ITEM 1.
BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren was formed in 1997 by the merger of UE and CIPSCO, the former parent company of CIPS. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP. Ameren’s subsidiaries, which are separate, independent legal entities, operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock depend upon distributions made to it by its subsidiaries.
The following table presents our total employees at December 31, 2006:
(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 63% of Ameren’s total employees. They represent 73% of the employees at UE, 83% at CIPS, 71% at Genco, 71% at CILCORP, 71% at CILCO, and 91% at IP. Two IBEW collective bargaining agreements covering about 320 UE workers expired on September 30, 2006. Another IBEW agreement covering 17 IP workers expired on November 30, 2006. The UE collective bargaining agreements have been extended indefinitely by mutual agreement, and the IP agreement is currently in force under an extension, while negotiations continue on all three agreements. At this time, all employees continue to work without disruption. The most significant remaining issue associated with the UE agreements involves health care benefit plan revisions, and the most significant issue associated with the IP agreement involves continuity of work and incentive pay provisions. Most of the remaining collective bargaining agreements, covering 5,000 employees at UE, CIPS, Genco, CILCORP, CILCO and IP, expire throughout 2007.
For additional information about the development of our businesses, our business operations, and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
BUSINESS SEGMENTS
Before the third quarter of 2006, Ameren reported only one business segment, Utility Operations, which comprised electric generation and electric and gas transmission and distribution operations. Ameren holding company activity was listed in the caption called Other.
In the third quarter of 2006, Ameren determined that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE determined it has one reportable segment: Missouri Regulated. CILCORP and CILCO determined they have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 17 - Segment Information to our financial statements under Part II, Item 8, of this report for additional information on reporting segments.
RATES 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 also regulates UE, CIPS, Genco, CILCO and IP as to their ability to charge market-based rates for the sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters. Less than 5% of the Ameren Companies’ electric operating revenues fall under FERC regulations.
About 39% of Ameren’s electric and 12% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2006. About 43% of
Ameren’s electric and 88% of its gas operating revenues were subject to regulation by the ICC that year. Interchange revenues are not subject to direct MoPSC or ICC regulation.
Missouri Regulated
About 82% of UE’s electric and 100% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2006.
If certain criteria are met, UE’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.
A new Missouri law enacted in July 2005 enables the MoPSC to put in place fuel and purchased power and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006 and became effective during the fourth quarter of 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. UE requested approval of a fuel and purchased power cost recovery mechanism in its electric rate case filed with the MoPSC in July 2006. The MoPSC staff and intervenors have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost recovery mechanism as part of this electric rate case. However, no environmental adjustment clause has been submitted in the rate case since final environmental cost recovery rules have not been adopted. UE’s requests are subject to approval by the MoPSC.
For further information on Missouri rate matters, including the Missouri law enabling fuel, purchased power and environmental cost recovery mechanisms, UE’s pending electric and gas rate cases following the expiration of a rate-adjustment moratorium in 2006 and termination of the JDA among UE, CIPS and Genco, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 - Rate and Regulatory Matters, and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
Illinois Regulated
The following table presents the approximate percentage of electric and gas operating revenues subject to regulation by the ICC for each of the Illinois Regulated companies for the year ended December 31, 2006:
(a)
Interchange revenues are not subject to ICC regulation.
During 2006, retail electric rates were subject to a legislative rate freeze in Illinois. In February 2005, CIPS, CILCO and IP filed with the ICC a proposal for power procurement through an ICC-monitored auction including, among other things, a rate mechanism that would pass power supply costs directly through to customers after the rate freeze expired on January 1, 2007, and power supply contracts expired December 2006. In January 2006, the ICC issued an order that unanimously approved the Ameren Illinois Utilities’ proposed power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to electric customers.
The power procurement auction was held and declared successful for fixed-price customers in September 2006. The vast majority of electric customers of CIPS, CILCO and IP are fixed-price customers.
If certain criteria are met, CIPS’, CILCO’s and IP’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.
Environmental adjustment rate riders authorized by the ICC permit the recovery of prudently incurred MGP remediation and litigation costs from CIPS’, CILCO’s and IP’s Illinois electric and natural gas utility customers. As a part of the order approving Ameren’s acquisition of IP, the ICC also approved a tariff rider that would allow IP to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.
This report includes further information on rate matters, including the ICC order allowing for the recovery of prudently incurred power costs effective January 2, 2007, and related court proceedings; CIPS’, CILCO’s and IP’s 2006 ICC electric delivery services rate case orders; and actions taken by certain Illinois legislators, the Illinois governor, the Illinois attorney general, and others regarding the expiration of the rate freeze and oppositions to the power procurement auction. See Results of Operations and Outlook in Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 - Rate and Regulatory Matters, and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
General Regulatory Matters
PUHCA 2005, enacted as part of the Energy Policy Act of 2005, repealed PUHCA 1935, effective February 8, 2006. Under PUHCA 2005, UE, CIPS, CILCO and IP must receive FERC approval to issue short-term debt securities and to conduct certain acquisitions, mergers and consolidations involving electric utility holding companies having a value in excess of $10 million. In addition, these Ameren utilities must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities with maturities of more than 12 months and to conduct mergers, affiliate transactions, and various other activities. Genco and EEI are subject to FERC’s jurisdiction when they issue any securities.
Under PUHCA 2005, FERC and any state public utility regulatory agencies may access books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren, the ICC, or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.
Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on June 11, 2024. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for the Osage plant expired on February 28, 2006, but the plant is allowed to operate under this license pending FERC’s decision on UE’s license renewal application. In May 2005, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage plant for another 40 years. The settlement must be approved by FERC. The license for UE’s Taum Sauk plant expires on June 30, 2010. The Taum Sauk plant is currently out of service due to a major breach of the upper reservoir in December 2005. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under open-ended authority, granted by an Act of Congress in 1905.
For additional information on regulatory matters, see Note 3 - Rate and Regulatory Matters and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, which include a discussion about the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.
Environmental Matters
Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These matters include identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on us. We could be subjected to criminal or civil penalties by regulatory agencies. We could be ordered to make payment to private parties by the courts. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.
For additional discussion of environmental matters, including 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 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
SUPPLY FOR ELECTRIC POWER
During 2006, the Ameren Companies’ peak demand from retail and wholesale customers was 17,703 megawatts. The combined peak capability to deliver power from owned generation and power supply agreements was 20,899 megawatts. Ameren-owned generation and purchased power currently meet the energy needs of UE, Genco, AERG and Marketing Company customers, with the required reserve margins. Power for the Ameren Illinois Utilities is purchased through an ICC-approved auction that was first held in September 2006. Factors that could cause us to purchase power include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it.
Effective January 1, 2006, Ameren became a member of SERC, a regional electric reliability organization. SERC is responsible for promoting, coordinating and ensuring the reliability and adequacy of the bulk electric power supply system in much of the southeastern United States, including portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP. Ameren was previously a member of MAIN, which ceased operations on January 1, 2006.
Before the termination of the JDA on December 31, 2006, the bulk power system of UE, CIPS and Genco operated as a single control area and transmission system,
and CILCO and IP operated as separate control areas. On July 7, 2006, UE, CIPS and Genco mutually agreed to terminate the JDA on December 31, 2006. This action was accepted by the FERC in September 2006. In conjunction with terminating the JDA, Ameren’s transmission-owning entities restructured their control areas into one control area in Missouri for UE’s transmission facilities and one in Illinois for the transmission facilities of CIPS, CILCO and IP. See Note 3 - Rate and Regulatory Matters and Note 13 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for more information on the JDA. In 2006, we had at least 18 direct connections with other control areas for the exchange of electric energy, some directly and some through the facilities of others. EEI operates a separate control area in southern Illinois. EEI’s transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG. UE, CIPS, CILCO and IP are transmission-owning members of the MISO, and they have transferred functional control of their systems to the MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems is provided pursuant to the terms of the MISO OATT on file with FERC. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.
Missouri Regulated
UE’s electric supply is obtained primarily from its own generation. In March 2006, UE completed the purchase of three CT facilities, totaling 1,490 megawatts of capacity at a price of $292 million. These purchases were designed to help meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining when to add future baseload generating capacity. UE expects the addition of these CT facilities to satisfy demand growth until about 2018. In the meantime, UE will be evaluating baseload electric generating plant options, including coal-fired, nuclear, pumped-storage and integrated gasification combined cycle coal technology. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for a discussion of the CT facilities purchases.
Illinois Regulated
CIPS, CILCO and IP own no generation facilities. CIPS bought power from Genco, and CILCO bought power from AERG, both under contracts that expired at the end of 2006. IP’s primary power supply contract with Dynegy also expired at the end of 2006. In connection with the expiration of the power supply agreements, the ICC approved an auction framework to allow electric utilities in Illinois, including CIPS, CILCO and IP, to procure power for use by their customers in 2007. The power procurement auction was held in September 2006. See Note 3 - Rate and Regulatory Matters and Note 13 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of the ICC-approved power procurement auction.
Non-rate-regulated Generation
In December 2005, EEI entered into a power supply agreement with Marketing Company, whereby EEI sells 100% of its capacity and energy to Marketing Company. Commencing in 2007, Genco and AERG are also selling power to Marketing Company. Marketing Company sold power through the Illinois power procurement auction to CIPS, CILCO and IP and is selling power through other contracts with wholesale and retail customers. See Note 3 - Rate and Regulatory Matters and Note 13 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of power supply agreements.
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2006, 2005 and 2004:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Less than 1% of total fuel supply.
(c)
The remaining CILCO (Illinois Regulated) generating facilities were contributed to CILCO (AERG) effective December 31, 2006.
The following table presents the cost of fuels for electric generation for the years ended December 31, 2006, 2005 and 2004.
(a)
The fuel cost for coal represents the cost of coal and costs for transportation.
(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 to calculate 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, CILCO (AERG) and EEI have agreements in place to purchase coal and to transport it to electric generating facilities through 2011. UE, Genco, AERG and EEI expect to enter into additional contracts to purchase coal. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. As of December 31, 2006, 100% of UE’s, Genco’s, AERG’s and EEI’s expected 2007 coal usage was under contract, and about 54% of the expected coal usage for 2008 to 2011 was under contract. Ameren burned 40 million (UE - 23 million, Genco - 8 million, AERG - 4 million, EEI - 5 million) tons of coal in 2006.
More than 90% of Ameren’s coal is purchased from the Powder River Basin in Wyoming. The remaining coal is purchased from the Illinois Basin. UE, Genco, AERG and EEI have a policy to maintain coal inventory consistent with their projected usage. Inventory may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. As of December 31, 2006, coal inventories for UE, Genco, AERG and EEI were adequate and consistent with historical levels, but below targeted levels due to rail deliveries from the Powder River Basin below requested levels. Disruptions in deliveries of coal could cause UE, Genco, AERG and EEI to incur higher costs for fuel and purchased power and could reduce their interchange sales.
Nuclear
Fuel assemblies for the 2007 spring refueling are already at UE’s Callaway nuclear plant. UE also has agreements or inventories to meet 61% of Callaway’s 2008 to 2011 requirements. UE expects to enter into additional contracts to purchase nuclear fuel. Prices cannot be accurately predicted at this time. UE is a member of Fuelco, which allows UE to join with other member companies to increase its purchasing power and opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was
completed in November 2005. The next refueling is scheduled for April 2007.
Natural Gas Supply for Power Generation
Ameren’s portfolio of natural gas supply resources includes firm transportation capacity, and firm no-notice storage capacity leased from interstate pipelines to maintain gas deliveries to our gas-fired generating units throughout the year, especially during the summer peak demand. UE, Genco and EEI primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to generating units. In addition to physical transactions, Ameren uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
UE’s, Genco’s and EEI’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. UE, Genco and EEI do this in two ways. UE, Genco and EEI optimize transportation and storage options and minimize cost and price risk through various supply and price hedging agreements that allow them to maintain access to multiple gas pools, supply basins, and storage. As of December 31, 2006, UE had about 39% and Genco had 100% of its required gas supply for generation for 2007 hedged for price risk. For 2008 to 2011, UE has 1% of its estimated required natural gas supply for generation hedged for price risk, and Genco has 7% hedged. As of December 31, 2006, EEI did not have any of its required gas supply for generation hedged for price risk.
Purchased Power
We believe that we can obtain enough purchased power to meet future needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected. The Ameren transmission system has a minimum of 18 direct connections to other control areas, which give us access to numerous sources of supply. UE, CIPS, CILCO and IP are members of the MISO. The MISO Day Two Energy Market is designed to provide transparency of power pricing and to make generation dispatch efficient. The MISO Day Two Energy Market also makes available power from the entire MISO transmission grid.
Illinois Regulated
CIPS, CILCO and IP were subject to legislative electric rate freezes in Illinois through January 1, 2007, and had power supply contracts in place through December 31, 2006, to meet their customers’ needs. In January 2006, the ICC approved a power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates at which power supply costs would be passed through to customers. The power procurement auction was held at the beginning of September 2006. The auction was designed to procure the power supply needs of CIPS, CILCO and IP through a portfolio of one-, two- and three-year supply agreements for residential and small commercial customers and one-year agreements for large commercial and industrial customers. Through the auction, CIPS, CILCO and IP acquired 100% of expected power supply requirements for all customers through May 31, 2008, two-thirds of supply requirements for residential and small commercial customers for June 1, 2008, through May 31, 2009, and one-third of the requirements for these customers for June 1, 2009, through May 31, 2010. See Note 14 - Commitments and Contingencies under Part II, Item 8, of the report for more information on the results of the Illinois power procurement auction. The next Illinois power procurement auction is scheduled for January 2008.
See Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Risk Factors under Part I, Item 1A, and Note 3 - Rate and Regulatory Matters, under Part II, Item 8, of this report for a discussion of credit rating changes issued in response to potential actions in Illinois that could threaten the financial solvency of CIPS, CILCO and IP and their ability to procure power.
Non-rate-regulated Generation
In December 2006, Genco and AERG each entered into separate power supply agreements to sell all of their generation capacity to Marketing Company. Both agreements began on January 1, 2007, and will continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement. In December 2005, Marketing Company entered into a power supply agreement with EEI, whereby EEI agreed to sell 100% of its capacity and energy to Marketing Company. This agreement expires on December 30, 2015. A portion of this power was sold by Marketing Company into the Illinois power procurement auction. For additional information on the electric power supply agreements, see Note 13 - Related Party Transactions to our financial statements under Part II, Item 8, of this report.
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 UE, CIPS, CILCO and IP gas customers in Illinois and Missouri dollar-for-dollar under PGA clauses, subject to prudency review by the ICC and the MoPSC.
For additional information on our fuel and purchased power supply, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation and Changing Prices in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report; Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report; and Note 1 - Summary of Significant Accounting Policies, Note 8 - Derivative Financial Instruments, Note 13 - Related Party Transactions, Note 14 - Commitments and Contingencies, and Note 15 - Callaway Nuclear Plant to our financial statements under Part II, Item 8, of this report.
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 and regulation;
•
the potential for more intense competition in generation and supply;
•
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;
•
availability of fuel and increases in prices;
•
rising labor and material costs;
•
continually developing and complex environmental laws, regulations and issues, including new air-quality standards, mercury regulations, and possible greenhouse gas limitations;
•
public concern about the siting of new facilities;
•
construction of new power generating and transmission facilities;
•
proposals for programs to encourage energy efficiency and renewable sources of power;
•
public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste;
•
consolidation of electric and gas companies; and
•
global climate issues.
We are monitoring these issues. We are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 3 - Rate and Regulatory Matters, and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years. Unless otherwise indicated, IP is included only for the periods after its acquisition on September 30, 2004.
(a)
Includes purchases from EEI.
(b)
Peak occurred before the acquisition date of September 30, 2004.
(c)
Represents gross generating capability.
(a)
Represents peak day throughput since the acquisition date of September 30, 2004. IP’s peak day throughput for the first three quarters of 2004 was 654 Dth.
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 committee, human resources committee, nominating and corporate governance committee, nuclear oversight committee, and public policy committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to the Ameren Companies.
These documents are also available in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. The public may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
ITEM 1A.
ITEM 1A. RISK FACTORS
The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are currently the subject of rate case proceedings and potential legislative action. The outcome of these proceedings and of other potential legislative action or future rate proceedings is largely outside of our control. Should these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position, or liquidity. In particular, we believe freezing electric rates at 2006 levels in Illinois would lead to CIPS, CILCORP, CILCO and IP being financially insolvent.
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, or liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on our results of operations, financial position, or liquidity.
Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. Ameren expects that many of its operating expenses will continue to rise. Ameren further expects to continue to make significant investment in its energy infrastructure. These are the two principal factors underlying the pending rate increase requests with the MoPSC and the rate increase requests recently acted upon and pending rehearing with the ICC. We cannot predict the outcome of these rate case proceedings or of potential Illinois legislative action to deny full recovery of costs. In addition, in response to competitive, economic, political, legislative and regulatory pressures, in connection with the resolution of our current rate case proceedings or otherwise, we may be subject to further rate moratoriums, rate refunds, limits on rate increases, or rate reductions, including phase-in plans. Any or all of these could have a material adverse effect on our results of operations, financial position, or liquidity.
Illinois
Electric Delivery Service Rate Cases
A provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS - an $8 million decrease, CILCO - a $21 million increase and IP - an $84 million increase) based on an allowed return on equity of 10%. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling $50 million, that were disallowed. The ICC’s decision on the recovery of these expenses is due in May 2007. The ICC denied requests for rehearings filed by other parties in this case. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which includes the cost of power, so these delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.
Potential Electric Rate Freeze and Recovery of Post-2006 Power Supply Costs
Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expired on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006.
Subsequently, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, and the independent auction manager declared a successful result in the auction for these fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. In February 2006, legislation was introduced in the Illinois House of Representatives that would have extended the electric rate freeze in Illinois at 2006 levels through 2010. On October 2, 2006, Speaker of the Illinois House of Representatives Michael Madigan sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly to consider this rate freeze legislation. The governor sent a letter indicating that once the votes to pass the legislation were in place, he would immediately call for a special session of the legislature. The governor’s letter further provided that if a consensus among members of the general assembly could not be reached in the near future, he would call a special session as well. The governor’s letter stated that he continued to support legislation extending the rate freeze and would like to sign it into law as soon as possible. No special session was called in 2006. During the Illinois General Assembly’s session that ended in January 2007, the Illinois House of Representatives passed legislation to freeze rates at 2006 levels through 2010, and the Illinois Senate passed legislation containing an electric rate increase phase-in plan. The Illinois Senate bill provided for a mandatory phase-in of the 2007 increase in residential electric rates over a three-year period. Neither piece of legislation was passed by the other chamber before the end of the session in early January 2007.
Any legislative measure will need to be approved by the Illinois House of Representatives and Illinois Senate, and signed by the Illinois governor before it can become law. New rates for CIPS, CILCO and IP reflecting the power costs resulting from the ICC-approved September 2006 auction and the delivery service rates authorized by the November 2006 ICC order became effective January 2, 2007. A new Illinois General Assembly went into session in late January 2007. As a result, all previous bills expired. New bills have been introduced during the current legislative session, including legislation to rollback rates to 2006 levels similar to previously proposed legislation. On February 27, 2007, the Ameren Illinois Utilities announced that they intended to file an electric rate increase mitigation plan with the ICC. As part of the plan, which is subject to ICC approval, the Ameren Illinois Utilities would fund an approximate $20 million one-time reduction to active residential accounts that would appear on electric bills in March and April 2007. The rate mitigation plan is targeted to customers with high volume usage. As part of the filing, the carrying charge of 3.25% in the current ICC-approved phase-in plan would be eliminated. If approved by the ICC, the one-time credit for residential customers would result in a charge to Ameren’s earnings in 2007 of $20 million, or 6 cents per share. In addition, eliminating the below-market interest rate on deferred amounts under the phase-in plan would increase financing costs for the Ameren Illinois Utilities during the deferral period. The actual cost to Ameren will depend on the level of participation in the phase-in plan.
CIPS, CILCORP, CILCO and IP believe that legislation freezing electric rates at 2006 levels, if enacted, would have a material adverse effect on their results of operations, financial position, and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP. They believe it could cause significant job losses and, without governmental intervention, significant disruptions in electric and gas
service. Since Ameren’s Illinois utilities own no generation facilities, the companies must purchase power on the competitive market to meet customers’ energy needs. If electric rates were to be frozen at 2006 levels, the major credit rating agencies have stated that the Ameren Illinois Utilities’ credit ratings would be downgraded to deep junk (or speculative) status. Such a downgrade of CILCO’s ratings would also result in a similar downgrade of CILCORP’s ratings. We believe that CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements for products and services, such as natural gas, and would eventually run out of cash and available credit and be unable to borrow. We believe that this would cause the Ameren Illinois Utilities and CILCORP to become financially insolvent. In reaction to intensified political discussion in Illinois regarding electric rate freeze extension legislation, in October 2006, S&P downgraded the short- and long-term credit ratings of the Ameren Companies and kept the Ameren Companies on credit watch with negative implications; Moody’s placed the long-term debt ratings of the Ameren Companies under review for possible downgrade; and Fitch placed the ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.
