase heavy forgings totaled $84.5 million through 2010 ($6.5 million in 2008, $7.5 million in 2009, and $70.5 million in 2010). They are included in the other obligations table above.
Environmental Matters
We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations. The more significant matters are discussed below.
Clean Air Act
The EPA issued final SO2, NOx and mercury emission regulations in May 2005. The Clean Air Interstate Rule and the Clean Air Mercury Rule require significant reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. States have finalized rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule. Although the federal rules mandate a specific cap for SO2, NOx and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and it may implement a more stringent program than the federal program. Illinois has finalized rules to implement the federal Clean Air Interstate Rule program that will reduce the number of NOx allowances automatically allocated to Genco’s, AERG’s and EEI’s plants. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution control equipment. Current plans include the installation of scrubbers for SO2 reduction and selective catalytic reduction (SCR) systems for NOx reduction at certain coal-fired plants in Illinois. Missouri rules, which substantially follow the federal regulations and became effective in April 2007, and approved by the EPA in December 2007, are expected to reduce mercury emissions 81% by 2018, and NOx emissions 30% and SO2 emissions 75% by 2015. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. Current plans include the installation of scrubbers for SO2 reduction and co-benefit reduction of mercury and pollution control equipment designed to reduce mercury emissions at certain coal-fired plants in Missouri.
Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. In 2009, Genco, AERG and EEI expect to begin putting into service equipment designed to reduce mercury emissions. These rules, when fully implemented, are expected to reduce mercury emissions 90%, NOx emissions 50%, and SO2 emissions 70% by 2015 in Illinois.
In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that effectively vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The Court’s decision is subject to appeal and it is uncertain how the EPA will respond. At this time, we are unable to determine the impact that this action would have on our estimated expenditures for compliance with environmental rules, our results of operations, financial position, or liquidity.
The table below presents estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air Mercury Rule through 2017 and related state implementation plans. The estimates described below could change depending upon additional federal or state requirements, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with the proposed rules, thereby deferring capital investment.
(a)
UE’s expenditures are expected to be recoverable in rates over time.
Illinois and Missouri must also develop attainment plans to meet the federal eight-hour ozone ambient standard, the federal fine particulate ambient standard, and the Clean Air Visibility rule. Both states have filed ozone attainment plans for the St. Louis area. The state attainment plans for fine particulate matter must be submitted to the EPA by April 2008. The plans for the Clean Air Visibility rule were submitted in December 2007. The costs in the table assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet these new standards in the St. Louis region. Should Missouri develop an alternative plan to comply with these standards, the cost impact could be material to UE, but we would expect these costs to be recoverable from ratepayers. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for ozone and fine particulate matter. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.
The impact of future initiatives related to greenhouse gas emissions and global warming on us are unknown and therefore not included in the estimated environmental expenditures. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, or liquidity.
Emission Allowances
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act, under the Acid Rain Program and NOx Budget Trading Programs, created marketable commodities called allowances. Currently each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program has applied to all electric generating units in Illinois since the beginning of 2004; it was applied to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low-NOx burners, over-fire air systems, combustion optimization, rich-reagent injection, selective noncatalytic reduction, and selective catalytic reduction systems.
The following table presents the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that are carried as intangible assets as of December 31, 2007.
(a)
Vintages are from 2007 to 2017. Each company possesses additional allowances for use in periods beyond 2017. Units are in millions of SO2 allowances (currently one allowance equals one ton emitted).
(b)
Vintages are from 2007 to 2008. Units are in NOx allowances (one allowance equals one ton emitted).
(c)
Includes value assigned to EEI allowances as a result of purchase accounting of $29 million.
UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. The Clean Air Interstate Rule program will require that SO2 allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO2 allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG, and EEI expect to install control technology designed to further reduce SO2 emissions, as discussed above.