CIPS, CILCO and IP strongly believe that freezing rates at 2006 levels in Illinois would not be in the best interests of any of the Ameren Illinois Utilities or their customers. In December 2006, the ICC approved a constructive rate increase phase-in plan proposed by CILCO, CIPS and IP for residential, small commercial, and eligible local governmental and school customers to address the significant increases in customer rates for the Ameren Illinois Utilities beginning in 2007. However, if the Illinois legislature passes rate phase-in legislation that does not allow for the full and timely recovery of costs, it could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.
Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies, and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their legal and financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois Utilities will prevail over the stated opposition of certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois Utilities are considering will be successful.
We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs. Nor can we predict the actions the Illinois General Assembly and governor may take that may affect electric rates or the power procurement process for CIPS, CILCO and IP. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk (or speculative) status, a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, significant risk of disruption in electric and gas service, significant job losses, and financial insolvency. In addition, Ameren, CILCORP and IP could be required to record a charge for goodwill impairment for the goodwill that was recorded when Ameren acquired CILCORP and IP. As of December 31, 2006, Ameren had $830 million, CILCORP $542 million and IP $213 million of goodwill on their balance sheets. Furthermore, if the Ameren Illinois Utilities are unable to recover their costs from customers, the utilities could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which allows CIPS, CILCORP, CILCO and IP to defer certain costs pursuant to actions of rate regulators and to recover such costs in rates charged to customers. This would result in the elimination of all regulatory assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary charge on their statements of income that could be material. As of December 31, 2006, CIPS had $146 million, CILCORP $75 million, CILCO $75 million and IP $401 million recorded as regulatory assets on their balance sheets.
Missouri
With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In December 2006, the MoPSC staff and other stakeholders filed direct testimony in response to UE’s rate case filings. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million and a gas rate increase of $2 million to $3 million. During the course of the rate proceeding, parties to the case may change their positions. A decision from the MoPSC is expected no later than June 2007. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.
UE does not currently have a rate-adjustment clause for its electric operations in Missouri that would allow it to recover from customers the costs for purchased power, fuel, or infrastructure investment. Therefore, insofar as UE has not hedged its fuel and power costs, UE is exposed to changes in fuel and power prices to the extent they exceed the costs embedded in current electric rates. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism that would be subject to MoPSC approval. The MoPSC staff and intervenors in the electric rate case have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost-recovery mechanism as part of its pending Missouri electric rate case, but no rules have been established for such a mechanism. Any new energy infrastructure investment could result in increased
financing requirements for UE, which could increase further depending on rate case outcomes. The lack of timely recovery of these costs could have a material adverse effect on UE’s results of operations, financial position, or liquidity. We are unable to predict whether the MoPSC will approve our request for a fuel and purchased power cost recovery mechanism in our pending electric rate case. We also are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted.
If Illinois electric rates are frozen at 2006 levels or if the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates is otherwise impaired, there may be a material adverse effect on Ameren, UE and Genco in addition to the Ameren Illinois Utilities and CILCORP.
We believe that freezing electric rates at 2006 levels in Illinois would cause CIPS, CILCORP, CILCO and IP to become financially insolvent. Although the Ameren Companies are separate, independent legal entities with separate businesses, assets and liabilities, there is a risk that the financial insolvency of CIPS, CILCORP, CILCO and IP could have a materially adverse effect on Ameren, UE and Genco. If rates are frozen at 2006 levels in Illinois for CIPS, CILCO and IP, or if the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates is otherwise impaired, such events might increase Ameren’s, UE’s and Genco’s cost of capital or adversely affect the ability of these companies to access the capital markets, particularly during times of uncertainty in the capital markets, which could negatively affect their ability to maintain and expand their businesses. Moody’s, S&P and Fitch each have indicated that they would lower the credit ratings for CIPS, CILCORP, CILCO and IP to deep junk (or speculative) status, if electric rates were frozen at 2006 levels, reflecting the material impact such action would have on the cash flow and liquidity of these companies. It is possible that the rating agencies could decide to lower the credit ratings of Ameren, UE or Genco at the same time. Any adverse change in the ratings of Ameren, UE or Genco could also increase their cost of borrowing under existing credit facilities, and suppliers might begin to request prepayment for products and services (such as fuel, power and gas) or the posting of collateral.
If CIPS, CILCORP, CILCO and IP become insolvent, their commitments to Ameren, Genco and AERG might be unfulfilled. Pursuant to agreements executed in connection with the recent Illinois power procurement auction, Marketing Company is selling to CIPS, CILCO and IP power that is being supplied under contracts from Genco and AERG. If CIPS, CILCORP, CILCO and IP become insolvent, Genco, AERG or Marketing Company may not be able to recover the cost of power delivered to those companies but not paid for prior to insolvency. Marketing Company’s commitments to sell power to CIPS, CILCO, IP and other unaffiliated parties also rely, in part, on power supplied by AERG. In the event of financial insolvency, AERG may not be able to deliver power it has committed to sell to Marketing Company; that could force Marketing Company to acquire the power to meet its commitments at a higher cost.
In addition, dividends on Ameren’s common stock and the payment of Ameren’s other obligations, including its debt, depend on distributions made to it by its subsidiaries. If CIPS, CILCORP, CILCO and IP should become insolvent, they will not be able to make distributions to Ameren. Additionally, if CIPS, CILCORP, CILCO and IP fall below investment grade in ratings of their securities, they will be limited in the amount of dividends they may pay. As a result, the board of directors of Ameren might decide to rely more heavily on UE and Ameren’s unregulated operations to support dividends on Ameren’s common stock, or to reduce or eliminate the payment of dividends. Moreover, the absence of distributions from the Illinois utilities and CILCORP could force Ameren to use other available sources of liquidity to service its debt obligations.
We cannot determine at this time whether the freezing of rates at 2006 levels in Illinois that would lead to CIPS, CILCORP, CILCO and IP insolvency will occur. We also cannot determine what the resulting effect would be on Ameren, UE and Genco. However, the financial insolvency of CIPS, CILCORP, CILCO and IP could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren, UE and Genco.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to various arrangements (including our affiliates) who owe us money, energy, coal or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. In such event, we might incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.
Increased federal and state environmental regulation will require UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and to incur increased operating costs. Future limits on greenhouse gas emissions could result in significant increases in capital and operating expenditures.
About 61% of Ameren’s generating capacity is coal-fired and about 85% of its electric generation was produced by its coal-fired plants in 2006. The rest is nuclear, gas-fired, hydroelectric, and oil-fired. In May 2005, the EPA issued final regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. The new rules require significant additional reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of capital compliance costs for Ameren, UE, Genco and AERG range from $3.5 billion to $4.5 billion by 2016.
The Missouri Department of Natural Resources formally proposed rules to implement the federal Clean Air Mercury and Clean Air Interstate Rules in November 2006. Missouri
rules are similar to the federal rules. The Missouri Air Conservation Commission approved the rules at their February 2007 meeting. The rules will be effective after publication in the Missouri Register targeted for April 2007. The rules will also need to be approved by the EPA. If approved, these rules when fully implemented are expected to reduce mercury emissions 81% by 2018 and to reduce NOx emissions 30% and SO2 emissions 75% by 2015.
Illinois has proposed rules to implement the federal Clean Air Interstate Rule program; however it is anticipated that the rules will not be finalized until the second quarter of 2007. The Illinois EPA proposed rules for mercury that are significantly stricter than the federal rules. Illinois has also proposed Clean Air Interstate Rule program rules for NOx that are more stringent than the federal program. In 2006, Genco, AERG, EEI, and the Illinois EPA entered into an agreement on Illinois’ mercury rules. Under the agreement, Illinois generators may delay the compliance date for mercury reductions in exchange for accelerated installation of NOx and SO2 controls. The agreement with the Illinois EPA also restricts the purchase of SO2 and NOx emission allowances to meet specific allowed emission rates set forth in the agreement. The Illinois Joint Committee on Administrative Review approved the Illinois mercury rule in December 2006, and the Illinois Pollution Control Board issued a final order and adopted the mercury rule in late December 2006. The final rule was published in the Illinois Register in January 2007. The rule will also need to be approved by the EPA. When fully implemented, these rules are expected to reduce mercury emissions 90%, NOx emissions 50% and SO2 emissions 70% by 2015.
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity by the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects. Future legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.
The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were made.
In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act, seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired plants. Genco is asked to respond to specific EPA questions about certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standards required by the Clean Air Act. These information requests are being complied with, but we cannot predict the outcome of this matter.
We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on our results of operations, financial position, or liquidity. Any of these factors could result in a significant increase in capital expenditures, closure of power plants, penalties and operating costs for UE, Genco, CILCO (through AERG) and EEI. Therefore, such factors could also result in decreased revenues, increased financing requirements and increased costs for these Ameren companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois.
Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.
We offer defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. Based on our assumptions at December 31, 2006, and the new contribution requirements in the Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect to pay a required contribution of $100 million to $150 million. Required contributions of $150 million to $200 million each year are also expected for 2010 and 2011. We expect the companies to share future funding requirements as follows: UE - 61%; CIPS - 10%; Genco - 11%; CILCO - 7%; and IP - 11%. These amounts are estimates. They may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits may adversely affect our results of operations, financial position, or liquidity.
UE’s, Genco’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, liability, and increased purchased power costs.
UE, Genco, AERG, Medina Valley, and EEI own and operate coal-fired, nuclear, gas-fired, hydroelectric, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output and efficiency levels. Among these risks are:
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increased prices for fuel and fuel transportation;
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facility shutdowns due to a failure of equipment or processes or operator error;
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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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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; and
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catastrophic events such as fires, explosions, floods, or other similar occurrences affecting electric generating facilities.
The breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could continue to have an adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park.
The FERC investigation of the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation by the FERC’s Office of Enforcement. They looked into alleged violations of license conditions and FERC regulations by UE as the licensee of the Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply with a new dam safety program developed in connection with the settlement.
In December 2006, the state of Missouri, through its attorney general and 10 business owners filed separate lawsuits regarding the Taum Sauk breach. The attorney general’s lawsuit, which was filed in the Missouri circuit court in St. Louis, alleges negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims. The business owners’ suit, which was filed in the Missouri circuit court in Reynolds County, contains similar allegations. It seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages. In January 2007, the Missouri Department of Natural Resources filed a petition to intervene as a plaintiff in the attorney general’s lawsuit.
In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk Plant, assuming successful resolution of outstanding issues with agencies of the state of Missouri. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer. In 2005, the Taum Sauk facility provided 589,000 megawatthours of electricity.
To the extent that UE needs to purchase power because of the unavailability of the Taum Sauk facility, there is the risk that UE will not be permitted to recover these additional costs from ratepayers if such a request is made. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2007 pretax earnings by $15 million to $20 million as a result of higher-cost sources of power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs. In addition, there is also the risk that UE will not be permitted to rebuild the Taum Sauk facility upper reservoir. UE could be required to expense its remaining investment in the plant of $64 million immediately.
At this time, excluding fines and penalties, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. Under UE’s insurance policies, all claims by UE are subject to review by its insurance carriers. Until the reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, a final decision about whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.
As of December 31, 2006, Genco and CILCO (through AERG) owned non-rate-regulated electric generating facilities with capacities of 4,222 megawatts and 1,138 megawatts, respectively. During 2006, most of Genco’s and AERG’s wholesale and retail electric power supply agreements
expired. As a result, Genco and AERG now compete for the sale of energy and capacity through Marketing Company.
As of December 31, 2006, EEI owned 1,055 megawatts of non-rate-regulated electric generating facilities. On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. All of EEI’s generating capacity now competes for the sale of energy and capacity through Marketing Company.
To the extent that electric capacity generated by these facilities is not under contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
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the current and future market prices for natural gas, fuel oil, and coal;
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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 ICC with respect to power procurement procedures;
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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 markets adjacent to Illinois;
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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 13% of UE’s 2006 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 availability 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’s nuclear operations or those of others in the United States;
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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 2007. During an outage, which occurs approximately every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, compared with non-outage years.
Operating performance at UE’s Callaway nuclear plant has resulted in unscheduled or extended outages. The operating performance at UE’s Callaway nuclear plant has declined both in comparison with its past operating performance and in comparison with the operating performance of other nuclear plants in the United States. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. Management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, training, and overall organizational effectiveness have been reviewed. Some actions have been taken and other actions are under consideration. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren and UE.
Our energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings.
We are exposed to changes in market prices for natural gas, fuel, electricity, emission allowances, and transmission congestion. Prices for natural gas, fuel, electricity, and emission allowances may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We use long-term purchase and sales contracts in
addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities because of future volatility in these markets.
Although we routinely enter into contracts to hedge our exposure to the risks of demand, market effects of weather, and changes in commodity prices, we do not hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, or liquidity.
Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.
Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs for repair, which could have a material adverse effect on our results of operations, financial position, or liquidity.
Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.
We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including those related to future environmental compliance. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. See the Credit Ratings section in Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of credit rating changes in response to actions in Illinois with respect to the matter of power procurement commencing in 2007.
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 2 - Acquisitions, Note 6 - Long-term Debt and Equity Financings, and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2007 peak summer electrical demand:
(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. See a discussion of this incident and related matters below.
(c)
There is an economic development lease arrangement applicable to these CTs.
(d)
Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).
(e)
UE acquired this CT from affiliates of NRG Energy, Inc., in March 2006.
(f)
UE acquired this CT from affiliates of Aquila, Inc., in March 2006.
(g)
These CTs were transferred from Genco to UE in May 2005.
(h)
Ameren owns an 80% interest in EEI. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
(i)
There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).
(j)
These CTs are owned by Genco and leased to its parent, Development Company. The operating lease is for a minimum term of 15 years expiring September 30, 2015. Genco receives rental payments under the lease in fixed monthly amounts that vary over the term of the lease and range from $0.8 million to $1.0 million.
(k)
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.
(l)
These facilities were transferred from CILCO to AERG in October 2003.
(m)
This facility was transferred from CILCO to AERG effective December 31, 2006.
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer. For additional information on the Taum Sauk incident, see Note 14 - Commitments and Contingencies under Part II, Item 8 of this report.
The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2006:
Our other properties include distribution lines, underground cables, office buildings, warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all principal plants and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bond and credit facility indebtedness and to certain permitted liens and judgment liens). The exceptions are as follows:
•
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.
•
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 October 2003, CILCO transferred substantially all of its generating property and plant to its non-rate-regulated electric generating subsidiary, AERG. In December 2006, CILCO transferred the remainder of its generating property and plant to AERG. As part of these transfers, CILCO’s transferred generating property and plant was released from the lien of the indenture securing its first mortgage bonds. In May 2005, UE transferred substantially all of its Illinois electric and gas transmission and distribution properties to CIPS. As a part of the transfer, UE’s transferred utility properties were released from the lien of the indenture securing its first mortgage bonds and immediately became subject to the lien of the indenture securing CIPS’ first mortgage bonds. In July 2006 and February 2007, AERG recorded open-ended mortgages and security agreements with respect to its E.D. Edwards and Duck Creek power plants to serve as collateral to secure its obligations under multiyear, senior secured credit facilities entered into on July 14, 2006 and February 9, 2007, along with other Ameren subsidiaries. See Note 5 -
Credit Facilities and Liquidity for details of the credit facilities.
In December 2002, UE conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city for a 20-year term. As a part of the transaction, most of UE’s Peno Creek CT property and plant was released from the lien of the indenture securing UE’s first mortgage bonds. Under the terms of this capital lease, UE retains all operation and maintenance responsibilities for the facility. Ownership of the facility will return to UE at the expiration of the lease. When ownership of the Peno Creek CT facility is returned to UE by Bowling Green, the property and plant may again become subject to the lien of any outstanding UE first mortgage bond indenture.
In March 2006, UE purchased a CT facility located in Audrain County, Missouri, from NRG Audrain Holding, LLC, and NRG Audrain Generating LLC, affiliates of NRG Energy, Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County and assumed NRG’s obligations under the lease. The lease term will expire December 1, 2023. Under the terms of this capital lease, UE has all operation and maintenance responsibilities for the facility, and ownership of the facility will be transferred to UE at the expiration of the lease. When ownership of the Audrain County CT facility is transferred to UE by the county, the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
For additional information on these CT lease arrangements, see Note 2 - Acquisitions under Part II, Item 8, of this report.
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 April 2005, Caterpillar Inc. intervened in the ICC proceedings relating to the power procurement auction and related tariffs of CILCO, CIPS and IP. In the Ameren Illinois Utilities’ 2005 auction process proceedings, Caterpillar Inc., in conjunction with other industrial customers as a coalition, opposed the Ameren Illinois Utilities’ filing on issues regarding auction design and auction process, among others. In February 2006, Caterpillar Inc. intervened in the 2006 rate cases filed by the Ameren Illinois Utilities with the ICC to modify their electric delivery service rates. In the 2006 rate cases, Caterpillar Inc., in conjunction with other industrial customers as a coalition, opposed the Ameren Illinois Utilities’ filings on issues regarding rate design and revenue requirements, among others. Douglas R. Oberhelman is an executive officer of Caterpillar Inc. and a member of the board of directors of Ameren. Mr. Oberhelman did not participate in Ameren Corporation’s board and committee deliberations relating to these matters.
Anheuser-Busch, Incorporated, an affiliate of Anheuser-Busch Companies, Inc., and The Boeing Company are members of the Missouri Industrial Energy Consumers group (MIEC) which, on September 1, 2006, intervened in the MoPSC proceedings relating to UE’s request for an increase in base rates for electric service. MIEC’s position in the case is that UE overstated its needed revenue requirement and that a disproportionate amount of the increase has been assigned to industrial customers. MIEC also opposes UE’s requested fuel and purchased power cost recovery mechanism. Patrick T. Stokes is the chairman of the board of directors of Anheuser-Busch Companies, Inc. and James C. Johnson is an officer of The Boeing Company. Mr. Stokes and Mr. Johnson are also members of the board of directors of Ameren. Neither Mr. Stokes nor Mr. Johnson participated in Ameren Corporation’s board and committee deliberations relating to these matters.
For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1, Business, and Item 1A, Risk Factors, above. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 3 - Rate and Regulatory Matters, and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
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 2006 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, 2006, all positions and offices held with the Ameren Companies, tenure as officer, and business background for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.
AMEREN CORPORATION:
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the officers. Except for Richard J. Mark and Donna K. Martin, all of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
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 May 25, 2006, Ameren submitted to the NYSE a certificate of the chief executive officer of Ameren certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.
Ameren common shareholders of record totaled 79,041 on January 31, 2007. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2006 and 2005.
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; Development 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 2006 and 2005:
(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. CILCO paid dividends to CILCORP of $20 million in the quarterly period ended March 31, 2005.
On February 9, 2007, 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 30, 2007, to stockholders of record on March 7, 2007.
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 each of October and November 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. Included in November were four shares of Ameren common stock purchased to satisfy an employee’s tax obligation incurred with the vesting of performance share units and share distribution under Ameren’s Long-term Incentive Plan of 1998 upon the employee’s death. 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, 2006.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31, 2006. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute (EEI) Index (which comprises most investor-owned electric utilities in the United States). The comparison assumes that $100 was invested on January 1, 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; and 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 $18 million ($(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. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for further information.
(d)
Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN 46R. 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
Clearly, 2006 will be remembered as an incredibly challenging year for Ameren, as well as for the communities served by UE, CIPS, CILCO and IP. For the better part of the second half of 2006, Ameren was focused on addressing the consequences resulting from unprecedented summer and winter storms. In 2006, UE also continued its extensive restoration efforts associated with the December 2005 breach of the upper reservoir at its Taum Sauk pumped-storage, hydroelectric facility and settled related liability matters with federal authorities. Unfortunately, UE did not receive a unified settlement offer from all relevant Missouri state authorities. On February 2, 2007, UE submitted plans and an environmental report to the FERC to rebuild the upper reservoir of the Taum Sauk plant assuming successful resolution of outstanding issues with authorities of the state of Missouri.
Because of the likelihood of higher electric rates in Illinois following the end of a legislative rate freeze on January 2, 2007, certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block an ICC-approved auction that occurred in September 2006 to procure power for use by the Ameren Illinois Utilities’ customers beginning in 2007. These parties continue to challenge the auction process and the recovery of costs for power supply resulting from the auction through rates to customers. To mitigate the impact of the electric rate increases on customers, an electric rate increase phase-in plan was approved by the ICC in December 2006. In November, the Ameren Illinois Utilities also received an ICC order increasing their electric delivery service rates by an aggregate of $97 million. This order authorized a 10% return on equity, but was significantly less than the Ameren Illinois Utilities’ request for approximately a $200 million increase primarily because of the disallowance of significant levels of expenses, which the Ameren Illinois Utilities believe were prudently incurred. Primarily as a result of this order and cost increases since the 2004 base year for setting these rates, the return on equity in 2007 for the Ameren Illinois Utilities will be meaningfully below the 10% return on equity allowed by the order. A rehearing was granted on a portion of the disallowed costs. The necessity and timing of additional electric delivery services rate increase requests in Illinois will be influenced by the result of this rehearing, which is expected in May 2007. In July 2006, UE filed for its first electric rate increase in almost 20 years. UE’s electric rate filing included a proposed annual increase in electric rates of $361 million. UE also filed last July for an increase in natural gas delivery rates of $11 million annually. Interveners in the electric rate case have recommended rate reductions. Decisions are expected by the MoPSC by June 2007.