The Clean Air Interstate Rule will have both an annual program and an ozone season program for regulating NOx emissions, with separate allowances issued for each program. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. UE, Genco, AERG and EEI expect to be allocated NOx allowances for both programs in Illinois in 2008.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. Ameren believes that currently proposed legislation can be classified as moderate to extreme depending upon proposed CO2 emission limits, the timing of implementation of these limits, and the method of allocating
allowances. The moderate scenarios include provisions for a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of carbon dioxide, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. When consumed natural gas emits about half the amount of CO2 as coal. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also would affect the cost of nonelectric transportation, heating for our customers and many industrial processes. Under some policy scenarios being considered by Congress, Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. The costs to comply with future legislation or regulations could be so expensive that Ameren and other similarly situated electric power generators may be forced to close some coal-fired facilities. 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.
In April 2007, the U.S. Supreme Court issued a decision that determined that the EPA has the authority to regulate carbon dioxide and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” As a result, the EPA could begin to regulate such emissions.
Ameren has taken actions to address the global climate issue. These include implementing efficiency improvements at our power plants; participating in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage in the lower Mississippi valley to sequester carbon; using coal combustion by-products as a direct replacement for cement, thereby reducing carbon emissions at cement kilns; participating in “Missouri Schools Going Solar,” a project that will install photovoltaic solar arrays on school grounds; and partnering with other utilities, the Electric Power Research Institute, and the Illinois State Geological Survey in the DOE Illinois Basin Initiative, which will examine the feasibility and methods of storing CO2 within deep unused coal seams, mature oil fields, and saline reservoirs.
The impact on us of future initiatives related to greenhouse gas emissions and global warming is unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state, where our Non-rate-regulated Generation coal-fired plants are located, greenhouse gas program could have a material impact on our future results of operations, financial position, or liquidity.
Clean Water Act
In July 2004, the EPA issued rules under the Clean Water Act that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts on aquatic species. These rules pertain to all existing generating facilities that currently employ a cooling-water intake structure whose flow exceeds 50 million gallons per day. The rules may require us to install additional intake screens or other protective measures and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our facilities. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit remanded many provisions of these rules to the EPA for revision. Until the EPA reissues these rules and the studies on the power plants are completed, we will be unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2010.
New Source Review
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 (NSR) 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 performed.
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 power plants. We are currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Resolution of these matters could have a material adverse impact on the future results of operations, financial position or liquidity of Ameren, Genco, AERG and EEI. A resolution could result in increased capital expenditures, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would likely require the installation of control technology, some of which is already planned for compliance with other regulatory requirements such as the Clean Air Interstate Rule and the Illinois mercury rules.
Remediation
We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of degree of fault, legality of original disposal, or ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.
As of December 31, 2007, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 14, CILCO four, and IP 25. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of December 31, 2007, estimated obligations were: CIPS - $24 million to $42 million, CILCO - $5 million to $8 million, IP - $76 million to $171 million. CIPS, CILCO and IP also recorded liabilities of $24 million, $5 million, and $76 million, respectively, to represent estimated minimum obligations as no other amount within the range is a better estimate at this time.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. See Note 2 - Rate and Regulatory Matters for information on a Missouri law enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of December 31, 2007, UE estimated its obligation at $5 million to $13 million. UE recorded $5 million to represent its estimated minimum obligation for its MGP sites as no other amount within the range is a better estimate at this time. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates. As of December 31, 2007, UE estimated its obligation at $4 million to $17 million. UE recorded $4 million to represent its estimated minimum obligation for these sites as no other amount within the range is a better estimate at this time. We are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.
In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties (PRPs) to evaluate the extent of potential contamination with respect to Sauget Area 2.
Sauget Area 2 investigation activities under the oversight of the EPA are largely completed, and the results will be submitted to the EPA by the third quarter of 2008. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection.
In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $2 million at December 31, 2007, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.
In addition, our operations, or those of our predecessor companies, involve the use, disposal of and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our results of operations, financial position, or liquidity.
Polychlorinated Biphernals Information Request
Polychlorinated biphernals (PCBs) are a blend of chemical compounds that were historically used in a variety of industrial products because of their chemical and thermal stability. In natural gas systems, PCBs were used as a compressor lubricant and a valve sealant before their sale for these applications was banned by the EPA in 1979. During the third quarter of 2007, the Ameren Illinois Utilities received requests from the Illinois attorney general and the EPA for information regarding its experiences with PCBs in its gas distribution system. The Ameren Illinois Utilities have responded to these information requests.