While 2006 was full of challenges, we did remain focused on our core operations and were able to achieve several notable accomplishments. From an operational standpoint, Ameren’s power plants performed very well in 2006, setting records for generation output. Availability and capacity factors of the Missouri Regulated coal-fired power plants were comparable with solid 2005 results, averaging 90% and 82%, respectively. In 2006, Ameren’s non-rate-regulated coal-fired plants improved their availability from 82% to 85% year over year and capacity factors from 68% to 73%. We also successfully executed our plan to hedge most of our estimated available 2007 non-rate-regulated
generation due to the expiration of our below-market contracts at the end of 2006.
Earnings
Ameren reported earnings of $2.66 per share for 2006 which compared to earnings of $3.02 per share last year. Ameren’s earnings in 2005 included an 11 cent per share charge for the adoption of a new accounting principle related to AROs. Earnings in 2006 were affected by restoration efforts associated with severe storms that reduced Ameren’s net income by 26 cents per share. In addition, costs related to the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility decreased 2006 earnings by 20 cents per share. Ameren also incurred a charge of 5 cents per share related to funding commitments for low-income energy assistance and energy-efficiency programs associated with the December 2006 ICC order associated with the electric rate increase phase-in plan. Incremental gains of approximately 9 cents per share in 2006, associated with the sale of certain non-core properties, including leveraged leases, reduced the negative impact of these items.
Earnings in 2006 were also unfavorably affected by escalating costs for fuel and related transportation, operating materials, and financing costs and depreciation associated with significant energy infrastructure investments in Ameren’s regulated electric and gas utility businesses. In addition, earnings were significantly affected by mild summer and winter weather, as well as lower power prices for excess energy sales as compared to 2005. Market prices for power in 2005 were higher than 2006 as a result of the significant impact of hurricanes and rail disruptions in 2005. Operating results in 2006 benefited from organic sales growth; improved plant performance; the lack of a scheduled refueling and maintenance outage at UE’s Callaway nuclear plant; Illinois electric commercial and industrial customers returning to tariff rates because these rates were below market rates for power; and higher sales levels of emission allowances.
Liquidity
Cash flows from operations of $1.3 billion in 2006 at Ameren, along with other funds, were used to pay dividends to common shareholders of $522 million and fund capital expenditures of $992 million and CT acquisitions of $292 million. Financing activities in 2006 primarily consisted of refinancing debt and funding capital investment with borrowings under credit facilities.
Outlook
Electric rates in Illinois are expected to continue to be a source of debate among legislators and regulators in 2007. Proposed actions have included freezing rates at 2006 levels despite significantly higher purchased power costs for the Ameren Illinois Utilities. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover costs from their electric customers in a timely manner would result in material adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts.
The ultimate resolution of pending electric and gas rate cases in Missouri, coupled with a final decision in the rehearing of certain electric delivery service rate case issues in Illinois, will have a significant impact on earnings in 2007 and 2008. Ameren’s regulated utilities are expected to experience significant increases in the costs of serving their customers, including coal and related transportation costs that are expected to increase by 15% to 20% in 2007 and another 5% to 10% in 2008. Many of these costs will be in excess of those reflected in 2007 regulated rates because rates are largely based on historical costs. Ameren expects to realize significantly higher electric margins due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts in 2007. In the future, Ameren also expects to realize lower income associated with the sale of emission allowances and noncore properties than realized in 2006. While Ameren expects continued economic growth in its service territory to benefit energy demand in 2007 and beyond, higher energy prices could result in reduced demand from consumers.
The EPA, together with state authorities, is requiring more stringent emission limits on all coal-fired power plants. Between 2007 and 2016, Ameren expects its subsidiaries will be required to spend between $3.5 billion and $4.5 billion to retrofit their power plants with pollution control equipment. Approximately half of this investment will be at UE and therefore is expected to be recoverable over time from ratepayers. The recoverability of amounts invested in non-rate-regulated operations will depend on whether market prices for power adjust to reflect this increased investment by the industry.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries, which are separate, independent legal entities with separate businesses, assets and liabilities, 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 transmission and distribution business, a non-rate-regulated electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business 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. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the periods before September 30, 2004, do not reflect IP’s results of operations or financial position. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for further information on the accounting for the IP acquisition. 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. About 90% of Ameren’s revenues were directly subject to state or federal regulation in 2006. This regulation can have a material impact on the prices we charge for our services. Our non-rate-regulated sales are 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 fuel or purchased power cost recovery mechanisms in Missouri for our electric utility businesses. We do have natural gas cost recovery mechanisms in Missouri and Illinois for our gas delivery businesses. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 for a discussion of pending rate cases and the Illinois power procurement auction process and related tariffs. 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 risks 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 $547 million ($2.66 per share) for 2006, $606 million ($3.02 per share) for 2005, and $530 million ($2.84 per share) for 2004. 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 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.
Earnings were negatively impacted in 2006 by:
•
costs and lost electric margins associated with outages caused by severe storms (26 cents per share);
•
milder weather conditions (estimated at 17 cents per share);
•
costs associated with the upper reservoir breach in December 2005 at UE’s Taum Sauk pumped-storage hydroelectric plant (20 cents per share);
•
an unscheduled outage at UE’s Callaway nuclear plant (7 cents per share);
•
higher depreciation expense (11 cents per share);
•
increased taxes other than income taxes (8 cents per share);
•
contributions made in association with the Illinois Customer Elect electric rate increase phase-in plan (5 cents per share);
•
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.
Earnings were favorably impacted in 2006 by:
•
Higher margins on interchange sales (33 cents per share);
•
increased net gains on the sale of noncore properties, including leveraged leases, compared with 2005 (9 cents per share);
•
the lack of a refueling and maintenance outage at UE’s Callaway nuclear plant in 2006 (18 cents per share);
•
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.
Cents per share information presented above is based on average shares outstanding in 2005.
Ameren’s net income before cumulative effect of the adoption of FIN 47 in 2005 increased $98 million and earnings per share increased 29 cents in 2005 compared with 2004.
Earnings were favorably impacted in 2005 by:
•
warmer weather in the summer of 2005 compared with extremely mild conditions in the summer of 2004 (estimated at 26 cents per share);
•
inclusion of IP results for an additional nine months in 2005 (23 cents per share);
•
increased margins on interchange sales (11 cents per share);
•
the lower cost of the refueling and maintenance outage at UE’s Callaway nuclear plant in 2005 versus the 2004 refueling and maintenance outage (3 cents per share);
•
increased emission allowance sales earnings (2 cents per share);
•
net gains on sales of noncore properties, including leveraged leases in 2005 (7 cents per share);
•
lower employee benefit costs (5 cents per share); and
•
other factors including organic growth.
Earnings were negatively impacted in 2005 by:
•
incremental costs of operating in the MISO Day Two Energy Market (29 cents per share);
•
the lack of a FERC-ordered refund of $18 million in exit fees as had occurred in 2004 - this fee had previously been paid by UE and CIPS to the MISO, upon their re-entry into the MISO (6 cents per share);
•
increased labor costs (8 cents per share); and
•
other factors including increased fuel and purchased power costs and coal conservation efforts in 2005.
An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2005 compared with 2004.
Cents per share information presented above is based on average shares outstanding in 2004.
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, 2006, 2005 and 2004:
(a)
Includes earnings from market-based interchange power sales that provided the following contributions to net income: UE: 2006 - $65 million; 2005 - $75 million; 2004 - $75 million. Genco: 2006 - $20 million; 2005 - $47 million; 2004 - $39 million. CILCORP: 2006 - $18 million; 2005 - $13 million.
(b)
Includes earnings from a non-rate-regulated 40% interest in EEI.
(c)
Excludes net income prior to the acquisition on September 30, 2004.
(d)
Includes earnings 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 (2005 and 2006), transition costs associated with the CILCORP and IP acquisitions (2004), and intercompany eliminations.
Before the third quarter of 2006, Ameren reported one segment, Utility Operations, comprising electric generation and electric and gas transmission and distribution operations. Ameren holding company activity was listed in the caption called Other. As a result of the following changes in circumstances, Ameren, UE, CILCORP and CILCO changed their segments in the third quarter of 2006:
•
the Ameren Companies’ chief operating decision-making group began to assess the performance and allocate resources based on a new segment structure and made related organizational and management reporting changes in the third and fourth quarters of 2006;
•
electric generation deregulation in Illinois, which became effective on January 1, 2007;
•
the expiration of affiliate power supply agreements for CIPS and CILCO, and other supply agreements for IP on December 31, 2006;
•
the July 2006 termination of the JDA among UE, Genco and CIPS effective December 31, 2006; and
•
the September 2006 completion of a statewide auction to procure power for CIPS, CILCO and IP for 2007 and beyond, and Marketing Company’s sale in that auction of power being acquired from Genco and AERG.
In the third quarter of 2006, Ameren determined that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE determined that it has one reportable segment: Missouri Regulated. CILCORP and CILCO determined that they have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. A discussion of changes in components of net income between periods by business segment is provided below where material. Prior-period
presentation has been adjusted for comparative purposes. See Note 17 - Segment Information to our financial statements under Part II, Item 8, of this report for further discussion of Ameren’s, UE’s, CILCORP’s and CILCO’s business segments.
Below is a table of income statement components by segment for the years ended December 31, 2006, 2005 and 2004:
(a)
Ameren acquired IP on September 30, 2004. Therefore, 2004 included IP results for just three months. See discussion below in each respective section for the effect of the additional nine months of IP results in 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, 2006, 2005 and 2004. 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.
The variations in electric and gas margins for Ameren show the contribution from IP for the first nine months of 2005 as a separate line item, which allows an easier comparison with other margin components. The variation in IP electric margin in 2005 is compared with the full year of 2004, despite Ameren’s acquisition of IP occurring on September 30, 2004.
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004, and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
The effect of storm-related native-load outages increasing interchange revenues is included under the storm-related outages line.
(c)
Includes predecessor information for periods before September 30, 2004.
2006 versus 2005
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 margins 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 margins on interchange sales from these items was reduced by lower power prices, resulting from declining market prices for natural gas, the significant impact of hurricanes and rail 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.
•
Upgrades performed during the refueling and maintenance outage in 2005, which increased Callaway’s output and electric margin by $22 million.
•
Organic growth and industrial customers who switched 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 $14 million, and lower emission allowance costs, totaling $5 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, that reduced the electric margin by $33 million in 2006 compared with 2005.
•
Severe storm-related outages in 2006 that reduced overall electric margin by $9 million as less electricity was sold for native load, partially offset by an increase in margins 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 margins because of the unavailability of UE’s Taum Sauk hydroelectric plant in 2006 compared with 2005.
•
An $11 million reduction in native load margins 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 margins 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 that became 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 from 2005. UE’s Missouri Regulated electric margin increased by $9 million in 2006 compared with 2005. Factors contributing to an increase in UE’s electric margin were as follows:
•
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 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.
Factors that contributed to a decrease in UE’s electric margin were as follows:
•
Unfavorable weather conditions that reduced 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 that reduced electric native load sales and resulted in an estimated net reduction in overall electric margin of $6 million.
•
Lower margins on nonaffiliate 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 megawatthour in 2005 to $37 per megawatthour in 2006. However, margins 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 margins 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.
•
Reduced electric margin because of the unavailability of UE’s Taum Sauk hydroelectric plant.
•
Reduced electric margin from UE’s other hydroelectric generation, 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 that 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. Factors contributing to the decreased margins were as follows:
•
Mild winter weather conditions that reduced gas margins 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 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. Factors contributing to an increase in CIPS’ electric margin were as follows:
•
The transfer to CIPS of UE’s Illinois service territory in May 2005, which increased electric margin by $7 million.
•
Primarily industrial customers, switching back to CIPS from Marketing Company in 2006 because tariff rates were below market rates for power.
•
Decrease in MISO Day Two Energy Market costs of $7 million.
•
Increased miscellaneous revenues of $2 million.
Factors contributing to a decrease in CIPS’ electric margin were as follows:
•
Unfavorable weather conditions, as evidenced by a 9% decrease in cooling degree-days in 2006 compared with 2005 that reduced electric margins by $7 million.
•
Severe storm-related outages in 2006 that 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 the 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. Factors
contributing to an increase in CILCO’s Illinois Regulated electric margin were as follows:
•
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.
Factors contributing to a decrease in CILCO’s Illinois Regulated electric margin were as follows:
•
Unfavorable weather conditions, as evidenced by an 18% decrease in cooling degree-days in 2006 compared with 2005, that reduced electric margins 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. Factors contributing to a decrease in CILCO’s gas margin were as follows:
•
Mild winter weather conditions in CILCO’s service territory, as evidenced by a 7% decrease in heating degree-days in 2006 compared with 2005, that 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. Factors contributing to a decrease in IP’s electric margin were as follows:
•
Unfavorable weather conditions, as evidenced by a 10% decrease in cooling degree-days in 2006 compared with 2005, that reduced electric margins by $9 million.
•
Severe storm-related outages in 2006 that 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.
Factors contributing to an increase in IP’s electric margin were as follows:
•
A net increase in electric margin as a result of primarily industrial customers switching 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, that 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. Factors contributing to a decrease in Genco’s electric margin were as follows:
•
Lower wholesale margins 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.
•
Higher net emission allowance costs 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.
•
Lower margins on interchange sales in 2006 compared with 2005, primarily because of lower power prices, and a $23 million reduction in 2006 due to the amendment of the JDA among UE, Genco and CIPS. The average realized power prices on Genco’s interchange sales decreased from $47 per megawatt in 2005 to $38 per megawatt hour in 2006.
•
Higher MISO Day Two Energy Market costs totaling $12 million in 2006 compared with 2005, since 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. Factors contributing to an increase in AERG’s electric margin were as follows:
•
Lower purchased power costs due to improved power plant availability.
•
A decrease in emission allowance utilization expenses of $9 million in 2006 compared with 2005.
•
An increase in margins 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. Factors contributing to EEI’s increase in electric margin were as follows:
•
An increase in margins on interchange sales, which resulted from the expiration of its affiliate cost-based sales contract on December 31, 2005, and its replacement with an affiliate market-based sales contract.
•
Sales of emission allowances.
2005 versus 2004
Ameren
Ameren’s electric margin increased by $366 million in 2005 compared with 2004. An additional nine months of IP results was included in 2005, which added $352 million of electric margin. Other factors contributing to an increase in Ameren’s electric margin were as follows:
•
An increase in margin on interchange sales of $66 million in 2005 compared with 2004, principally because of higher power prices and access to the MISO Day Two Energy Market. Average realized prices on Ameren’s interchange sales increased from $30 per megawatthour in 2004 to $44 per megawatthour in 2005. Higher market prices for natural gas, emission allowances, and coal in 2005 contributed to the higher power prices. Hurricanes and disruptions in coal delivery contributed to these higher prices. The MISO Day Two Energy Market also contributed to an increase in margins on interchange sales by an estimated $34 million in 2005 as compared to 2004. With the inception of the MISO Day Two Energy Market in 2005, all transmission losses, previously borne by the energy providers, were transferred to MISO, which effectively allowed the generation units to increase sales by approximately 1.8%.
•
Favorable weather conditions, as warmer summer weather in 2005 compared with extremely mild conditions in the summer of 2004 resulted in a 37% increase in cooling degree-days in 2005 in Ameren’s service territory. Excluding the additional nine months of IP sales in 2005, Ameren’s weather-sensitive residential and commercial sales were up 10% and 3%, respectively, in 2005 compared with 2004.
•
Sales to Noranda, which increased electric margin by $33 million. Effective June 1, 2005, UE began to supply approximately 470 megawatts (peak load) of electric service (or about 5% of UE’s generating capability, including committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri under a 15-year agreement.
•
Organic growth.
Factors contributing to a decrease in Ameren’s electric margin were as follows:
•
MISO costs that were $107 million higher in 2005 compared with 2004. MISO costs increased as a result of line losses, transmission congestion charges, and charges associated with volatile weather conditions and deviations of actual from forecasted plant availability and customer loads. Some of these higher costs were attributed to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of plants, and price volatility.
•
Electric rate reductions resulting from the 2002 UE electric rate case settlement in Missouri that negatively affected electric revenues by $7 million during 2005. These were the final rate reductions under the 2002 rate case settlement.
•
An extended refueling and maintenance outage at UE’s Callaway nuclear plant in 2005.
•
Expiration and nonrenewal of low-margin, non-rate-regulated power sales contracts to customers outside our core service territory.
•
Coal conservation efforts that reduced interchange sales.
•
Unscheduled coal-fired plant outages during the peak summer period, which resulted in increased higher-cost CT generation used to serve the demand.
•
Increased utilization and mark-to-market losses on emission allowance put options of $50 million in 2005. However, fuel and purchased power costs were reduced in 2005 by a $21 million gain at Genco resulting from the nonmonetary swap of certain earlier vintage-year SO2 emission allowances for later vintage-year emission allowances.
Ameren’s gas margin increased by $120 million in 2005 compared with 2004, primarily because of the inclusion of an additional nine months of IP results in 2005. Excluding these IP results, gas margin increased $16 million, primarily due to UE’s rate increase, which became effective in the first quarter of 2005, and more favorable weather conditions in the fourth quarter of 2005 than in the same period in 2004.
Missouri Regulated
UE
UE’s electric margin decreased by $22 million in 2005 compared with 2004. Factors contributing to a decrease in UE’s electric margin were as follows:
•
The transfer of UE’s Illinois service territory to CIPS, which was completed in May 2005. This transfer resulted in an estimated decrease in electric margin of $74 million in 2005.
•
Reduced electric rates in the first quarter of 2005 as compared to the first quarter of 2004.
•
Increased MISO Day Two Energy Market costs totaling $59 million in 2005 compared with 2004.
•
Coal conservation efforts that reduced excess plant production and interchange sales.
•
Increased CT generation using high-cost natural gas to serve increased summer demand.
•
A $12 million decrease in emission allowance transactions in 2005 compared with 2004.
Factors contributing to an increase in UE’s electric margin were as follows:
•
Sales to Noranda, which increased electric margin by $33 million.
•
An increase in margins on interchange sales. Margins on interchange sales with nonaffiliates increased $26 million in 2005, compared with 2004, primarily because of higher power prices and access to the MISO Day Two Energy Market. The MISO Day Two Energy Market resulted in an increase in margins on interchange sales by an estimated $23 million in 2005 compared to 2004, as a result of reduced transmission losses.
•
Favorable weather conditions as evidenced by a 25% increase in cooling degree-days in 2005 compared with 2004.
UE’s gas margin increased by $10 million in 2005 compared with 2004, because of the effect of a rate increase in the first quarter of 2005 and favorable weather. This increase was reduced by the May 2005 transfer of UE’s Illinois service territory to CIPS, which decreased the gas margin by $4 million.
Illinois Regulated
Illinois Regulated’s electric margin increased by $41 million, or 5%, in 2005 compared with 2004. Illinois Regulated’s gas margin increased by $5 million, or 2%, in 2005 compared with 2004. See below for explanations of the variances in electric and gas margins for the Illinois Regulated segment.
CIPS
CIPS’ electric margin increased by $41 million in 2005 compared with 2004. Factors contributing to an increase in CIPS’ electric margin were as follows:
•
Increased native load sales as a result of the transfer to CIPS of UE’s Illinois service territory. The transfer of the Illinois service territory resulted in an estimated increase in electric margin of $27 million in 2005.
•
Favorable weather conditions, as evidenced by a 44% increase in cooling degree-days in 2005 compared with 2004.
•
Customers who switched back to CIPS from Marketing Company because tariff rates were below market rates.
CIPS’ electric margin was reduced by a $23 million increase in MISO costs, included in purchased power, in 2005 compared with 2004.
CIPS’ 2005 gas margin was comparable with 2004. The transfer to CIPS of UE’s service territory and favorable weather conditions offset gas inventory and other adjustments. The service territory transfer increased CIPS’ gas margin by $4 million in 2005.
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 2005 compared with 2004:
(a)
See Non-rate-regulated Generation under Results of Operations for an explanation of CILCO’s (AERG) change in electric margin in 2005 compared with 2004.
CILCO’s (Illinois Regulated) electric margin increased by $11 million, or 8%, in 2005 compared with 2004, primarily because of increased native load growth, primarily in the industrial sector, along with more favorable summer weather in 2005 than in 2004.
CILCO’s (Illinois Regulated) gas margin increased by $2 million in 2005 compared with 2004, primarily because of favorable weather in the fourth quarter of 2005.
IP
IP’s electric margin decreased by $11 million in 2005 compared with 2004, primarily because of higher purchased power and MISO costs in 2005. Although power costs decreased in 2005 under IP’s new power supply agreement with DYPM and related purchase accounting adjustments, costs on other power contracts were higher than in 2004. MISO costs included in purchased power were $9 million higher in 2005. The decrease in electric margin was reduced by weather that was more favorable in 2005 than in 2004.
IP’s gas margin increased by $2 million, or 1%, in 2005 compared with 2004 because of a rate increase effective in May 2005 that added $4 million. This benefit was reduced by unfavorable winter weather during the first quarter of 2005.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $27 million, or 4%, in 2005 compared with 2004. See below for explanations of electric margin variances for the Non-rate-regulated Generation segment.
Genco
Genco’s electric margin decreased by $17 million in 2005 compared with 2004. Factors contributing to a decrease in Genco’s electric margin were as follows:
•
A decrease in wholesale margins because Genco had to purchase higher-cost power to serve Marketing Company’s greater load. The increase in load was due to increased volume from the transfer of UE’s Illinois service territory to CIPS and warmer-than-normal weather. Increased purchased power, principally from UE under the JDA, was caused by a major power plant maintenance outage that occurred primarily during the first quarter of 2005.
•
A $26 million increase in emission allowance utilization in 2005 compared with 2004. Emission allowance utilization was reduced in 2005 by a net gain of $15 million associated with a $21 million nonmonetary swap of certain earlier vintage-year SO2 emission allowances for later vintage-year emission allowances, reduced by losses of $6 million on emission allowance options.
The decrease in Genco’s electric margin was reduced by a $23 million increase in margins on interchange sales in 2005 over 2004. The increase in margins on interchange sales was the result of higher power prices and access to the MISO Day Two Energy Market. The MISO Day Two Energy Market resulted in an increase in margins on interchange sales by an estimated $10 million in 2005 over 2004 as a result of reduced transmission losses.
CILCO (AERG)
AERG’s electric margin decreased by $25 million, or 22%, in 2005 compared with 2004. Factors contributing to an increase in AERG’s electric margin were as follows:
•
Lower margins on nonaffiliated interchange sales as output from AERG’s plants was reduced due to outages. The equivalent availability factor for AERG’s plants was 73% in 2005 compared with 84% in 2004. The net capacity factor was 61% in 2005 compared with 66% in 2004.
•
Higher fuel and purchased power costs because of unscheduled plant outages during the peak summer period and increased cost of emission allowance utilization totaling $20 million.
•
An $8 million increase in MISO costs in 2005 compared with 2004.
The decrease in electric margin was reduced by the use of low-cost coal at one of AERG’s power plants in 2005.
EEI
EEI’s electric margin increased by $15 million in 2005 compared with 2004, primarily because of sales of emission allowances.
Other Operations and Maintenance Expenses
2006 versus 2005
Ameren
Ameren’s other operations and maintenance expenses increased $69 million in 2006 over 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 power plant 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 the Delta Air Lines, Inc., lease in 2005 as discussed below, 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, primarily because an anticipated increase in uncollectible accounts due to high gas prices was mitigated by mild winter weather. In 2005, there was a Callaway nuclear plant refueling and maintenance outage that resulted in other operations and maintenance expenses of $31 million; there was no refueling and maintenance outage in 2006. The next refueling and maintenance outage at the Callaway plant is scheduled for the spring of 2007.
Variations in other operations and maintenance expenses at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2006 and 2005 are outlined below.
Missouri Regulated
UE
Other operations and maintenance expenses increased $15 million in 2006 over 2005, primarily because of storm repair expenditures of $38 million, incremental costs associated with the Taum Sauk incident of $25 million, as noted above, and higher power plant maintenance expenses at UE’s coal-fired power plants. Reducing the impact of these unfavorable items were decreased injuries and damages 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 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 $5 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 electric rate increase phase-in plan, along with storm repair and tree trimming expenditures of $5 million 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 electric rate increase phase-in plan of $8 million in 2006, along with higher rental expenses, and higher injuries and damages expenses. The negative effect of these items was reduced by lower labor 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 increased 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.
2005 versus 2004
Ameren
Ameren’s other operations and maintenance expenses increased $150 million in 2005 compared with 2004. IP expenses in the first nine months of 2005 added other operations and maintenance expenses of $166 million to Ameren (it was owned for only three months in 2004). Excluding these IP expenses, other operations and maintenance expenses decreased $16 million. Plant maintenance expenditures decreased as expenses related to the 2005 Callaway nuclear plant refueling and maintenance outage were lower in 2005 than in 2004, as discussed below. Lower employee benefit costs also resulted in reduced other operations and maintenance expenses in 2005. Ameren and several subsidiaries consummated the sale of noncore properties, including leveraged lease assets, in 2005. The net pretax gain on the sale of these assets was $26 million, which reduced other operations and maintenance expenses. Reducing these favorable items was an impairment of $10 million recorded in the third quarter of 2005 for Ameren’s investment in a leveraged lease of an aircraft to Delta Air Lines, Inc., which filed Chapter 11 bankruptcy in September 2005. Additionally, labor costs, other than those incurred for the Callaway refueling and maintenance outage, were higher in 2005 compared with 2004. Ameren, UE and CIPS received a refund of previously paid exit fees totaling $18 million upon their reentry into the MISO during the second quarter of 2004. This refund did not recur in 2005 and, therefore, other operations and maintenance expenses for this item increased in 2005 relative to 2004.
Variations in other operations and maintenance expenses at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2005 and 2004 were as follows.
Missouri Regulated
UE
Other operations and maintenance expenses at UE were comparable in 2005 and 2004. Maintenance and labor costs for refueling and maintenance outages were $31 million in 2005 compared with $39 million in 2004. The 2005 and 2004 refueling and maintenance outages each lasted about 64 days; however, in 2005, the outage included more capital activities and less maintenance activities than in 2004. In 2005, Ameren replaced steam generators and turbine rotors in addition to normal maintenance procedures. Additionally, in 2004, there was an unscheduled outage at the Callaway nuclear plant and planned outages at two coal-fired plants. The transfer of UE’s Illinois service territory to CIPS in May 2005 decreased other operations and maintenance expenses
by $16 million in 2005. Reducing these favorable variances were increased labor costs and storm damage expenses in 2005. Additionally, UE received a $13 million MISO exit fee refund during 2004.
Illinois Regulated
Other operations and maintenance expenses increased $154 million in the Illinois Regulated segment in 2005 compared to 2004, primarily because of the additional nine months of IP results in 2005. Other variances between the years are discussed below.
CIPS
Other operations and maintenance expenses at CIPS were comparable in 2005 and 2004. Information technology, employee benefit, and administrative and general costs decreased in 2005. These positive items were offset by the transfer of UE’s Illinois service territory to CIPS, which resulted in an increase in other operations and maintenance expenses of $16 million in 2005. Additionally, CIPS received a $5 million MISO exit fee refund during 2004 that did not recur in 2005.
CILCO (Illinois Regulated)
Other operations and maintenance expenses at CILCO (Illinois Regulated) decreased $28 million in 2005 from 2004. These expenses decreased primarily because of lower employee benefit costs in 2005 and the absence of an $8 million charge we paid in 2004 to settle a litigation claim by Enron Power Marketing, Inc., in conjunction with Ameren’s acquisition of CILCORP in 2003.
IP
IP’s other operations and maintenance expenses increased $39 million in 2005 over 2004, partly because IP received a refund of previously paid exit fees of $9 million from MISO during 2004. Other operations and maintenance expenses also increased, including tree trimming costs and overhead and labor costs associated with the integration of systems and operations with Ameren in 2005.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $13 million in 2005 compared with 2004 in the Non-rate-regulated Generation segment, as detailed below.
Genco
Other operations and maintenance expenses at Genco increased $4 million in 2005 over 2004, primarily because of a major power plant maintenance outage in 2005. These costs were reduced by lower employee benefit costs.
CILCORP (Parent Company Only)
Other operations and maintenance expenses were comparable in 2005 and 2004.
CILCO (AERG)
Other operations and maintenance expenses increased $6 million in 2005 over 2004, primarily because of increased plant maintenance expenditures resulting from power plant outages.
EEI
Other operations and maintenance expenses increased $5 million in 2005 over 2004, primarily because of increased power plant maintenance expenditures.
Depreciation and Amortization
2006 versus 2005
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 at Ameren’s, CILCORP’s and CILCO’s 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, a portion of which were related to 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 due to CTs transferred to UE from Genco in May 2005. Reducing depreciation expense was the transfer of property 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.
CIPS
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.
2005 versus 2004
Ameren
Ameren’s depreciation and amortization expenses increased $75 million in 2005 from 2004, principally because of an additional nine months of IP results in 2005, which added $59 million. Capital additions also resulted in increased depreciation expenses in 2005.
Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2005 and 2004 were as follows.
Missouri Regulated
UE
Depreciation and amortization expenses at UE increased $16 million in 2005 over 2004. The increases were primarily due to capital additions and depreciation on CTs transferred from Genco to UE in May 2005, partially offset by the elimination of depreciation on property transferred by UE to CIPS in the Illinois service territory transfer in May 2005.
Illinois Regulated
Depreciation and amortization expenses increased $66 million in the Illinois Regulated segment in 2005 compared to 2004, primarily because of the additional nine months of IP results in 2005. Other variances between the years are discussed below.
CIPS
CIPS’ depreciation and amortization expenses increased $7 million in 2005 over 2004, primarily because of depreciation on property transferred in May 2005 from UE in the Illinois service territory transfer and capital additions.
CILCO (Illinois Regulated)
Depreciation and amortization expenses at CILCO (Illinois Regulated) were comparable in 2005 and 2004.
IP
IP’s depreciation and amortization expenses, excluding the amortization of regulatory assets, were comparable in 2005 and 2004. Amortization of regulatory assets at IP decreased $33 million in 2005 from 2004. The transition cost regulatory asset was eliminated in conjunction with Ameren’s acquisition of IP in September 2004.
Non-rate-regulated Generation
Depreciation and amortization expenses in the Non-rate-regulated Generation segment decreased $4 million in 2005 compared with 2004, principally at Genco, because of the transfer of CTs from Genco to UE in May 2005.
Depreciation and amortization expenses were comparable in 2005 and 2004 at CILCORP (Parent Company Only), CILCO (AERG) and EEI.
Taxes Other Than Income Taxes
2006 versus 2005
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 at Ameren’s, CILCORP’s and CILCO’s 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
Taxes other than income taxes increased $18 million in 2006 compared with 2005 in the Illinois Regulated segment. Taxes other than income taxes increased $8 million at CIPS, $4 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
Taxes other than income taxes increased $7 million in 2006 compared with 2005 at Non-rate-regulated Generation, primarily because of higher property taxes at Genco. There was a favorable court decision in the first quarter of 2005 that did not recur in 2006. Taxes other than income taxes were comparable in 2006 and 2005 at CILCORP (Parent Company Only), CILCO (AERG), and EEI.
2005 versus 2004
Ameren
Ameren’s taxes other than income taxes increased $53 million in 2005 over 2004, principally because of an additional nine months of IP results in 2005, which added $54 million.
Variations in taxes other than income taxes at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2005 and 2004 were as follows.
Missouri Regulated
UE
UE’s taxes other than income taxes increased $7 million in 2005 over 2004, primarily because of increased property taxes due to higher assessments. These property tax increases were mitigated in 2005 by the transfer of UE’s Illinois service territory to CIPS.
Illinois Regulated
Taxes other than income taxes increased $55 million in the Illinois Regulated segment in 2005 compared to 2004, primarily because of the additional nine months of IP results in 2005. Other variances between the years are discussed below.
CIPS
Taxes other than income taxes at CIPS were $7 million higher in 2005 than in 2004, primarily because of increased property taxes resulting from the transfer to CIPS of UE’s Illinois service territory in May 2005.
CILCO (Illinois Regulated)
Taxes other than income taxes decreased $4 million in 2005 from 2004 at CILCO (Illinois Regulated), primarily because of reduced gross receipts and property taxes.
IP
Taxes other than income taxes at IP were comparable in 2005 and 2004.
Non-rate-regulated Generation
Taxes other than income taxes decreased $8 million in 2005 compared with 2004 in the Non-rate-regulated Generation segment, primarily because of a favorable court decision in 2005 regarding property taxes at Genco. Taxes other than income taxes were comparable in 2005 and 2004 at CILCORP (Parent Company Only), CILCO (AERG) and EEI.
Other Income and Expenses
2006 versus 2005
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. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report. This amount is offset by an equivalent amount of interest expense associated with a capital lease for the CT recorded in interest charges on Ameren’s and UE’s statements of income. Miscellaneous expense decreased $8 million, primarily due to decreased donations in 2006 and the write-off of unrecoverable natural gas costs in 2005.
Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s 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 UE’s CT capital lease as noted above, 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 at Illinois Regulated, CIPS, CILCO (Illinois Regulated) and IP in 2006 and 2005.
Non-rate-regulated Generation
Other income and expenses were comparable at Non-rate-regulated Generation, Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in 2006 and 2005.
2005 versus 2004
Ameren
Other income and expenses at Ameren decreased $10 million in 2005 compared with 2004. Excluding the additional nine months of IP results in 2005, other income and expenses at Ameren decreased $14 million from 2004. Miscellaneous income decreased $8 million, primarily due to reduced interest income from the investment of equity issuance proceeds in the prior year. Miscellaneous expense increased $6 million, primarily because of unrecoverable natural gas cost write-offs at CIPS and CILCO and integration costs at IP in 2005.
Variations in other income and expenses at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2005 and 2004 were as follows.
Missouri Regulated
UE
Other income and expenses were comparable in 2005 and 2004.
Illinois Regulated
Other income and expenses decreased $7 million in the Illinois Regulated segment in 2005 compared with 2004, including the additional nine months of IP results in 2005. Variances between the years are discussed below.
CIPS
Miscellaneous income decreased $6 million in 2005 from 2004 at CIPS, primarily because of reduced interest income on intercompany note receivable from Genco. Miscellaneous expense increased $3 million primarily because of the write-off in 2005 of unrecoverable natural gas costs.
CILCO (Illinois Regulated)
Other income and expenses were comparable in 2005 and 2004.
IP
Miscellaneous income at IP decreased $138 million in 2005 from 2004, primarily because of reduced interest income after the elimination of IP’s note receivable from a former affiliate in conjunction with Ameren’s acquisition of IP on September 30, 2004. Miscellaneous expense increased $2 million primarily as a result of acquisition-related integration costs.
Non-rate-regulated Generation
Other income and expenses were unfavorable $6 million in 2005 compared with 2004 in the Non-rate-regulated Generation segment, as detailed below.
CILCORP (Parent Company Only)
Miscellaneous income decreased $2 million in 2005 from 2004, primarily because of derivative mark-to-market adjustments. Miscellaneous expense was comparable between periods.
Genco, CILCO (AERG) and EEI
Other income and expenses were comparable in 2005 and 2004.
See Note 7 - Other Income and Expenses to our financial statements under Part II, Item 8, of this report for further information.
Interest
2006 versus 2005
Ameren
Ameren’s interest expense increased $49 million in 2006 over 2005 primarily because of items noted below in Ameren’s, CILCORP’s and CILCO’s business segments and for each of the Ameren Companies individually.
Missouri Regulated
UE
Interest expense increased $55 million in 2006 over 2005 as a result of the issuances of $300 million of senior secured notes in July 2005 and $260 million of senior secured notes in December 2005, along with increased short-term borrowings, resulting in part from 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 recorded in Other income and deductions on Ameren’s and UE’s statements of income.
Illinois Regulated
Interest expense increased $9 million in 2006 compared with 2005 in the Illinois Regulated segment, primarily because of the issuance of $75 million of senior secured notes in June 2006 along with increased money pool borrowings at IP. Interest expense at CIPS and CILCO (Illinois Regulated) was comparable in 2006 and 2005.
Non-rate-regulated Generation
Interest expense decreased $16 million in 2006 compared with 2005 in the Non-rate-regulated Generation segment. It decreased $13 million at Genco resulting from the maturity of its $225 million of senior notes in 2005. Interest expense at CILCORP (Parent Company Only), CILCO (AERG) and EEI was comparable in 2006 and 2005.
2005 versus 2004
Ameren
Interest expense increased $23 million at Ameren in 2005 over 2004, principally because of the acquisition of IP, which added $32 million of interest for the first nine months of 2005. Excluding the additional IP interest expense in 2005, Ameren’s interest expense decreased $9 million, primarily because of items discussed below in Ameren’s, CILCORP’s and CILCO’s business segments and for each of the Ameren Companies individually.
Missouri Regulated
UE
UE’s interest expense increased $13 million in 2005 over 2004, primarily because of the issuances of $300 million senior secured notes in July 2005, $85 million senior secured notes in January 2005, and $300 million senior secured notes in September 2004, partially offset by maturities of $188 million of first mortgage bonds in August 2004 and $85 million of first mortgage bonds in December 2004 and the redemption of $100 million first mortgage bonds in June 2004.
Illinois Regulated
Interest expense increased $24 million in the Illinois Regulated segment in 2005 compared with 2004, primarily because of the additional nine months of IP results in 2005. Other variances between the years are discussed below.
CIPS
Interest expense decreased $3 million in 2005 from 2004, primarily because of the redemption of $70 million of environmental revenue bonds in December 2004.
CILCO (Illinois Regulated)
Interest expense was comparable in 2005 and 2004.
IP
Interest expense at IP decreased $87 million in 2005 from 2004, primarily because of redemptions and repurchases of indebtedness of $700 million in the fourth quarter of 2004 and $70 million in early 2005 and reductions in notes payable to IP SPT.
Non-rate-regulated Generation
Interest expense decreased $27 million in 2005 compared with 2004 in the Non-rate-regulated Generation segment, as detailed below. Additionally, interest expense decreased $4 million at other non-rate-regulated subsidiaries, primarily because of reduced money pool borrowings.
Genco
Genco’s interest expense decreased $21 million in 2005 from 2004, primarily because of the maturity of $225 million of senior notes in November 2005, lower average money pool borrowings, and a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren. The outstanding balance on the intercompany note payable to CIPS was $197 million at December 31, 2005, compared with $283 million at December 31, 2004. The intercompany note payable to Ameren was repaid in 2005.
CILCORP (Parent Company Only), CILCO (AERG) and EEI
Interest expense was comparable in 2005 and 2004.
Income Taxes
2006 versus 2005
Ameren
Ameren’s effective tax rate decreased in 2006 from 2005, primarily because of differences between the book and tax treatment of the sale of noncore properties, as well as items discussed below.
Variations in effective tax rates at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2006 and 2005 were as follows
Missouri Regulated
UE
Effective tax rate increased over the prior year primarily because of an increase in nondeductible expenses and an increase in reserves for uncertain tax positions related to tax returns filed in the current year.
Illinois Regulated
Effective tax rate increased in 2006 from 2005 at Illinois Regulated, primarily because of the items detailed below.
CIPS
Effective tax rate decreased from the prior year, primarily because of favorable tax return to accrual adjustments.
CILCO (Illinois Regulated)
Effective tax rate increased in 2006 over 2005, primarily because of unfavorable tax return to accrual adjustments and an increase in nondeductible expenses.
IP
Effective tax rates were comparable in 2006 and 2005.
Non-rate-regulated Generation
Effective tax rate decreased in 2006 compared with 2005 at Non-rate-regulated Generation, primarily because of the items detailed below.
Genco
Effective tax rate decreased in 2006 from 2005 primarily because of favorable tax return to accrual adjustments and the resolution of uncertain tax positions in the current year based on favorable developments with taxing authorities.
CILCO (AERG)
Effective tax rate decreased in 2006 from 2005 primarily because of favorable tax return to accrual adjustments and the resolution of uncertain tax positions in the current year based on favorable developments with taxing authorities.
CILCORP (Parent Company Only)
Effective tax rate decreased over the prior year, primarily because of favorable tax return to accrual adjustments.
EEI
Effective tax rates were comparable in 2006 and 2005.
2005 versus
Ameren
Ameren’s effective tax rate increased in 2005 from 2004, primarily because of items discussed below at the various subsidiaries.
Variations in effective tax rates at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2005 and 2004 were as follows.
Missouri Regulated
UE
Effective tax rates were comparable in 2005 and 2004.
Illinois Regulated
Effective tax rate increased in the Illinois Regulated segment, primarily because of the items detailed below.
CIPS
Effective tax rate increased in 2005 over 2004, primarily because of unfavorable tax return to accrual adjustments.
CILCO (Illinois Regulated)
Effective tax rate decreased in 2005 from 2004, primarily because of favorable tax return to accrual adjustments, along with tax benefits related to company-owned life insurance.
IP
Effective tax rate increased in 2005 over 2004, primarily because of the cessation of amortization of investment tax credits after Ameren’s acquisition of IP.
Non-rate-regulated Generation
Effective tax rate increased in 2005 over 2004 in the Non-rate-regulated Generation segment, primarily because of the items detailed below.