The Ameren Illinois Utilities have evaluated their gas distribution systems. They believe that the presence of PCBs is limited to discrete areas and is not widespread throughout its service territories. We cannot predict whether any further actions will be required on the part of the Ameren Illinois
Utilities regarding this matter or what the ultimate outcome will be.
Pumped-storage Hydroelectric Facility Breach
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.
In October 2006, FERC approved a stipulation and consent agreement between UE and FERC’s Office of Enforcement that resolved all issues arising from an investigation conducted by FERC’s Office of Enforcement 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 paid a civil penalty of $10 million, paid $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and implemented a new dam safety program in connection with the settlement.
In February 2007, UE submitted to FERC an environmental report to rebuild the upper reservoir at its Taum Sauk plant. UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant in August 2007 and hired a contractor in November 2007. The estimated cost to rebuild the upper reservoir is in the range of $450 million. UE expects the Taum Sauk plant to be out of service through at least the fall of 2009.
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 suit, which was filed in the Missouri Circuit Court of St. Louis and subsequently transferred to the Circuit Court of Reynolds County, alleged 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 of Reynolds County and remains pending, contains similar allegations and seeks damages relating to business losses, lost profit, and unspecified punitive damages.
In November 2007, UE entered into a settlement agreement with the state of Missouri represented by the Missouri Attorney General, the Missouri Conservation Commission and the Missouri Department of Natural Resources that resolved the state of Missouri’s lawsuit and claims for damages and other relief related to the December 2005 Taum Sauk breach. The $177 million settlement agreement included cash payments to various state funds. In addition, pursuant to the settlement agreement, UE is required to replace the breached upper reservoir at the Taum Sauk pumped-storage hydroelectric plant with a new upper reservoir, subject to authorization by FERC, which was received in August 2007. The Circuit Court of Reynolds County approved the settlement agreement through a consent judgment in January 2008.
As part of the settlement agreement, UE agreed that it will not attempt to recover from ratepayers in any future rate increase any in-kind or monetary payments to the state parties required by the settlement agreement or costs incurred in the reconstruction of the new upper reservoir (expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that are currently not reasonably foreseeable and costs that would have been incurred absent the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant).
At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the reservoir will range from $199 million to $219 million. As of December 31, 2007, UE had paid $96 million and accrued a $103 million liability, including costs resulting from the FERC-approved stipulation and consent agreement discussed above, while expensing $32 million and recording a $167 million receivable due from insurance companies. As of December 31, 2007, UE had received $89 million from insurance companies, which reduced the insurance receivable balance to $78 million. As of December 31, 2007, UE had a $121 million receivable due from insurance companies related to the rebuilding of the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.
In September 2007, the Missouri Coalition for the Environment, the Sierra Club, and American Rivers filed a motion to seek intervention and rehearing and a stay of FERC authorization granted to UE to rebuild the upper reservoir at its Taum Sauk plant. In December 2007, FERC granted intervention, denied rehearing, and dismissed the request for stay. In February 2008, the Missouri Coalition for the Environment and the Missouri Parks Association filed an appeal of FERC’s decision with the U.S. Court of Appeals for the Eighth Circuit. We are unable to predict how or when the Court of Appeals will rule on this appeal.
In December 2007, the Missouri Parks Association filed a lawsuit in the U.S. District Court for the District of Columbia against UE and FERC to stop the reconstruction of the upper reservoir at the Taum Sauk plant. The Missouri Parks Association claims that FERC failed to adequately study the environmental effect of reopening the hydroelectric plant or alternatives to rebuilding it. In January 2008, UE filed a motion to dismiss the lawsuit, arguing that the U.S. District Court lacks jurisdiction over the subject matter of the case. This motion is currently pending.
Until litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Mechanics’ Liens
Approximately 20 mechanics’ liens were filed by various subcontractors who provided labor or material for a 2007 planned maintenance outage at the Duck Creek facility of CILCO subsidiary, AERG. The total lien claim amount was $26 million plus interest at December 31, 2007. In November 2007, the primary subcontractor on the project filed a complaint for foreclosure of its mechanic’s lien of $19 million plus interest against AERG in the Circuit Court of Fulton County, Illinois. AERG believes it has paid the general contractor the amount due in full (less a contract-allowed holdback of $4 million), and since this arose out of a contract dispute between the general contractor and the primary subcontractor, AERG is currently considering its potential remedies against the general contractor. At this time, we are unable to predict the impact of these liens and lawsuit on CILCO’s or AERG’s future results of operations, financial position, or liquidity.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 189 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of December 31, 2007, the average number of parties was 70.