Genco
Effective tax rate increased in 2005 over 2004, primarily because of increases in reserves for uncertain tax positions based on unfavorable developments with taxing authorities, offset by deductions under Section 199.
CILCORP (Parent Company Only)
Effective tax rate increased in 2005 over 2004, primarily because of increases related to unfavorable tax return to accrual adjustments.
CILCO (AERG)
Effective tax rate increased in 2005 over 2004, primarily because of an increase in reserves for uncertain tax positions based on unfavorable developments with taxing authorities.
EEI
Effective tax rate decreased in 2005 from 2004, primarily because of benefits related to the Section 199 deduction.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO 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 and IP. For operating cash flows prior to 2007, Genco principally relied on power sales to an affiliate under a contract that expired at the end of 2006, and on sales to other wholesale and industrial customers under short and long-term contracts. Beginning in 2007, Genco and AERG will sell power previously sold under contracts that expired at the end of 2006 to Marketing Company, which has sold power through the Illinois power procurement auction and is selling power through other primarily market-based contracts with wholesale and retail customers. The amount of power that Genco, AERG, EEI, Marketing Company and their affiliates may supply to CIPS, CILCO and IP through the Illinois power procurement auction is limited to 35% of CIPS’, CILCO’s and IP’s aggregate annual load. In addition to cash flows from operating activities, each of the Ameren Companies plans to use available cash, money pool, or other short-term borrowings from affiliates, commercial paper, or credit facilities 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, 2006, for Ameren, UE, Genco, CILCORP, CILCO and IP. The Ameren Companies will reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings or equity infusions from Ameren. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 of this report for a discussion of an Illinois legislative proposal to freeze electric rates at 2006 levels for CIPS, CILCO and IP. If such legislation is enacted, CIPS, CILCORP, CILCO and IP will not have enough operating cash flow to support normal operations, which would lead to financial insolvency.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
2004 amounts include predecessor financial information prior to the acquisition date of September 30, 2004.
Cash Flows from Operating Activities
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 were an $84 million decrease in pension and postretirement benefit contributions in 2006 compared with 2005, and the collection of higher-than-normal trade receivables caused by cold December 2005 weather during the winter heating season. The cash impact from trade receivables was more significant in the current period because we had higher gas prices and colder December weather in 2005 than in the year-ago period. 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 Taum Sauk upper reservoir in December 2005, and $37 million of other operations and maintenance expenses due to severe storms. Most of the Taum Sauk expenditures are pending recovery from insurance carriers. 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 than they were a year ago 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 14 - 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 compared with 2005. Other operations and maintenance expenses were comparable with the previous year, despite $59 million (including $10 million for a FERC fine) spent due to the breach of the Taum Sauk upper reservoir collapse 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 there was increased debt outstanding. Cash used for coal purchases increased compared with 2005 because of alleviation of 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 compared to 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 compared with the year-ago period. 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 in 2006 by $17 million compared with 2005, pension and postretirement benefit payments decreased $9 million, and interest payments were lower in the 2006 period 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 the year-ago period. 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 was the collection of higher-than-normal trade receivables caused by cold December 2005 weather during the heating season, 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 during 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.
2005 versus
Ameren’s increase in cash from operations in 2005, compared with 2004, was primarily attributable to $207 million of incremental IP operating cash flow in the nine months ended September 30, 2005, since Ameren did not own IP during the comparable period in 2004. Excluding the impact of IP, Ameren’s increase in electric and gas margins of $14 million and $16 million, respectively, also contributed to the increase in cash from operations. In addition, decreased pension and other postretirement benefit contributions of $206 million and decreased interest payments of $30 million contributed to the favorable variance in cash from operations. Reducing the positive variance in 2005 were increased tax payments of $159 million, the absence in 2005 of $36 million of cash from the UE coal contract settlement received in 2004, and an increase in net investment in inventories and trade receivables and payables due to higher gas prices and colder weather in December 2005 compared to December 2004. The absence in 2005 of $34 million of refunds in 2004 for previously paid fees to MISO and RTO start-up costs also reduced the positive variance in cash from operations. Ameren’s working capital investment in coal inventories as of December 31, 2005, did not change significantly, compared with 2004, as a million-ton decrease in volumes due to rail derailments was offset by higher prices.
At UE, cash from operating activities in 2005 was generally consistent with changes in its results of operations and its operating cash flows in 2004. A $127 million decrease in pension and postretirement contributions benefited 2005 operating cash flow as compared with 2004. Significant items negatively impacting cash in 2005 compared with 2004 include: increased tax payments of $37 million; less cash from electric margins and emissions sales of $36 million; the impact of the coal contract settlement discussed above; the absence of $20 million received in 2004 for MISO exit fees and RTO start-up costs discussed above; and increased working capital investment, primarily because of timing differences, prices, and weather as discussed above.
CIPS’ increase in cash from operating activities in 2005 was principally due to increased electric margins of $41 million, a reduction of $23 million in pension and postretirement benefit contributions, and reduced interest and tax payments. This was reduced by increases in cash outflows caused by differences in the timing and amount of working capital items, compared with 2004.
Cash from operating activities increased for Genco in 2005 compared with 2004, primarily because of reduced pension and postretirement contributions of $20 million and lower interest payments of $39 million. Reducing this increase were increased tax payments of $41 million.
Cash from operating activities decreased for CILCORP and CILCO in 2005 compared with 2004, primarily because of increased tax payments of $60 million for CILCORP and $54 million for CILCO, lower electric margins of $16 million for CILCORP and $14 million for CILCO, and increased working capital investment at CILCORP and CILCO, primarily due to higher prices and colder weather, which increased inventories and receivables by $20 million and $28 million for CILCORP and $20 million and $31 million for CILCO.
CILCORP’s cash from operating activities was also negatively affected by additional interest payments of $14 million in 2005 compared with 2004. These decreases were reduced by a decrease in pension and other postretirement contributions of $33 million.
IP’s cash from operations in 2005 compared with 2004 was affected by Ameren’s ownership of IP for all of 2005 compared with only the fourth quarter of 2004. IP’s operating cash flows in 2005 are not directly comparable with 2004’s because of the integration of IP into Ameren’s operations, significant changes in capital structure, termination of certain of IP’s former affiliate agreements, and new purchased power arrangements, among other factors. IP’s cash from operations in 2005 benefited from lower taxes paid of $141 million, which resulted mostly from changes in taxable income and deferred tax benefits from accelerated depreciation resulting from the acquisition, and lower interest paid of $93 million. Negative impacts to IP’s operating cash in 2005 included the absence of $128 million of interest received from IP’s former affiliate, increased cash required for other operations and maintenance expenses of $59 million, and increased working capital investment. Significant drivers of the increase in working capital investment were colder weather and higher gas prices in December 2005, which increased receivables and gas inventories. IP’s gas sales were up 45% over December 2004.
Pension Funding
Ameren’s 2004 and 2005 contributions to the defined benefit retirement plan’s qualified trusts, among other things, provide cost savings, because they mitigate future benefit cost increases. In addition, the contribution in 2004 allowed us to avoid paying a portion of the insurance premium to the Pension Benefit Guaranty Trust Corporation. Federal interest rate relief expired on December 31, 2005. Based on our assumptions at December 31, 2006, and the new contribution requirements in the Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect to contribute $100 million to $150 million. Required contributions of $150 million to $200 million each year are also expected for 2010 and 2011. We expect the companies to share the obligation: UE - 61%; CIPS - 10%; Genco - 11%; CILCO - 7%; and IP - 11%. These amounts are estimates. They may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. See Note 10 - Retirement Benefits to our financial statements under Part II, Item 8, of this report for additional information.
Cash Flows from Investing Activities
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 are intended to meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining the timing of future base-load 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 as discussed below in the Sale of Noncore Properties section.
UE’s cash used in investing activities decreased in 2006, compared with the same period in 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 storms referenced above 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 impacting CIPS’ investing cash flow was an $18 million reduction in proceeds from CIPS’ note receivable from Genco in 2006 compared with 2005. 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 bond is expected to be redeemed in 2007. 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 payable of $71 million that 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 proceeds in 2005 from 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.
See Note 14 - 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.
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.
Sale of Noncore Properties
In 2006, Ameren, UE, CILCORP, and CILCO generated proceeds totaling $56 million (2005 - $54 million), $13 million (2005 - $- million), $11 million (2005 - $13 million), and $11 million (2005 - $13 million), respectively, from the sale of certain noncore properties, including leveraged leases.
Prior to the 2005 leveraged lease sale, CILCORP transferred certain of its direct and indirect subsidiaries that hold leveraged leases to Resources Company and AERG in exchange for a note receivable. Additionally, an indirect subsidiary of CILCORP that owned leveraged leases was transferred to AERG in exchange for a note receivable.
See Note 3 - Rate and Regulatory Matters to our financial statements, under Part II, Item 8 of this report for a discussion of the noncore property sales.
2005 versus
Ameren had a decrease in cash used in investing activities, primarily because of $429 million used to acquire IP in 2004. That decrease was partially offset by a $97 million increase in capital expenditures reflecting a full year of IP capital expenditures in 2005 compared with three months of IP expenditures in 2004, and the increased capital expenditures at UE discussed below.
UE’s cash used in investing activities increased in 2005, primarily because UE spent $237 million to purchase 550 megawatts of CTs from Genco and $25 million to purchase CT equipment from Development Company. Excluding these CT acquisitions, UE’s capital expenditures in 2005 were consistent with those in 2004. UE maintained consistent plant expenditures by allocating fewer resources to projects at its coal-fired plants as it spent $221 million of expenditures at its Callaway nuclear plant for upgrades during a refueling and maintenance outage.
CIPS had a net use of cash in 2005 compared with net cash proceeds from investing activities in 2004, primarily because of an $18 million increase in capital expenditures and a $72 million reduction in cash received from principal payments on a note receivable from Genco. The increased capital expenditures were used to improve the reliability of CIPS’ transmission and distribution systems.
Genco had a net source of cash in 2005, compared with a net use of cash from investing activities in 2004, primarily because of the sale of 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, to UE for $241 million. The benefit of these proceeds was reduced by increased capital expenditures for upgrades at one of its power plants in 2005 and by an increase in emission allowance purchases of $64 million.
CILCORP’s and CILCO’s cash used in investing activities decreased in 2005 from 2004, primarily because CILCORP and CILCO reduced capital expenditures and received proceeds of $13 million in 2005 from the sale of leveraged leases. In 2004, CILCO’s subsidiary, AERG, made capital expenditures for significant power plant upgrades to increase fuel supply flexibility for power generation. The purchase of emission allowances negatively affected cash by $20 million more in 2005 than in 2004.
IP had net proceeds of cash in 2005 and a net use of cash in 2004, primarily because of proceeds of $140 million for repayments of advances made to the money pool by IP in 2004.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2006, 2005, and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
The 2004 amounts include $100 million incurred prior to the acquisition date of September 30, 2004.
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 towards 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. The scrubbers are necessary to comply with environmental regulations. 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 and 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 UE’s Callaway nuclear plant. Ameren and UE also incurred expenditures of $65 million for three CTs at UE’s Venice plant, $60 million for numerous projects at UE’s 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.
Ameren’s capital expenditures for 2004 were made principally for various upgrades at UE’s power plants, including the replacement of condenser bundles, and other upgrades during the 2004 refueling and maintenance outage at UE’s Callaway nuclear plant. The replacement and upgrade work at UE’s Callaway plant resulted in capital expenditures of $40 million in 2004. In addition, UE incurred costs for steam generators and low pressure rotors that were replaced during the 2005 refueling and maintenance outage at the Callaway nuclear plant. UE also incurred capital expenditures related to the installation of new CTs at its Venice plant and replacement of turbines at two of its power plants in 2004. In addition, UE’s capital expenditures included environmental and other upgrades at its power plants and expenditures for new transmission and distribution lines. CILCORP’s and CILCO’s capital expenditures in 2004 were primarily related to power plant projects to improve flexibility in future fuel supply for power generation. Genco’s 2004 capital expenditures were primarily attributed to the replacement of a turbine generator at one of its power plants. Capital expenditures at IP and CIPS consisted of numerous projects to upgrade and maintain the reliability of their respective electric and gas transmission and distribution systems and to add new customers to the systems.
The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2007 through 2011, 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 upgrades to existing coal and gas-fired generating facilities and compliance with new environmental regulations. CILCO (AERG)’s estimate includes capital expenditures for generation-related activities, as well as for compliance with new environmental regulations at AERG’s generating facilities.
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.
The EPA issued final SO2, NOx, and mercury emission regulations in May 2005. The rules require significant reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. States were mandated to develop their own regulations as well. In February 2007, the Missouri Air Conservation Commission approved the proposed federal Clean Air Mercury and Clean Air Interstate rules, which substantially follow the federal rules. In December 2006, the Illinois Pollution Control Board adopted the mercury regulations, which are significantly stricter than the federal rules. Illinois has proposed rules to implement the federal Clean Air Interstate Rule program;
however it is anticipated that the rules will not be finalized until the second quarter of 2007. The table below presents estimated capital costs based on current technology to comply with both (1) the federal Clean Air Interstate Rule and Clean Air Mercury Rule through 2016, and (2) Illinois’ mercury regulations pursuant to an agreement between Genco, CILCO, EEI, and the Illinois EPA. Under the agreement, Genco, CILCO and EEI may delay the compliance date for mercury reductions in exchange for accelerated installation of NOx and SO2 controls. The agreement with the Illinois EPA also restricts purchasing SO2 and NOx emission allowances to meet specific allowed emission rates set forth in the agreement. 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 by June 2007 and the federal fine particulate ambient standard by April 2008. The costs in the table assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet this new standard in the St. Louis region. Should Missouri develop an alternative plan to comply with this standard, the cost impact could be material to UE. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for ozone and fine particulate. At this time, we are unable to determine the impact state actions would have on our results of operations, financial position, or liquidity.
See Note 14 - 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
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 used in 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, but 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, compared with the year-ago period.
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 the 2006 period compared with the 2005 period.
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, compared with 2005. 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 compared with the year-ago period, because 2005 included net borrowings on this note that provided CILCORP with cash. Positive effects on cash flow include 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, compared with 2005, 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. 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.
2005 versus
Ameren had a net use of cash used for financing activities in 2005, compared with a net source of cash in 2004, primarily because of a $1 billion decrease in proceeds from common stock issuances in 2005 compared with 2004. The common stock proceeds in 2004 were principally used to fund the acquisition of IP and Dynegy’s 20% interest in EEI on September 30, 2004, and to repurchase and redeem certain IP indebtedness subsequent to the acquisition. In 2005, total common stock proceeds of $454 million included $345 million from the issuance of 7.4 million shares of common stock related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units. The 2005 increase in cash used in financing activities was also attributable to $224 million of net redemptions of short-term debt, compared with net proceeds of $256 million in 2004. Decreased long-term debt redemptions of $847 million, increased long-term debt issuances of $185 million, and the absence in 2005 of a $67 million UE nuclear fuel lease payment in 2004 partially offset the decrease in cash from financing activities in 2005.
UE cash provided by financing activities increased in 2005, compared with 2004, primarily because of a $374 million decrease in long-term debt redemptions, a $239 million increase in issuances of long-term debt, a $35 million decrease in the payment of dividends to Ameren, and the absence of a $67 million nuclear fuel lease payment that was made in 2004. These 2005 benefits in cash from financing activities were partially offset by $295 million used for short-term debt repayments; in 2004, UE had net proceeds from short-term debt.
CIPS’ cash used in financing activities decreased in 2005 from 2004, primarily because of a $40 million cash increase from reduced dividends paid to Ameren, and decreased long-term debt redemptions of $50 million. These positive effects on cash were partially offset by decreased issuances of long-term debt of $35 million and net repayments of utility money pool borrowings of $13 million.
Genco’s cash used in financing activities increased in 2005 from 2004, primarily because of a $225 million long-term debt redemption in 2005 and increased payments of $30 million on its note payable to Ameren. The funds for these repayments came from the $241 million in proceeds from the 2005 sale of 550 megawatts of CTs to UE. Net cash used in financing activities also increased because of a capital contribution decrease of $72 million. A reduction of $72 million in payments on a note payable to CIPS and a net increase in non-state-regulated subsidiary money pool borrowings of $95 million, partially offset the additional uses of cash.
Effective May 1, 2005, Genco and CIPS amended certain terms of Genco’s subordinated affiliate note payable to CIPS by issuing to CIPS an amended and restated subordinated promissory note for $249 million with an interest rate of 7.125% per year, a five-year amortization schedule, and a maturity of May 1, 2010.
CILCORP and CILCO had a net source of cash in financing activities in 2005, compared with a net use of cash in 2004. For CILCORP, an $88 million increase in proceeds from an intercompany note payable to Ameren and from decreased long-term debt redemptions of $41 million benefited cash. Reducing these increases were an increase in net repayments of money pool borrowings of $33 million and lower long-term debt issuances of $19 million. CILCO’s increase in cash from financing activities was mainly due to decreased long-term debt redemptions of $103 million and increased capital contributions from Ameren of $27 million. Reducing these increases were increased net repayments of utility money pool borrowings of $36 million and increased dividend payments of $10 million.
IP had a net use of cash in investing activities in 2005, compared with a net source of cash in 2004, primarily because 2004 included an $871 million capital contribution from Ameren. IP’s $76 million increase in dividends to Ameren also contributed to IP’s increase in cash used in financing activities. These negative effects on cash were reduced by lower redemptions and repurchases of long-term debt of $732 million and by $75 million of cash received from utility money pool borrowings.
Short-term Borrowings and Liquidity
Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities of 1 to 45 days. See Note 5 - 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 as of February 9, 2007, and the availability as of December 31, 2006:
(a)
Ameren Companies may access this credit facility through intercompany borrowing arrangements.
(b)
See Note 5 - 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, including for issuance of letters of credit, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. Borrowings by CIPS, CILCO and IP under this facility are on a 364-day basis. See Note 5 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for discussion of this credit facility.
(d)
This credit facility was entered into on February 9, 2007. The maximum amount available to each borrower, including for the issuance of letters of credit, is limited as follows: CILCORP - $125 million, IP - $200 million and AERG - $200 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. CIPS’, CILCO’s and IP’s participation in the 2007 $500 million credit facility is subject to appeal by the ICC. Borrowings by CIPS, CILCO and IP under this facility are on a 364-day basis. See Note 5 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report for a discussion of this credit facility.
At December 31, 2006, Ameren and certain of its subsidiaries had $1.65 billion of committed credit facilities, consisting of two facilities as described below, in the amounts of $1.15 billion and $500 million.
Ameren could directly borrow under the $1.15 billion facility up to the entire amount of the facility; UE could directly borrow under this facility up to $500 million on a 364-day basis; and Genco could directly borrow under this facility up to $150 million on a 364-day basis. 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, AFS and Ameren Energy, 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 agreements. See Note 5 - 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 Ameren from time to time is available cash and cash equivalents. At December 31, 2006, Ameren had $137 million 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 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. IP has unlimited short-term debt authorization from FERC.
Genco is authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt authorization from FERC.
With the repeal of PUHCA 1935, the issuance of short-term unsecured debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer 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 2006, 2005 and 2004 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 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.
(a)
Ameren’s and UE’s long-term debt increased $240 million 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.
(b)
Represents borrowings made under the $1.15 billion credit facility discussed in Note 5 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report.
(c)
Shares issued upon settlement of the purchase contracts, which were a component of the adjustable conversion-rate equity security units.
(d)
Component of the adjustable conversion-rate equity security units.
(e)
Amounts for IP before September 30, 2004, have not been included in the total long-term debt and preferred stock redemption and repurchases at Ameren.
(f)
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, 2006:
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 certain of its 401(k) plans pursuant to effective SEC Form S-8 registration statements. Under DRPlus and its 401(k) plans, Ameren issued 1.9 million, ($96 million) shares of common stock in 2006, 2.1 million ($109 million) in 2005, and 2.3 million ($107 million) in 2004.
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 5 - 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 6 - 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, 2006, 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, such as the legislation proposed to freeze electric rates at 2006 levels in Illinois for CIPS, CILCO and IP, may create
uncertainty in the capital markets. Such events would probably increase our cost of capital or adversely affect our ability to access the capital markets. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further discussion.
Dividends
Ameren paid to its shareholders common stock dividends totaling $522 million, or $2.54 per share, in 2006, $511 million, or $2.54 per share, in 2005, and $479 million, or $2.54 per share, in 2004. This resulted in a payout rate based on net income of 95% in 2006, 84% in 2005, and 90% in 2004. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 41% in 2006, 41% in 2005 and 43% in 2004.
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, and overall business considerations. On February 9, 2007, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on March 30, 2007, to shareholders of record on March 7, 2007.
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, 2006, except as described below with respect to the 2006 $500 million credit facility, none of these conditions existed at the Ameren Companies. As a result, they were allowed to pay dividends. The restrictions on the ability of IP to declare and pay dividends on its common stock that were established by the ICC order approving Ameren’s acquisition of IP terminated in December 2006 with IP’s redemption of the remaining $33,000 of its 11.50% series mortgage bonds due 2010. This ICC order also requires IP to establish 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%.
On July 14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a $500 million multiyear, senior secured credit facility (the “2006 $500 million credit facility”). This facility limits 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, get 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 consolidated total debt to consolidated operating cash flow ratio, 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, 2006, AERG failed to meet the debt-to-operating cash flow ratio test in the 2006 $500 million credit facility. AERG therefore is currently limited in its ability to pay dividends to a maximum of $10 million per fiscal year. The other borrowers are not currently limited in their dividend payments by this provision of the 2006 $500 million credit facility. On February 9, 2007, CIPS, CILCORP, CILCO, IP and AERG entered into another $500 million multiyear senior secured credit facility (the “2007 $500 million credit facility”) which contains identical provisions restricting the payment of dividends. See Note 5 - Credit Facilities and Liquidity to our financial statements under Part II, Item 8, of this report.
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 $65 million, $20 million and $10 million for the years ended December 31, 2006, 2005 and 2004, respectively.
(b)
Before October 2004, the ICC prohibited IP from paying dividends. If permitted, IP’s dividends would have been paid directly to Illinova and indirectly to Dynegy.
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 9 - 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, 2006. See Note 10 - 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)
The weighted average variable rate debt has been calculated using the interest rate as of December 31, 2006.
(c)
Excludes unamortized discount of $6 million at UE, $1 million at CIPS, $1 million at Genco, and $4 million at IP.
(d)
Excludes fair market value adjustments of long-term debt of $60 million for CILCORP and $32 million for IP.
(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)
Represents purchase contracts for coal, gas, nuclear fuel, and power.
(g)
Represents parent company only.
Off-Balance-Sheet Arrangements
At December 31, 2006, 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:
On October 10, 2006, Moody’s placed the long-term credit ratings of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP under review for possible downgrade, and affirmed the commercial paper ratings of Ameren and UE. Moody’s had removed the review for possible downgrade in July 2006. According to Moody’s, the review for possible downgrade was reinstituted because of concerns that the timely recovery of increased utility costs could be impaired by legislative action in Illinois, specifically the rate freeze legislation discussed in Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report. Moody’s stated that enactment of the rate freeze legislation in Illinois would be expected to result in a multi-notch downgrade of the ratings of CIPS, CILCO and IP to speculative (sub-investment) grade, reflecting the severe impact such action would have on the utilities’ cash flow and liquidity. Moody’s has also indicated that if legislation freezing rates at 2006 levels, or similar legislation that restricts the recovery of costs in a timely manner, becomes a substantial possibility, it may consider additional credit ratings downgrades with regard to one or more of the Ameren Companies.
On October 10, 2006, Fitch placed the credit ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative. The ratings of UE and Genco were affirmed and not affected by these rating actions. The negative rating watch resulted from the heightened political rhetoric surrounding future utility rates in Illinois and uncertainty related to recovery of CIPS’, CILCORP’s, CILCO’s and IP’s purchased power costs.
On October 5, 2006, S&P, in reaction to the intensified political discussion in Illinois regarding possible legislation freezing rates at 2006 levels, downgraded the credit ratings of the Ameren Companies. As a result of S&P’s downgrade of Ameren’s and UE’s short-term ratings to A-3, Ameren and UE are currently limited in their access to the commercial paper market. All of the S&P credit ratings for the Ameren Companies remain on credit watch with negative implications. According to S&P, it will continue to lower the Ameren Companies credit ratings if, in its opinion, the likelihood of Illinois legislation freezing electric rates at 2006 levels increases. If the legislation is passed, S&P will lower ratings on CIPS, CILCO, CILCORP and IP to “B” - a deep junk or speculative credit rating category.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital. It may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. For example, if at December 31, 2006, the Ameren Companies had a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could have been required to post collateral or other assurances for certain trade obligations amounting to $236 million, $43 million, $22 million, $21 million, $40 million, $40 million, or $72 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. Suppliers may request prepayment for products and services. 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.
OUTLOOK
Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2007 and beyond.
Revenues
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In 2006, electric rate freezes or adjustment moratoriums and power supply contracts expired in Ameren’s regulatory jurisdictions. At the end of 2006, electric rates for Ameren’s operating subsidiaries had been fixed or declining for periods ranging from 15 years to 25 years. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In September 2006, the power procurement auction was held and declared successful with respect to power for fixed-price customers, the vast majority of electric customers of CIPS, CILCO and IP. The auction clearing price was about $65 per megawatthour for the fixed-price residential and small commercial product and about $85 per megawatthour for large commercial and industrial customers. Marketing Company participated in the auction with power being acquired from Genco and AERG, subject to an auction rules limitation of providing no more than 35% of the Ameren Illinois Utilities’ expected annual load, and it was awarded sales in the auction. As a result of the high auction price for the large commercial and industrial customers, almost all of these customers chose a different supplier.
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In 2006, the Non-rate-regulated Generation segment generated 30 million megawatthours of power (Genco - 15 million, AERG - 7 million, EEI - 8 million). Power previously supplied by Genco to CIPS and by AERG to CILCO was subject to below-market-priced contracts that expired on December 31, 2006. All but 5 million megawatthours of Genco’s pre-2006 wholesale and retail electric power supply agreements also expired during 2006. About 1 million megawatthours of these
contracts expire by the end of 2007 and another 2 million expire by the end of 2008. Substantially all of these contracts involved below-market prices. These agreements had an average embedded selling price of $36 per megawatthour. In 2006, Genco also sold 2.1 million net megawatthours of power in the interchange market at an average market price of $38 per megawatthour. In 2006, AERG’s power was sold principally to CILCO, at an average price of $32 per megawatthour. In addition, AERG sold 1.5 million net megawatthours of power in the interchange market at an average price of $37 per megawatthour in 2006. The Non-rate-regulated Generation segment expects to generate 32 million megawatthours of power in 2007 (Genco - 17 million, AERG - 7 million, EEI - 8 million). Genco, AERG and EEI have contracts to sell all their power to Marketing Company. Marketing Company will resell this power and provide the net proceeds to Genco and AERG.
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The marketing strategy for Non-rate-regulated Generation is to optimize our generation output in a low risk manner to minimize earnings and cash flows volatility, while capitalizing on our low-cost generation fleet to provide for solid, sustainable returns. Through a mix of physical and financial sales contracts, and the Illinois 2006 power procurement auction, Non-rate-regulated Generation has sold approximately 90% of its expected 2007 generation output (29 million megawatthours) at an average price of $51 per megawatthour. Expected sales in 2007 include an estimated 7.6 million megawatthours of power sold through the Illinois power procurement auction at about $65 per megawatthour (2008 - 6.8 million, 2009 - 4.3 million). Including auction sales, approximately 55% of the expected generation output in 2008 is sold.
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CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). In November 2006, the ICC issued an order approving an annual revenue increase for electric delivery service of $97 million in the aggregate (CIPS - $8 million decrease, CILCO - $21 million increase and IP - $84 million increase) based on an allowed return on equity of 10%. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling approximately $50 million, that were disallowed. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity in 2007. Prior to January 2, 2007, most customers were taking service under a frozen bundled electric rate in 2006, which included the cost of power, so any delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates. The necessity and timing of new Illinois delivery service rate cases for the Ameren Illinois Utilities will be driven by several factors, including the results of the pending rehearing.
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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 Ameren Illinois Utilities’ customers based on the results of the Illinois power procurement auction held in early September 2006 and increases resulting from the delivery service rate cases. CIPS and IP average residential rates are expected to increase in 2007 by approximately 40% over 2006 rates, and CILCO average residential rates are expected to increase approximately 55% over 2006 rates. Due to the magnitude of these increases, certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. CIPS, CILCO and IP have received favorable rulings from the ICC and the circuit court of Cook County, Illinois on opposition claims filed by the Illinois attorney general, CUB and ELPC. These rulings are currently under court appeals.
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On October 2, 2006, Speaker of the Illinois House of Representatives Michael Madigan sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly to consider legislation to freeze electric rates at 2006 levels. The governor sent a letter indicating that once the votes to pass the legislation were in place, he would immediately call for a special session of the legislature. The governor’s letter further provided that if a consensus among members of the general assembly could not be reached in the near future, he would call a special session in that event as well. No special session was called. The governor’s letter stated that he continued to support legislation extending a rate freeze and would like to sign it into law as soon as possible. During the Illinois General Assembly’s session that ended in January 2007, the Illinois House of Representatives passed legislation to freeze 2006 electric rates through 2010, and the Illinois Senate passed legislation containing a rate increase phase-in plan. The Illinois Senate bill provided for a mandatory phase-in of the 2007 increase in residential rates over a three-year period. Neither piece of legislation was passed by the other chamber before the session ended in early January 2007. Any legislative measure will need to be approved by the Illinois House of Representatives and Illinois Senate, and signed by the governor before it can become law. A new Illinois General Assembly went into session in late January 2007. As a result, all previous bills expired. New bills have been introduced during the current legislative session, including legislation to rollback rates to 2006 levels similar to previously proposed legislation.
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CIPS, CILCO and IP believe that legislation freezing electric rates at 2006 levels, if enacted, would have a material adverse effect on the results of operations, financial position, and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP. They believe it could cause significant job losses and, without governmental intervention, significant disruptions in electric and gas service. Ameren’s Illinois utilities own no generation, so the companies must purchase power on the competitive market to meet their customers’ energy needs. If electric rates were frozen at 2006 levels, the major credit rating agencies have stated that the Ameren Illinois Utilities’ credit ratings would be downgraded to deep junk (or speculative) status. Such a downgrade of CILCO’s ratings would also result in a similar downgrade of CILCORP’s ratings.
•
With such credit ratings, CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements for products and services, such as natural gas, and would run out of cash and available credit and be unable to borrow. We believe this would cause the Ameren Illinois Utilities to become financially insolvent. Any decision or action that impairs the ability of CIPS, CILCO, and IP to fully recover costs from their electric customers in a timely manner would result in material adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts.
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In December 2006, the ICC approved a constructive electric rate increase phase-in plan proposed by the Ameren Illinois Utilities for residential customers, eligible schools, local governments and small commercial customers, to address the significant increases in customer rates for the Ameren Illinois Utilities beginning in 2007. This optional plan limits annual rate increases to 14% in 2007, 2008, and 2009, with amounts in excess of the cap and a 3.25% carrying cost allowed to be collected over a three-year period beginning in 2010. This below-market carrying cost charge will result in increased net borrowing and financing costs for the Ameren Illinois Utilities. On February 27, 2007, the Ameren Illinois Utilities announced that they intended to file an electric rate increase mitigation plan with the ICC. As part of the plan, which is subject to ICC approval, the Ameren Illinois Utilities would fund an approximate $20 million one-time reduction to active residential accounts that would appear on electric bills in March and April 2007. The rate mitigation plan is targeted to customers with high volume usage. As part of the filing, the carrying charge of 3.25% in the current ICC-approved phase-in plan would be eliminated. If approved by the ICC, the one-time credit for residential customers would result in a charge to Ameren’s earnings in 2007 of $20 million, or 6 cents per share. In addition, eliminating the below-market interest rate on deferred amounts under the phase-in plan would increase financing costs for the Ameren Illinois Utilities during the deferral period. The actual cost to Ameren will depend on the level of participation in the phase-in plan. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a further discussion of Illinois rate matters.
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The Illinois General Assembly and the ICC may consider changes to the Illinois power procurement process in the future. The next Illinois power procurement auction for the Ameren Illinois Utilities is scheduled to take place in January 2008.
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In July 2006, UE filed requests with the MoPSC for an increase in electric rates of $361 million and in natural gas delivery rates of $11 million. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million and a gas rate increase of $2 million to $3 million. Other stakeholders also made recommendations. A decision from the MoPSC is expected no later than June 2007. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a further discussion of Missouri rate matters.
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We expect continued economic growth in our service territory to benefit energy demand in 2007 and beyond, but higher energy prices could result in reduced demand from consumers, especially in Illinois.
•
UE, Genco and CILCO are seeking to raise the equivalent availability and capacity factors of their power plants through greater investments and a process improvement program and investment.
•
Very volatile power prices in the Midwest affect the amount of revenues Ameren, UE, Genco and CILCO (through AERG) can generate by marketing power into the wholesale and interchange markets and influence the cost of power we purchase in the interchange markets. These companies hedged approximately 86% of estimated available 2007 generation (2008 - 70%, 2009 - 60%).
Fuel and Purchased Power
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In 2006, 85% of Ameren’s electric generation (UE - 77%, Genco - 97%, CILCO - 99%) was supplied by its coal-fired power plants. About 93% of the coal used by these plants (UE - 97%, Genco - 87%, CILCO - 69%) was delivered by railroads from the Powder River Basin in Wyoming. In 2005, deliveries from the Powder River Basin were restricted due to derailments. As of December 31, 2006, coal inventories for UE, Genco and AERG were adequate, and consistent with historical levels. However, inventories and deliveries were still below desired levels because of railroad capacity limitations. Disruptions in coal deliveries could cause UE, Genco and CILCO 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.
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Ameren’s coal and related transportation costs are expected to increase 15% to 20% in 2007 and 5% to 10% in 2008. Ameren’s nuclear fuel costs are also expected to rise over the next few years. In 2007, nuclear fuel costs are expected to increase 13% to
18%. In addition, power generation from higher-cost gas-fired plants is expected to increase in the next few years. 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 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;
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fixed-rate debt;
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commercial paper; and
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auction-rate long-term debt.
We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.
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, 2006:
(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.
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, 2006, 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 purchase and sale activity with nonaffiliated companies. At December 31, 2006, UE’s, CIPS’, Genco’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange purchases and sales was less than $1 million, net of collateral (2005 - $39 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 $35 million at December 31, 2006 (2005 - $26 million).
Equity Price Risk
Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. 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 with benchmark returns and for the effect of expenses paid from plan assets.
In future years, the costs of such plans reflected in net income or OCI and cash contributions to the plans could increase materially, without pension asset portfolio investment returns equal to or in excess of our assumed return on plan assets of 8.5%.
UE also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2006, this fund was invested primarily in domestic equity securities (67%) and debt securities (32%) and totaled $285 million (2005 - $250 million). By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets. The fixed-rate, fixed-income securities are exposed to changes in interest rates. UE actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the assets of the trust to various investment options. UE’s exposure to equity price market risk is in large part mitigated, because UE is currently allowed to recover decommissioning costs, which would include unfavorable investment results, through electric rates.
Commodity Price Risk
We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through structured risk management programs and policies, which include structured forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.
Similar techniques are used to manage risks associated with fuel exposures for generation. Most UE, Genco and AERG fuel supply contracts are physical forward contracts. UE, Genco and AERG do not have a provision similar to the PGA clause for electric operations, so UE, Genco and AERG have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. We generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions. As part of its pending electric
rate case filed in July 2006, UE has requested approval by the MoPSC for a fuel and purchased power cost recovery mechanism to its tariffs.
Transportation costs for coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. The natural gas transportation expenses for the distribution utility companies and the gas-fired generation units are controlled by FERC via published tariffs with rights to extend the contracts from year to year. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariffs for our requirements.
The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the five-year period 2007 through 2011:
(a)
Calculations are based on an effective tax rate of 38%.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
In the event of a significant change in coal prices, UE, Genco and CILCO would probably take actions to further mitigate their 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 or fuel sources.
With regard to exposure for commodity price risk for nuclear fuel, UE has fixed-priced and base-price-with- escalation agreements, or it uses inventories that provide some price hedge. Fuel assemblies for the 2007 spring refueling are already at the Callaway nuclear plant. UE has price hedges for 61% of the 2008 to 2011 nuclear fuel requirements.
The nuclear fuel markets have undergone significant change; from a buyer’s market to a seller’s market with increased potential for supply disruptions. UE has increased its desired inventories of nuclear fuel (with inherent price hedge) and has increased its forward contract coverage. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some market-price-related component. Therefore, nuclear fuel price increases are expected and price hedging becomes less available. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices which cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have no sophisticated financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if available.
With regard to the electric generating operations for UE, Genco and AERG that are exposed to changes in market prices for natural gas used to run the CTs, the natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas while minimizing costs. We optimize transportation and storage options and price risk by structuring supply agreements to maintain access to multiple gas pools and supply basins.
Through the market allocation process, UE, CIPS, Genco, CILCO and IP have been granted FTRs associated with the advent of the MISO Day Two Energy Market. Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois market. The FTRs are intended to mitigate expected electric transmission congestion charges related to our physical electricity business. Depending on the congestion and prices at various points on the electric transmission 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 will need, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.
With regard to UE’s natural gas distribution business and CIPS’, CILCO’s and IP’s power and natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow UE, CIPS, CILCO and IP to pass on to retail customers prudently incurred costs. Our strategy is designed to reduce the effect of market fluctuations for our regulated customers. We cannot eliminate the effects of price volatility. However, procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.
With regard to our exposure for commodity price risk for construction and maintenance activities, Ameren is exposed to changes in market prices for metal commodities and labor availability.
The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the five-year period 2007 through 2011:
(a)
Represents the percentage of natural gas price hedged for the peak winter season of November through March. The year 2007 represents the period January 2007 through March 2007. The year 2008 represents November 2007 through March 2008. This continues each successive year through March 2011.
(b)
Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than 1 megawatt of demand as part of the Illinois power procurement auction held in September 2006. Excluded from the percent hedged amount is purchased power for fixed-price large commercial and industrial customers with 1 megawatt of demand or higher who had 30 to 50 days after the date the auction was declared successful (September 15, 2006) to elect not to receive power from CIPS, CILCO or IP. The majority of these customers chose a third-party supplier. However, regardless of whether customers choose a third-party supplier, the purchased power needed to serve the remaining load is 100% price-hedged through May 31, 2008, due to the Illinois auction. Also excluded from the percent hedged amount is power purchased to serve large-service real-time pricing customers, as the auction results have not been finalized for this customer class.
See Note 3 - Rate and Regulatory Matters and Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information. See Supply for Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear, natural gas, hydroelectric and oil. Also see Note 14 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information.
Fair Value of Contracts
Most of our commodity contracts qualify for treatment as normal purchases and normal sales. 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 may cause any of these conditions:
•
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sales 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 under contracted commitment; 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. See Note 8 - Derivative Financial Instruments to our financial statements under Part II, Item 8, of this report for further information.
The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2006. The sources used to determine the fair value of these contracts were active quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than three years.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
Principally fixed price vs. floating over-the-counter power swaps, power forwards and fixed price vs. floating over-the-counter natural gas swaps.
(b)
Principally coal and SO2 option values based on a Black-Sholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates.
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:
We have completed integrated audits of Ameren Corporation’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 of financial statements 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 asset retirement costs as of December 31, 2005, and the manner in which it accounts for defined benefit pension and postretirement obligations as of December 31, 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
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, 2007
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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 asset retirement costs as of December 31, 2005, 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, 2007
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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 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 asset retirement costs as of December 31, 2005, 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, 2007
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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 asset retirement costs as of December 31, 2005, 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, 2007
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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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) 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 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 asset retirement costs as of December 31, 2005, 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, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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) 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 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 asset retirement costs as of December 31, 2005, 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, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
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, 2006 and 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2006 and for the periods October 1, 2004 to December 31, 2004 (successor) and January 1, 2004 to September 30, 2004 (predecessor) 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 asset retirement costs as of December 31, 2005, 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, 2007
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 consolidated 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 consolidated 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 consolidated 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 consolidated 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 was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed, effective February 8, 2006. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries, which are separate, independent legal entities with separate businesses, assets and liabilities, 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 Greater St. Louis. UE supplies electric service to 1.2 million customers and natural gas service to 125,000 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, in conjunction with the Illinois Customer Choice Law. Genco commenced operations on May 1, 2000, when CIPS transferred its five coal-fired power plants representing in the aggregate about 2,860 megawatts of capacity and related liabilities to Genco at historical net book value. The transfer was made in exchange for a subordinated promissory note from Genco in the amount of $552 million and shares of Genco’s common stock that were subsequently distributed to Ameren as a dividend in kind. Ameren then contributed the shares to Development Company as an additional capital contribution. Genco also owns 17 CTs, which gave it a total installed generating capacity of about 4,222 megawatts as of December 31, 2006. Genco is a subsidiary of Development Company, a subsidiary of Resources Company, which in turn is a subsidiary of Ameren.
•
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 an estimated population of 1 million. CILCO supplies electric service to 215,000 customers and natural gas service to 220,000 customers. In October 2003, CILCO transferred its coal-fired plants and a CT facility, representing in the aggregate about 1,100 megawatts of electric generating capacity, to a wholly owned subsidiary known as AERG, as a contribution in respect of all the outstanding stock of AERG and AERG’s assumption of certain liabilities. The net book value of the transferred assets was $378 million. In December 2006, CILCO transferred to AERG its cogeneration facility and oil-fired diesel generator, which represent in the aggregate about 23 megawatts of electric generating capacity. The net book value of the transferred assets was $20 million. No gain or loss was recognized on the transfers, as the transactions were accounted for as transfers between entities under common control. The transfers were made in conjunction with the Illinois Customer Choice Law. 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. Ameren acquired IP on September 30, 2004, from Dynegy, which had acquired it with Illinova in early 2000. 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 635,000 customers and natural gas service to 430,000 customers, including most of the
Illinois portion of the Greater St. Louis area. See Note 2 - Acquisitions for further information.