The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages, which, if awarded at trial, typically would be shared among the various defendants.
From October 1, 2007, through December 31, 2007, six additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the circuit court of Madison County, Illinois. Seven lawsuits were settled. The following table presents the status as of December 31, 2007, of the asbestos-related lawsuits that have been filed against the Ameren Companies:
(a)
Totals do not equal to the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
As of December 31, 2007, nine asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.
IP has a tariff rider 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 are recoverable by IP from a trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. At December 31, 2007, the trust fund balance was $22 million, including accumulated interest.
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.
The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.
NOTE 14 -
CALLAWAY NUCLEAR PLANT
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2017. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.
Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. UE intends to submit a
license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will then be decommissioned by immediate dismantlement and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. See Note 1 - Summary of Significant Accounting Policies for additional information on asset retirement obligations. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2007, 2006 and 2005. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 2005. Minor tritium contamination was discovered on the Callaway nuclear plant site in the summer of 2006. Existing facts and regulatory requirements indicate that this discovery will not cause any significant increase in the decommissioning cost estimate when the next study is conducted and filed on September 1, 2008. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported as Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset or regulatory liability, as appropriate.
NOTE 15 -
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which such estimates are practicable to estimate that value:
Cash, Temporary Investments, and Short-term Borrowings
The carrying amounts approximate fair value because of the short-term maturity of these instruments.
Marketable Securities
The fair value is based on quoted market prices obtained from dealers or investment managers.
Nuclear Decommissioning Trust Fund
The fair value estimate is based on quoted market prices for securities held in the trust fund.
Long-term Debt
The fair value estimate is based on the quoted market prices for same or similar issues or on the current rates offered to the Ameren Companies for debt of comparable maturities.
Preferred Stock of UE, CIPS, CILCO and IP
The fair value estimate is based on the quoted market prices for the same or similar issues.
Derivative Financial Instruments
Market prices used to determine fair value are primarily based on published indices and closing exchange prices. In addition, valuations must rely on management’s estimates, which take into account time value of money and volatility factors.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2007 and 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
UE has investments in debt and equity securities that are held in a trust fund for the purpose of funding the nuclear decommissioning of its Callaway nuclear plant. See Note 14 - Callaway Nuclear Plant for further information. We have classified these investments as available for sale and we have recorded all such investments at their fair market value at December 31, 2007 and 2006.
Investments by the nuclear decommissioning trust fund are allocated 60% to 70% to equity securities, with the balance invested in fixed-income securities.
Downgrades of subprime U.S. mortgage-related assets have resulted in a decline in the fair value of subprime-related investments. UE has assessed the investments held in its nuclear decommissioning trust fund and determined that direct exposure to subprime mortgages was not material.
The following table presents proceeds from the sale of investments in UE’s nuclear decommissioning trust fund and the gross realized gains and losses on those sales for the years ended December 31, 2007, 2006 and 2005:
Net realized and unrealized gains and losses are reflected in regulatory assets or regulatory liabilities on Ameren’s and UE’s Consolidated Balance Sheets. This reporting is consistent with the method we use to account for the decommissioning costs recovered in rates. Gains or losses on assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in electric rates paid by UE’s customers.
The following table presents the costs and fair values of investments in debt and equity securities in UE’s nuclear decommissioning trust fund at December 31, 2007 and 2006:
The following table presents the costs and fair values of investments in debt securities in UE’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2007:
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund. We believe that these losses are temporary in nature, and we expect the investments to recover their value in the future given the long-term nature of these investments. Decommissioning will not occur until the operating license for our nuclear facility expires. The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in UE’s nuclear decommissioning trust fund that were not deemed to be other-than-temporarily impaired. They are aggregated by
investment category and the length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2007:
NOTE 16 -
SEGMENT INFORMATION
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization) and other non-rate-regulated activities, which are in Other. The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company.