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 through UE and Development Company, which each own 40% of EEI. Ameren consolidates EEI for financial reporting purposes, while UE reports EEI under the equity method. 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. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income, Cash Flows, and Stockholders’ Equity for the periods prior to September 30, 2004, do not reflect IP’s results of operations. See Note 2 - Acquisitions for further information about the accounting for the IP acquisition. 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) 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. Certain reclassifications have been made to make prior-year financial statements conform to 2006 reporting, including the reclassification of emission allowance purchases and sales from Operating Activities to Investing Activities on the Statements of Cash Flows for Ameren, UE, Genco, CILCORP and CILCO. In the third quarter of 2006, Ameren, UE, CILCORP and CILCO changed their reportable segments. See further discussion in Note 17 - Segment Information.
As part of the acquisition of IP on September 30, 2004, Ameren “pushed down” the effects of purchase accounting to the financial statements of IP. Accordingly, IP’s postacquisition financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for preacquisition (predecessor) and postacquisition (successor) periods, separated by a bold black line. As a result of the acquisition of IP, certain reclassifications have been made to make IP prior-year financial statements conform to our current presentation.
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 3 - 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, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(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 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 Accounting Changes and Other Matters relating to SFAS No. 143 and FIN 47 below and Note 4 - 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 2006, 2005 and 2004 generally ranged from 3% to 4% of the average depreciable cost. See Accounting Changes and Other Matters relating to SFAS No. 143 and FIN 47 below for further information.
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 for 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 2006, 2005 and 2004:
(a)
Excludes rates for IP before the acquisition date of September 30, 2004.
Goodwill and Intangible Assets
Goodwill. As of December 31, 2006, Ameren, CILCORP and IP had goodwill of $830 million, $542 million and $213 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.
As a result of the ICC electric delivery service rate case orders effective January 2, 2007, discussed in Note 3 - Rate and Regulatory Matters, Ameren, CILCORP and IP concluded in the fourth quarter of 2006 that amounts previously recorded as goodwill in connection with Ameren’s acquisitions of IP and CILCORP related to pension and other postretirement benefit purchase accounting adjustments
were now probable of recovery following the guidance of SFAS No. 71 as amended by SFAS No. 141, “Business Combinations.” Accordingly, at December 31, 2006, $54 million for CILCORP and $186 million for IP were reclassified from goodwill to regulatory assets and deferred income taxes of $21 million for CILCORP and $73 million for IP were recorded, reducing goodwill by $146 million, as shown in the table below. These regulatory assets will be amortized to earnings as the amounts are collected from IP and CILCO ratepayers. This reclassification had no impact to CILCO’s balance sheet as Ameren’s purchase accounting for the CILCORP acquisition was not “pushed down” to the CILCO financial statements.
In December 2006, Ameren adopted SFAS No. 158. In accordance with that accounting standard, 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. For Ameren, the unfunded obligation at December 31, 2006, was approximately $1.1 billion. 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 approximately $406 million, $234 million, $95 million, $36 million, ($51) million, $55 million and ($8) million, respectively. UE, CIPS and CILCO recorded regulatory assets of approximately $270 million, $108 million and $63 million, respectively, based on the expected recovery of these costs from ratepayers. The adoption of SFAS No. 158 resulted in an immaterial impact on accumulated other comprehensive income at Ameren. CILCORP and IP recognized gains in Accumulated Other Comprehensive Income of approximately $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 approximately $24 million and $2 million, respectively, net of taxes.
The changes in the carrying amount of goodwill for the period from January 1, 2006 to December 31, 2006, were as follows:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
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.
(d)
A $4 million impairment was recorded in first quarter of 2006 for customer contracts, which had been amortized over an average life of 10 years.
At December 31, 2005, intangible assets also included intangible pension assets of $77 million at Ameren, $42 million at UE, $7 million at Genco, $3 million at CILCORP and $4 million at CILCO. With the adoption of SFAS No. 158, there are no intangible pension assets at December 31, 2006. See Note 10 - Retirement Benefits for further details related to these intangible pension assets.
The following table presents the net carrying value of emission allowances consumed (sold) for Ameren, UE, Genco and CILCO during the years ended December 31, 2006, 2005 and 2004.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
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. The determination of whether impairment has occurred is made by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If impairment has occurred, we recognize the amount of the impairment by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value.
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 impairments would be recorded as regulatory assets 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 16 - 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 based on internal and third-party estimates, which 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.
Interchange Revenues
The following table presents the interchange revenues included in Operating Revenues - Electric for the years ended December 31, 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes interchange revenues at Marketing Company and EEI totaling $357 million for the year ended December 31, 2006 (2005 - $32 million, 2004 - $53 million).
(b)
The 2006, 2005 and 2004 amounts were less than $1 million.
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.
Purchased Power
The following table presents the purchased power expenses included in Operating Expenses - Fuel and
Purchased Power for the years ended December 31, 2006, 2005 and 2004.
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Beginning in 2007 in CIPS’, CILCO’s and IP’s Illinois retail electric utility jurisdictions, changes in purchased power costs will be reflected in billings to electric customers through a charge for market-based power costs resulting from a competitive procurement process. See Note 3 - Rate and Regulatory Matters for a discussion of the power procurement cost recovery mechanism.
See Note 13 - Related Party Transactions for further information on affiliate purchased power transactions.
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 charged to expense based on net kilowatthours generated and sold.
Stock-based Compensation
Effective January 1, 2006, Ameren adopted SFAS No. 123 (revised 2004) “Share-based Payment” (SFAS 123R), which revises SFAS 123 and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS 123R requires companies to measure the cost of employee services received in exchange for an award of equity instruments by the grant-date fair value of the award. Ameren adopted SFAS 123R utilizing the modified prospective application. Under that approach, SFAS 123R applies to all awards granted or modified after the effective date. Ameren’s unearned compensation related to nonvested awards granted prior to its adoption of FAS 123R was eliminated against Ameren’s Other Paid-in Capital effective January 1, 2006, based on the guidance provided by SFAS 123R.
Had compensation cost for all stock options and restricted stock awards granted prior to 2003, when Ameren adopted SFAS 123, been determined on a fair value basis consistent with SFAS No. 123, Ameren’s net income would have been reduced by $1 million for the year ended December 31, 2004; and, its pro forma basic and diluted earnings per share would have equaled actual earnings per share for the year ended December 31, 2004. Compensation cost for Ameren’s options granted prior to 2003 would have been fully recognized in 2004. Had compensation cost for all stock option awards granted prior to 2003 been determined on a fair value basis for Dynegy equity compensation in which IP employees participated, predecessor IP’s net income would have been reduced by $3 million for the nine months ended September 30, 2004. On October 1, 2004, as a result of Ameren’s acquisition of IP, all unvested stock options granted to IP employees became null and void.
See Note 11 - Stock-based Compensation for further information.
Excise Taxes
Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. 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 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004.
(b)
The 2004 amount includes January through September 2004 predecessor information, which was $30 million.
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 12 - Income Taxes.
Minority Interest and Preferred Dividends of Subsidiaries
For the years ended December 31, 2006, 2005, and 2004, Ameren had minority interest expense related to EEI of $27 million, $3 million and $4 million, respectively, and preferred dividends of subsidiaries of $11 million, $13 million, and $11 million, respectively.
Earnings Per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2006, 2005, and 2004 due to an immaterial number of stock options, restricted stock shares, and performance share units outstanding. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 38,438 shares in 2006, 65,917 shares in 2005, and 196,709 shares in 2004.
Accounting Changes and Other Matters
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48)
FIN 48 establishes that the financial statement effects of a tax position taken or expected to be taken in a tax return are to be recognized in the financial statements when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. In addition, FIN 48 requires expanded disclosure with respect to the uncertainty in income taxes and is effective as of the beginning of our 2007 fiscal year. We are still in the process of determining the impact the adoption of FIN 48 will have on our results of operations, financial position, and liquidity; however, at this time, we do not expect the impact of the adoption to be material.
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 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. We are still determining the impact the adoption of SFAS No. 157 will have on our results of operations, financial position, and liquidity, if any; however, at this time, we do not expect the impact to be material.
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)
In September 2006, the FASB issued SFAS No. 158, which 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. Employers must 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. SFAS No. 158 also requires additional disclosures in the notes to the financial statements. The recognition and disclosure provisions of SFAS No. 158 were effective for us as of December 31, 2006. To the extent we determined that it is probable that the liabilities associated with the adoption of SFAS No. 158 will be recoverable through rates charged by Ameren’s rate-regulated businesses (UE, CIPS, CILCO and IP), a regulatory asset was recorded. See Note 10 - Retirement Benefits for additional information on the impact of the adoption of SFAS No. 158 at December 31, 2006.
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 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, and 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.
SFAS No. 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations
SFAS No. 143 requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to 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, UE recorded AROs related to its Callaway nuclear plant decommissioning costs and retirement costs for a river structure. Additionally, Genco recorded an ARO for the retirement costs for a power plant ash pond. CILCORP and CILCO recorded AROs related to AERG power plant ash ponds.
FIN 47 clarified that an entity must recognize a liability for the fair value of a conditional ARO when it is incurred if the liability’s fair value can be reasonably estimated. FIN 47 also specified the information an entity would need to reasonably estimate the fair value of an ARO. In 2005, Ameren, Genco, CILCORP, and CILCO recognized net aftertax losses of $22 million, $16 million, $2 million, and $2 million, respectively, for the cumulative effect of a change in accounting principle for FIN 47. Upon adoption of FIN 47, Ameren, UE, Genco, CILCORP, and CILCO recorded AROs for retirement costs associated with 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 3 - Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2006 and 2005:
(a)
Ameren amounts do not equal total due to AROs at EEI.
(b)
The nuclear decommissioning trust fund assets of $285 million and $250 million as of December 31, 2006 and 2005, respectively, are restricted for decommissioning of the Callaway nuclear plant.
(c)
Substantially all accretion expense was recorded as an increase to regulatory assets.
(d)
Revision of UE’s Callaway nuclear plant ARO estimate.
(e)
Less than $1 million.
If FIN 47 had been in effect as of December 31, 2004, the pro forma asset retirement obligations would have been $518 million, $462 million, $2 million, $32 million, $12 million, $12 million and $2 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. If FIN 47 had been applied for the years ended December 31, 2005 and 2004, Ameren’s, Genco’s, CILCORP’s and CILCO’s net income would have been lower by $2 million, $1 million, less than $1 million, and less than $1 million, respectively, in each year. The FIN 47 application would have reduced Ameren’s basic and diluted earnings per share $0.01 per share in each of these two years. The adoption of FIN 47 did not have any income statement impact on UE, CIPS, or IP because a regulatory asset was recorded as an offset to the AROs and the related net capitalized asset retirement 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, 2006:
•
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 leveraged lease and affordable housing partnership arrangements that are variable interests. 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, 2006, Ameren had a net investment in leveraged leases of $13 million. At December 31, 2006, Ameren and UE had investments in affordable housing partnerships of $21 million and $17 million, respectively.
•
IP SPT. Ameren acquired a variable interest in IP SPT with the acquisition of IP on September 30, 2004. 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 collection 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 - ACQUISITIONS
IP and EEI
On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of IP and an additional 20% ownership interest in EEI from subsidiaries of Dynegy. Ameren acquired IP to complement its existing Illinois gas and electric operations. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP.
The total transaction value was $2.3 billion, including the assumption of $1.8 billion of IP debt and preferred stock. Cash consideration was $429 million, net of $51 million cash acquired, and included transaction costs. In addition, this transaction included a fixed-price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. This agreement met about 70% of IP’s electric customer requirements during 2005 and 2006. The remaining 30% of IP’s power was supplied by other companies through contracts and open-market purchases. The fair value of IP’s power supply agreements, including the fixed-price capacity power supply agreement with DYPM recorded at the acquisition date, resulted in a net liability of $109 million, which was fully amortized by December 31, 2006. In addition, IP recorded a fair value adjustment, resulting in a net asset of $20 million, which was fully amortized by December 31, 2005, for IP’s power supply agreement with EEI that expired at the end of 2005. Ameren funded this acquisition with the issuance of new Ameren common stock. Ameren issued an aggregate of 30 million common shares in February 2004 and July 2004, which generated net proceeds of $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price, to reduce IP debt assumed in this transaction, and to pay related premiums.
Ameren acquired IP for $355 million, including transaction costs, plus the assumption of $1.8 billion of IP debt and preferred stock. The excess of the purchase price for IP’s common stock and preferred stock over net assets acquired was allocated to goodwill in the amount of $326 million. The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI now held by Development Company was $125 million. The excess of purchase price over fair value was allocated to goodwill in the amount of $65 million in addition to specifically identifiable intangible assets of $48 million comprising emission allowances, which are amortized as they are used.
CT Facilities Purchases
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. This lease was entered into pursuant to Missouri economic development statutes to provide a development incentive property tax savings to the lessee for locating the CT facility in Audrain County. The lease will expire on December 1, 2023. 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 currently outstanding) 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. Audrain County will retain title to the CT facility during the term of the bond and the lease, and therefore the facility will be exempt from ad valorem taxation. The title to the facility will be transferred to UE at the expiration of the lease. UE also has all operation and maintenance responsibilities for the CT facility.
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.
These CT facility purchases were designed to help meet UE’s increased generating capacity needs as well as to
provide UE with additional flexibility in determining the timing of future baseload generating capacity additions. These purchases were accounted for as asset purchases.
NOTE 3 - RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings. We are unable to predict the ultimate outcome of these regulatory proceedings, the timing of the final decisions of the various agencies, 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 increase in base rates for electric service. UE’s filing included a proposed average increase in electric rates of 17.7%, or $361 million. UE is proposing to limit the increase on residential rates to 10%, allocating requested revenue amounts above that level to other customer classes. This rate increase filing was based on a test year ended June 30, 2006, and included known and measurable items through January 1, 2007. Since UE’s last electric rate case in 2002, UE has invested $2.5 billion in its electric operations. Those investments included more than $700 million for 2,600 megawatts of new generation to meet growing customer power demands. UE’s July 2006 electric rate request includes, among other items, the following features:
•
a requested return on equity of 12%, and a rate base of $5.8 billion with a capital structure including about 52% common equity;
•
a request for a fuel and purchased power cost recovery mechanism under the provisions of a Missouri state law enacted in 2005 (see MoPSC Rulemaking Proceeding below in this note for additional information);
•
a proposed alternative mechanism for the MoPSC’s consideration to share off-system sales margins with ratepayers;
•
an increase in depreciation rates;
•
renewable energy proposals, including the addition of 100 megawatts of renewable energy by 2010; and
•
commitments to offer low-income energy assistance and energy conservation programs.
Costs incurred related to the December 2005 failure of UE’s Taum Sauk pumped-storage hydroelectric plant for the cleanup of a nearby state park, reimbursement of state costs, and resolution of individuals’ claims were excluded from the revenue increase request.
In December 2006, the MoPSC staff and other stakeholders filed direct testimony in response to UE’s electric rate increase filing. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million based on a return on equity of 9.0% to 9.75%. The Missouri attorney general recommended a $53 million rate reduction based on a 9% return on equity. The Missouri Office of Public Counsel recommended a return on equity of 9.65%. The major factors contributing to the difference between the UE rate increase request and the MoPSC staff rate reduction recommendation include return on equity, depreciation levels, the treatment of a cost-base contract from EEI, that expired in December 2005, margins for interchange sales, and the treatment of emission allowance sales, among other matters. In addition, the MoPSC staff and intervenors have recommended that UE not be granted the right to use a fuel and purchased power cost recovery mechanism. A decision from the MoPSC is expected no later than June 2007.
Gas
In July 2006, UE filed a request with the MoPSC for an $11 million increase in natural gas delivery rates, based on an 11.5% return on equity, and a rate base of $218 million with a capital structure including about 52% common equity. In December 2006, the MoPSC staff and other stakeholders filed testimony in response to UE’s gas rate increase filing. The MoPSC staff recommended in their testimony a gas rate increase of $2 million to $3 million based on a return on equity of 9.0% to 9.75%, and a rate base of $201 million with a capital structure including 52% common equity. A decision from the MoPSC is expected no later than June 2007.
MoPSC Rulemaking Proceeding
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. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006 and became effective during the fourth quarter of 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. UE requested a fuel and purchased power cost recovery mechanism in its electric rate case filed with the MoPSC in July 2006. The MoPSC staff and intervenors have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost recovery mechanism as part of this electric rate case. However, no environmental adjustment clause has been submitted in the rate case since final environmental cost recovery rules have not been adopted. UE’s requests are subject to approval by the MoPSC.
Illinois
Electric
Under the Illinois Customer Choice Law, as amended with the consent of the Illinois utilities, CIPS’, CILCO’s and IP’s rates were frozen through January 1, 2007. In order to meet their customers’ power requirements, CIPS entered into a power supply agreement with Marketing Company and CILCO entered into an agreement with AERG for all of their power requirements through December 31, 2006. As part of Ameren’s acquisition of IP, IP entered into a power supply
agreement with DYPM to supply about 70% of its electric customer requirements through the end of 2006. See Note 13 - Related Party Transactions for a discussion of the affiliate power supply agreements. The following is a discussion of the current status of significant matters affecting our Illinois electric operations.
Illinois Power Procurement
During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and power procurement after the Illinois electric rate freeze expired on January 1, 2007, and supply contracts expired on December 31, 2006.
In February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for power procurement through an ICC-monitored auction, including, among other things, a rate mechanism to pass power supply costs directly through to customers. The form of power supply would meet the full requirements of each utility, and the risk of fluctuations in power supply requirements would be borne by the supplier. In January 2006, the ICC issued an order that unanimously approved the Ameren Illinois Utilities’ proposed power procurement auction and the related tariffs for use commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to customers. The order included the following key findings and provisions:
•
The auction proposal is reasonably designed to enable CIPS, CILCO and IP to procure power supply in a competitive and least-cost manner.
•
There is a limitation of 35% on the amount of power any single supplier can provide the Ameren Illinois Utilities’ expected annual load. Ameren-affiliated companies are considered one supplier for purposes of this limitation.
•
The proposal requires a portfolio of one-, two-, and three-year supply contracts.
•
Full cost recovery through a rate mechanism is permitted.
•
Annual, postauction prudence reviews by the ICC are required.
In accordance with the January 2006 ICC order, the power procurement auction was held at the beginning of September 2006. On September 14, 2006, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. On September 15, 2006, the independent auction manager, NERA Economic Consulting, declared a successful result in the auction for fixed-price customers. The auction clearing price was about $65 per megawatthour for the fixed-price residential and small commercial product and about $85 per megawatthour for large commercial and industrial customers. Marketing Company was awarded sales in the auction. See Note 13 - Related Party Transactions for a discussion of these affiliate power supply agreements. As a result of the high auction price for the large commercial and industrial customers, almost all of these customers chose a different supplier.
Certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. Opponents of the power procurement auction and related tariffs claim that the ICC did not have authority to approve market-based rates for electric service that have not been declared “competitive” pursuant to Section 16-113 of the Illinois Customer Choice Law. They further claim that the energy component of CIPS’, CILCO’s and IP’s retail rates for electricity should not be based on the costs to procure energy and capacity in the wholesale market. CIPS, CILCO and IP have received favorable rulings from the ICC and the circuit court of Cook County, Illinois, on opposition claims filed by the Illinois attorney general, CUB and ELPC.
Various parties, including CIPS, CILCO, IP, the Illinois attorney general, CUB, and ELPC, have appealed to Illinois district appellate courts the ICC’s denial of rehearing requests with respect to its January 2006 order. Although CIPS, CILCO and IP are generally supportive of the ICC order, they filed a request for rehearing with regard to the provision of the January 2006 order requiring an annual postauction prudence review to be performed by the ICC. In February 2006, they appealed the ICC’s denial of the request to the appellate court for the Fourth District in Illinois. CIPS, CILCO and IP asserted in their request for rehearing that there is no basis for such a prudence review. In their requests for rehearing of the January 2006 ICC order and their appeals of the ICC’s denial of their requests filed with the First District Illinois appellate court in March and April 2006, the Illinois attorney general, CUB and ELPC asserted that the Ameren Illinois Utilities power procurement auction should be dismissed on the basis of arguments generally similar to those that they previously raised. In June 2006, the Illinois attorney general filed a petition with the Supreme Court of Illinois seeking a direct and expedited review of appeals filed with Illinois district courts by various parties of the ICC’s January 2006 order approving the Illinois power procurement auction and a stay on implementation of the order. In this petition, the Illinois attorney general raised similar arguments to those discussed above. In August 2006, the Supreme Court of Illinois denied the Illinois attorney general’s petition and ordered that the appeals be consolidated in the appellate court for the Second District in Illinois. The Second District appellate court granted a motion of the Illinois attorney general to dismiss CIPS’, CILCO’s and IP’s appeal regarding the need for an annual postauction prudence review claiming that it was filed prematurely. CIPS, CILCO and IP appealed that decision to the Illinois Supreme Court, where it is now pending. In addition, on December 21, 2006, the Illinois attorney general filed a motion to stay the effectiveness of the retail rates approved by the ICC in its January 2006 order. The motion was denied by the Second District appellate court on December 29, 2006, and upon appeal, denied by the Illinois Supreme Court in January 2007. The Illinois attorney general’s, CUB’s and ELPC’s
appeals at the Second District appellate court are still pending. We cannot predict the outcome of these proceedings.