UE has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI and other non-rate-regulated activities, which are included in Other.
CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises leveraged lease investments, parent company activity, and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.
The following tables present information about the reported revenues and specified items included in net income of Ameren for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
(a)
Represents net income available to common shareholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
(b)
Total assets for Illinois Regulated included an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).
(c)
Includes cumulative effect of change in accounting principal net of income taxes of $(22) for consolidated Ameren.
(d)
Elimination of UE’s CT purchases from Non-rate-regulated Generation.
The following tables present information about the reported revenues and specified items included in net income of UE for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
(a)
Includes 40% interest in EEI and other non-rate-regulated activities.
(b)
Represents net income available to the common shareholder (Ameren).
The following tables present information about the reported revenues and specified items included in net income of CILCORP for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
(a)
Represents net income available to the common shareholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
(b)
Total assets for Illinois Regulated include an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).
The following tables present information about the reported revenues and specified items included in net income of CILCO for the years ended December 31, 2007, 2006 and 2005, and total assets as of December 31, 2007, 2006 and 2005.
(a)
Represents net income available to the common shareholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
(a)
Genco and CILCORP had no preferred stock outstanding.
During the third quarter of 2007, we identified a misallocation of first quarter 2007 purchased power expense among Ameren subsidiaries. The error resulted in an understatement of UE and Genco purchased power expense of approximately $7 million and $2 million, respectively, and an overstatement of CIPS, CILCORP, CILCO and IP purchased power expense of approximately $4 million, $1 million, $1 million, and $4 million, respectively, during the three months ended March 31, 2007. The error resulted in an overstatement of UE and Genco net income of $5 million and $1 million, respectively, and an understatement of CIPS, CILCORP, CILCO and IP net income of approximately $3 million, $1 million, $1 million, and $3 million, respectively, during the three months ended March 31, 2007. The error did not have a significant impact on previously reported subsidiary balance sheets or statements of cash flows, and the error had no impact on Ameren’s previously reported consolidated financial position, results of operations or cash flows.
UE, CIPS, Genco, CILCORP, CILCO and IP information for the quarter ended March 31, 2007 in the table above reflects the correction of this error. As a result, UE, CIPS, Genco, CILCORP, CILCO and IP financial information for the quarter ended March 31, 2007, in the table above differs from financial information reflected in the registrants’ previously filed combined Form 10-Q for the quarter ended March 31, 2007.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A
ITEM 9A and ITEM 9A(T). CONTROLS AND PROCEDURES.
Each of the Ameren Companies was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2007 fiscal year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2007, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
(b) Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of each of the Ameren Companies’ internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). After making that evaluation under the framework in Internal Control - Integrated Framework issued by the COSO, management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2007. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of UE’s, Genco’s, CIPS’, CILCO’s, CILCORP’s or IP’s (the Subsidiary Registrants) registered public accounting firm regarding internal control over financial reporting. Management’s report for the Subsidiary Registrants was not subject to attestation by the registered public accounting firm because temporary rules of the SEC permit the company to provide only management’s report in this annual report.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
(c) Change in Internal Control
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION.
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 2007 that has not previously been reported on an SEC Form 8-K.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2008 annual meetings of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K.
Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Executive Officers of the Registrants” in Part I of this report.
UE, CIPS, Genco, CILCORP, CILCO and IP do not have separately designated standing audit committees, but instead use Ameren’s audit and risk committee to perform such committee functions for their boards of directors. These companies have no securities listed on the NYSE and therefore are not subject to the NYSE listing standards. Douglas R. Oberhelman serves as chairman of Ameren’s audit and risk committee and Stephen F. Brauer, Susan S. Elliott and Richard A. Liddy serve as members. The board of directors of Ameren has determined that Douglas R. Oberhelman qualifies as an audit committee financial expert and that he is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of UE, CIPS, Genco, CILCORP, CILCO and IP use the nominating and corporate governance committee of Ameren’s board of directors to perform such committee functions. This committee is responsible for the nomination of directors and corporate governance practices. Ameren’s nominating and corporate governance committee will consider director nominations from shareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s Web site: www.ameren.com.
To encourage ethical conduct in its financial management and reporting, Ameren has adopted a Code of Ethics that applies to the principal executive officer, the principal financial officer, the principal accounting officer, the controllers, and the treasurer of the Ameren Companies. Ameren has also adopted a Code of Business Conduct that applies to the directors, officers and employees of the Ameren Companies, referred to as the Corporate Compliance Policy. The Ameren Companies make available free of charge through Ameren’s Web site (www.ameren.com) the Code of Ethics and Corporate Compliance Policy. These documents are also available free in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. Any amendment to, or waiver of, the Code of Ethics and Corporate Compliance Policy will be posted on Ameren’s Web site within four business days following the date of the amendment or waiver.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION.
Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14A. It is incorporated herein by reference. Information required by these SEC Regulation S-K items for UE, CIPS and CILCO will be included in each company’s definitive information statement for their 2008 annual meetings of shareholders filed pursuant to SEC Regulation 14C and is incorporated herein by reference. Information required by these SEC Regulation S-K items for IP is identical to the information that will be included in CIPS’ definitive information statement for CIPS’ 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14C and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Equity Compensation Plan Information
The following table presents information as of December 31, 2007, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans.
(a)
Consists of the Ameren Corporation Long-term Incentive Plan of 1998, which was approved by shareholders in April 1998 and expires on April 1, 2008, and the Ameren Corporation 2006 Omnibus Incentive Compensation Plan, which was approved by shareholders in May 2006 and expires on May 2, 2016. Pursuant to grants of performance share units (PSUs) under the Long-term Incentive Plan of 1998 and the 2006 Omnibus Incentive Compensation Plan, 745,058 of the securities represent PSUs at the target level of awards (including accrued and reinvested dividends). The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level based on the achievement of total shareholder return objectives established for such awards.
(b)
PSUs are awarded when earned in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs have been excluded for purposes of calculating the weighted-average exercise price.
UE, CIPS, Genco, CILCORP, CILCO and IP do not have separate equity compensation plans.
Security Ownership of Certain Beneficial Owners and Management
The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2008 annual meetings of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K. Information required by SEC Regulation S-K Item 403 for IP is as follows.
Securities of IP
All 23 million outstanding shares of IP’s common stock and 662,924 shares, or approximately 73%, of IP’s preferred stock are owned by Ameren. None of IP’s outstanding shares of preferred stock were owned by directors, nominees for director, or executive officers of IP as of February 1, 2008. To our knowledge, other than Ameren, which as noted above owns 73% of IP’s outstanding preferred stock, there are no beneficial owners of 5% or more of IP’s outstanding shares of preferred stock as of February 1, 2008, but no independent inquiry has been made to determine whether any shareholder is the beneficial owner of shares not registered in the name of such shareholder or whether any shareholder is a member of a shareholder group.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Information required by Item 404 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2008 annual meetings of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2008 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of UE, CIPS and CILCO for their 2008 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
(a)(3) Exhibits.
Reference is made to the Exhibit Index commencing on page 180.
(b)
Exhibits are listed in the Exhibit Index commencing on page 180.
CILCORP (Parent Company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2007
NOTE 1 -
BASIS OF PRESENTATION
CILCORP (Parent Company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes to our financial statements under Part II, Item 8, of this report.
NOTE 2 -
LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of long-term obligations of CILCORP (Parent Company only).
NOTE 3 -
COMMITMENTS AND CONTINGENCIES
See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of CILCORP (Parent Company only).
CENTRAL ILLINOIS LIGHT COMPANY (Parent Company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2007
NOTE 1 -
BASIS OF PRESENTATION
Central Illinois Light Company (Parent Company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes to our financial statements under Part II, Item 8, of this report.
NOTE 2 -
LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of long-term obligations of Central Illinois Light Company (Parent Company only).
NOTE 3 -
COMMITMENTS AND CONTINGENCIES
See Note 13 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of Central Illinois Light Company (Parent Company only).
(a)
Uncollectible accounts charged off, less recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; UE, 1-2967; CIPS, 1-3672; Genco, 333-56594; CILCORP, 2-95569; CILCO, 1-2732; and IP, 1-3004.
*Management compensatory plan or arrangement.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.