Delivery Service Rate Cases
CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). In October 2006, the administrative law judges issued a proposed order, which included a recommended revenue increase for electric delivery service of $147 million in the aggregate (CIPS - $8 million, CILCO - $29 million and IP - $110 million). In November 2006, the ICC issued an order approving an annual revenue increase for electric delivery service of $97 million in the aggregate (CIPS - $8 million decrease, CILCO - $21 million increase and IP - $84 million increase). The ICC’s order was based on a return on equity of 10.08%, 10.08% and 10.12% for CIPS, CILCO and IP, respectively. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling $50 million, that were disallowed. The ICC’s decision on the recovery of these expenses is due in May 2007. The ICC denied requests for rehearings filed by other parties to this case. Prior to January 2, 2007, most customers were taking service under a frozen bundled electric rate, which included the cost of power, so these delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates.
Potential Electric Rate Freeze and Recovery of Post-2006 Power Supply Costs
In February 2006, legislation was introduced in the Illinois House of Representatives that would have extended the electric rate freeze in Illinois through 2010. On October 2, 2006, Speaker of the Illinois House of Representatives, Michael Madigan, sent a letter to Illinois Governor Rod Blagojevich asking the governor to call a special session of the Illinois General Assembly to consider this rate freeze legislation. In response, the Illinois governor sent a letter indicating that once the votes to pass the legislation were in place, he would immediately call for a special session of the legislature. The governor’s letter further indicated that if a consensus among members of the general assembly was not reached in the near future, he would call a special session in that event as well. No special session was called. The governor’s letter stated that he continued to support legislation extending the rate freeze and would like to sign it into law as soon as possible. Copies of the speaker’s and governor’s letters appear as Exhibits 99.1 and 99.2, respectively, to the Current Report on Form 8-K dated October 4, 2006. During the Illinois General Assembly’s session that ended in January 2007, the Illinois House of Representatives passed legislation to freeze 2006 rates through 2010, and the Illinois Senate passed legislation containing an electric rate increase phase-in plan. The Illinois Senate bill provided for a mandatory phase-in of the 2007 increase in residential electric rates over a three-year period. Neither piece of legislation was passed by the other chamber before the end of the session in early January 2007.
Any legislative measure will need to be approved by the Illinois House of Representatives and the Illinois Senate, and signed by the governor before it can become law. New rates for CIPS, CILCO and IP reflecting the power costs resulting from the ICC-approved September 2006 auction and the delivery service rates authorized by the November 2006 ICC order became effective January 2, 2007. A new Illinois General Assembly went into session in late January 2007. As a result, all previous bills expired. New bills have been introduced during the current legislative session, including legislation to rollback rates to 2006 levels similar to previously proposed legislation.
CIPS, CILCORP, CILCO and IP believe that legislation freezing electric rates at 2006 levels would have a material adverse effect on their results of operations, financial position, and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP. They believe it could cause significant job losses and, without governmental intervention, significant disruptions in electric and gas service. Ameren’s Illinois utilities own no generation facilities, so the companies must purchase power in the competitive market to meet their customers’ energy needs. If electric rates were frozen at 2006 levels, the major credit rating agencies have stated that the Ameren Illinois Utilities’ credit ratings would be downgraded to deep junk (or speculative) status . Such a downgrade of CILCO’s ratings would also result in a similar downgrade of CILCORP’s ratings. We believe CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment demands for products and services, such as natural gas, and would run out of cash and available credit and be unable to borrow. We believe this would cause the Ameren Illinois Utilities and CILCORP to become financially insolvent. In reaction to intensified political discussion in Illinois regarding electric rate freeze extension legislation, in October 2006 S&P downgraded the short- and long-term credit ratings of the Ameren Companies and kept the Ameren Companies on credit watch with negative implications. Moody’s placed the long-term debt credit ratings of the Ameren Companies under review for possible downgrade. Fitch placed the ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.
Electric Rate Increase Phase-in Plan
In December 2006, the ICC approved the Ameren Illinois Utilities’ Customer Elect Plan (Phase-in Plan) and related riders, which went into effect on January 2, 2007. The Phase-in Plan allows residential customers, eligible schools, local governments and small commercial customers to choose on an individual basis either to pay the full amount of higher electricity costs in 2007 or to phase in increases over a period of years. Under this plan, rate increases are phased in at an annual maximum increase of 14% over the prior year’s bundled rate, over three years (2007-2009) or until the full amount of the rate increase is
reached, whichever is earlier. At the end of the phase-in period, customers have three years (2010-2012) to repay the deferred costs at a carrying charge interest rate of 3.25%. Participation in the plan is voluntary and approximately 90% of the Ameren Illinois Utilities’ customers are eligible. As part of this plan, CIPS, CILCO and IP made additional contributions of $4 million, $3 million, and $8 million, respectively, in December 2006, to their Dollar More and Warm Neighbors programs, which provide bill paying assistance, energy conservation materials, and rebates for energy-efficient equipment. Customers have until August 21, 2007, to enroll in the plan. Those who enroll by April 10, 2007, will have deferred credits that are retroactive to January 2, 2007. On February 27, 2007, the Ameren Illinois Utilities announced that they intended to file an electric rate increase mitigation plan, with the ICC. As part of the plan which is subject to ICC approval, the Ameren Illinois Utilities would fund an approximate $20 million one-time reduction to active residential accounts that would appear on electric bills in March and April 2007. The rate mitigation plan is targeted to customers with high volume usage. As part of the filing the carrying charge of 3.25% in the current ICC-approved phase-in plan would be eliminated.
Summary
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 procurement costs. Approximately 90% of the Ameren Illinois Utilities’ customers currently have the option to participate in the Phase-in Plan. We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, nor can we predict the actions the Illinois General Assembly and governor may take that might affect electric rates or the power procurement process for CIPS, CILCO and IP. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk (or speculative) status, a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, significant risk of disruption in electric and gas service, significant job losses, and financial insolvency. In addition, Ameren, CILCORP and IP could be required to record a one-time charge for impairment of goodwill that was recorded when Ameren acquired these companies. As of December 31, 2006, Ameren, CILCORP and IP had $830 million, $542 million and $213 million, respectively, of goodwill recorded on their balance sheets. Furthermore, if the Ameren Illinois Utilities are unable to recover their costs from customers, the utilities could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which allows CIPS, CILCORP, CILCO and IP to defer certain costs pursuant to actions of rate regulators. This would result in the elimination of all regulatory assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary charge on their and Ameren’s statements of income that could be material. As of December 31, 2006, CIPS, CILCORP, CILCO and IP had $146 million, $75 million, $75 million and $401 million, respectively, recorded as regulatory assets on their balance sheets.
Ameren, CIPS, CILCORP, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois Utilities will prevail over the stated opposition by certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois Utilities are considering will be successful.
Federal
Regional Transmission Organization
In early 2004, UE received authorization from the MoPSC and FERC to participate in the MISO for a five-year period, with further participation subject to approvals by the MoPSC. Consistent with the orders issued by the MoPSC and FERC, the MoPSC continues to set the transmission component of UE’s rates to serve its bundled retail load.
On May 1, 2004, functional control, but not ownership, of UE’s and CIPS’ transmission systems was transferred to the MISO. On September 30, 2004, prior to the completion of Ameren’s acquisition of IP as required by FERC’s order approving the acquisition, IP transferred functional control, but not ownership, of its transmission system to the MISO. These transfers had no accounting impact on UE, CIPS and IP because they continue to own their transmission assets.
In 2004, as part of the transfer of functional control of UE’s and CIPS’ transmission system to the MISO, Ameren received $26 million, which represented the refund of the $13 million exit fee paid by UE and the $5 million exit fee paid by CIPS, both of which were expensed when they left the MISO in 2001, plus $1 million interest on the exit fees and the reimbursement of $7 million that was invested in the proposed Alliance RTO. These refunds resulted in aftertax gains of $11 million, $8 million, and $3 million for Ameren, UE, and CIPS respectively, which were recorded in other operations and maintenance expenses during the quarter ended June 30, 2004. As part of the transfer of functional control of IP’s transmission system to the MISO at the end of September 2004, predecessor IP also received a refund of its MISO exit fee, plus interest on the exit fee, and RTO development costs resulting in aftertax gains of $9 million during the quarter ended September 30, 2004.
Before Ameren’s acquisition of CILCO in 2003, CILCO was already a member of the MISO, and it had transferred functional control of its transmission system to the MISO.
Genco does not own transmission assets, but pays the MISO to use the transmission system to transmit power from the Genco generating plants.
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 that was 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 the 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). FERC has not acted 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. The more recently filed settlements are pending. 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.
Hydroelectric License Renewal
In May 2005, UE, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage hydroelectric plant for another 40 years. The settlement must be approved by FERC. The current FERC license expired on February 28, 2006. Operations are permitted to continue under the expired license until the license renewal is approved.
Joint Dispatch Agreement
See Note 13 - Related Party Transactions for a description of the JDA among UE, CIPS and Genco, which terminated on December 31, 2006.
January 2006 JDA Amendment
As a result of the February 2005 MoPSC order approving the transfer of UE’s Illinois service territory to CIPS that was completed on May 2, 2005, the provision in the JDA that determines the allocation between UE and Genco of margins from short-term sales of excess generation to third parties had to be modified. Specifically, the MoPSC order required an amendment so that margins on third-party short-term power sales of excess generation would be allocated between UE and Genco based on generation output, not on load requirements, as the agreement had provided. In March 2006, FERC approved the amendment filed by UE, CIPS and Genco, effective January 10, 2006. This change in the allocation methodology resulted in a $23 million transfer of electric margins from Genco to UE during the year ended December 31, 2006.
Termination of JDA
On July 7, 2006, UE, CIPS and Genco mutually consented to waive a one-year termination notice requirement of the JDA and agreed to terminate it on December 31, 2006. This action with respect to the JDA was accepted by FERC in September 2006.
The benefits of the JDA to UE and Genco changed due to the emergence of transparent wholesale markets, the dispatching of generation being conducted by the MISO, and changes to the Illinois regulatory framework, among other things. As a result, UE believed the benefit it would receive from retaining the power it was transferring under the JDA to Genco at incremental cost would exceed the benefit it would have received from being able to call upon Genco’s generation under the JDA at incremental cost. Since UE was prepared to immediately provide Genco with one-year notice of termination in June 2006, Genco believed the potential benefit it could receive from being able to call upon UE’s generation through June 2007 was outweighed by, among other things, the negative consequences associated with the continued existence of the JDA past December 31, 2006. In particular, Genco believed that the JDA was no longer necessary or effective for dispatching Genco’s generation jointly with that of UE, because of changes in the marketplace for the sale of electricity, including the MISO Day Two Energy Market, and the centralized dispatching of generation by MISO. Additionally, the JDA was based on a combined control area for the UE and CIPS transmission facilities located in Missouri and Illinois, respectively. This combined control area created operational inefficiencies for Genco to effectively participate through Marketing Company in the Illinois power procurement auction to supply power beginning January 1, 2007. In conjunction with terminating the JDA, Ameren’s transmission-owning entities restructured their control areas into two areas: one in Missouri for UE’s transmission facilities and one in Illinois for the transmission facilities of CIPS, CILCO and IP. In December of 2006, FERC authorized the restructuring of the control areas as requested.
As a result of the termination of the JDA on December 31, 2006, UE and Genco no longer have the
obligation to provide power to each other. In 2006, Genco received from UE under the JDA net transfers of 10.1 million megawatthours of power at an average price of $19 per megawatthour and generated 15.3 million megawatthours of power from its plants at an average cost of $20 per megawatthour. This power was used in 2006 to supply CIPS’ load and other wholesale and retail customers at an average selling price of $36 per megawatthour. In 2006, Genco also sold 2.1 million net megawatthours of power in the interchange market at an average price of $38 per megawatthour. Upon termination of the JDA, Genco no longer receives the margins on sales that were supplied with power from UE.
Ameren’s and UE’s earnings will be affected by the termination of the JDA when UE’s rates are adjusted by the MoPSC. As discussed under Missouri Electric in this Note, UE filed a request in July 2006 with the MoPSC to increase its electric rates by $361 million. UE’s requested increase is net of the decrease in its revenue requirement resulting from increased margins expected to result from the termination of the JDA.
The ultimate impact of the termination of the JDA and the MoPSC’s treatment of the effects of such termination in UE’s current rate case proceeding on the Ameren Companies’ results of operations, financial position, or liquidity cannot be predicted at this time.
Leveraged Leases
Ameren owns interests in certain assets that were acquired with the acquisition of CILCORP that have been financed as leveraged leases. By an order dated April 15, 2004, issued pursuant to PUHCA 1935, the SEC determined that certain nonutility interests and investments of CILCORP and its subsidiaries, including investments in several leveraged leases, were not retainable by Ameren. The April 2004 SEC order required that Ameren cause its subsidiaries to sell or otherwise dispose of the nonretainable interests. The nonretainable interests primarily consist of lease interests in commercial real estate properties and equipment. The SEC approved the divestiture transaction structure proposed by Ameren in December 2005.
Ameren also owns interests in certain assets, acquired through the acquisition of CIPSCO, that have been financed as leveraged leases. One of these is an investment by an Ameren subsidiary involving an aircraft leased to Delta Air Lines, Inc. In September 2005, Delta Air Lines filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Although Ameren continues in its ownership of the lease, Ameren cannot predict the ultimate ability of Delta Air Lines to service debt and pay future rentals required under the lease, or the outcome of the bankruptcy process. Accordingly, Ameren recorded a pretax impairment of $10 million in the third quarter of 2005. By an order dated December 13, 2005, issued pursuant to PUHCA 1935, the SEC determined that CIPSCO’s interest in the Delta Air Lines leveraged lease should be divested. The SEC approved the divestiture transaction structure proposed by Ameren.
Ameren and several of its registrant and nonregistrant subsidiaries sold leveraged leases during 2006. The overall net gain (loss) before taxes from the sale of all these assets recognized by Ameren, CILCORP and CILCO was $3 million, ($7 million) and ($11 million), respectively.
Ameren is actively pursuing the sale of its interests in its remaining three leveraged lease assets.
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, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
See Note 1 - Summary of Significant Accounting Policies - Goodwill and Intangible Assets and Note 10 - Retirement Benefits for additional information.
(c)
Amount represents SFAS No. 109 deferred tax asset. See Note 12 - Income Taxes for amortization period.
(d)
These assets do not earn a return.
(e)
Represents recoverable costs for AROs at our rate-regulated operations. See SFAS No. 143 discussion in Note 1 - Summary of Significant Accounting Policies.
(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 repaid 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. Per the ICC order approving Ameren’s acquisition of IP, these costs are recoverable over four years after 2006 through rates.
(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 will be amortized over the remaining life of the related debt upon expiration of the electric rate freeze in Illinois on January 1, 2007.
(k)
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 being amortized over 14 years through 2007. In addition, this amount includes the portion of merger-related expenses applicable to the Missouri retail jurisdiction, which are being amortized through 2007 based on a MoPSC order.
(l)
Represents unamortized portion of investment tax credit and federal excise taxes. See Note 12 - Income Taxes for amortization period.
(m)
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 SFAS No. 143 discussion in Note 1 - Summary of Significant Accounting Policies.
(n)
Represents the deferral of gains on emission allowance vintage swaps UE entered into during 2005.
(o)
Represents deferral of SFAS No. 133 natural gas-related derivative market-to-market gains.
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 4 - PROPERTY AND PLANT, NET
The following table presents property and plant, net for each of the Ameren Companies at December 31, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
NOTE 5 - CREDIT FACILITIES AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, commercial paper issuances, and drawings under committed bank credit facilities.
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, 2006 and 2005, respectively:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit facility described below for the year ended December 31, 2006:
(a)
Amount is less than $1 million
At December 31, 2006, Ameren and certain of its subsidiaries had $1.65 billion of committed credit facilities, consisting of two facilities described below, in the amounts of $1.15 billion and $500 million. The $1.15 billion facility and the 2006 $500 million facility mature in July 2010 and January 2010, respectively.
Ameren could directly borrow under the $1.15 billion facility up to the entire amount of the facility. UE could directly borrow under this facility up to $500 million on a 364-day basis. Genco could directly borrow under this facility up to $150 million on a 364-day basis. Until July 13, 2006, CIPS, CILCO and IP could also each directly borrow under this facility up to $150 million on a 364-day basis. On July 14, 2006, the $1.15 billion credit facility was amended. The amended facility will terminate on July 14, 2010, with respect to Ameren. Effective July 13, 2006, the termination date for UE and Genco was extended to July 12, 2007. CIPS, CILCO and IP no longer had borrowing authority under this facility effective July 13, 2006, but remained parties to the agreement until September 8, 2006, as discussed in the Indebtedness Provisions and Other Covenants section below. Under the amended facility, Ameren will continue to have $1.15 billion of borrowing availability. UE and Genco will continue to have $500 million and $150 million, respectively, of borrowing availability.
Under the amended $1.15 billion credit facility, the principal amount of each revolving loan under the facility 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. The principal amount of each loan will be due and payable at the end of the interest period applicable to it, which shall not be later than the final maturity date of the facility. 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 amended facility for general corporate purposes, including for working capital, commercial paper liquidity support, and to fund loans under the Ameren money pool arrangements. See Exhibit 10.1 to the Current Report on Form 8-K, dated July 18, 2006, for a copy of the amended facility agreement.
On July 14, 2006, CIPS, CILCORP, CILCO, IP and AERG entered into a $500 million multiyear, senior secured credit facility expiring in 2010 (the 2006 $500 million credit facility). Borrowing authority under this facility was effective immediately for AERG and CILCORP and effective for CIPS, CILCO and IP on September 8, 2006, upon the receipt of regulatory approvals and the issuance by CIPS, CILCO and IP of mortgage bonds as security as described below. Once CIPS, CILCO and IP were authorized to borrow under this new facility, they were removed as parties to the $1.15 billion credit facility.
On February 9, 2007, CIPS, CILCORP, CILCO, IP and AERG entered into another $500 million multiyear, senior secured credit facility (the 2007 $500 million credit facility), also expiring in January 2010. Borrowing authority under this facility was effective immediately for CILCORP and AERG. The ability of CIPS, CILCO and IP to borrow under this facility is subject to the receipt of necessary regulatory approvals, and the issuance by CIPS, CILCO and IP of mortgage bonds as security as described below. The 2007 $500 million credit facility is in addition to the 2006 $500 million credit facility, which remains in effect.
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 - $150 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, 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 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 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). Borrowings by CIPS, CILCO and IP under the 2006 and 2007 $500 million credit facilities is on a 364-day basis. 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 on September 8, 2006, of mortgage bonds by each such utility under its respective mortgage indenture in the amounts of $135 million, $150 million and $150 million, respectively. Subject to the receipt of regulatory approval, the obligations of these companies under the 2007 $500 million credit facility will be secured by the issuance of mortgage bonds by each such utility under its respective mortgage indenture. 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 will 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. 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. See Exhibit 10.2 to the Current Report on Form 8-K, dated July 18, 2006, for a copy of the 2006 $500 million credit facility agreement and see Exhibit 10.1 to the Current Report on Form 8-K, dated February 13, 2007, for a copy of the 2007 $500 million credit facility agreement.
As a condition to the amendment of the $1.15 billion credit facility and the closing of the 2006 $500 million credit facility, effective July 14, 2006, Ameren terminated its $350 million credit facility. Ameren was the only borrower under this agreement, and there was no early termination penalty.
The $1.15 billion credit facility and the now-terminated $350 million credit facility were used to support the commercial paper programs that included all outstanding external short-term debt of Ameren and UE as of December 31, 2006 and 2005. The $1.15 billion amended facility will continue to support Ameren’s and UE’s commercial paper programs. 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. As a result of S&P’s downgrade of Ameren’s and UE’s short-term ratings to A-3 in October 2006, Ameren and UE are currently limited in their access to the commercial paper market.
In April 2006, EEI’s $20 million bank credit facility expired and was not renewed.
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 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, 2006, was 5.03% (2005 - 3.25%).
Non-state-regulated subsidiaries
Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, Ameren Energy and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement subject to applicable regulatory short-term borrowing authorizations. However, 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 other external sources. At December 31, 2006, $861 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, 2006 was 4.65% (2005 - 5.49%).
See Note 13 - 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, 2006, 2005, and 2004.
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.
Indebtedness Provisions and Other Covenants
The bank credit facilities described above contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. As discussed above, the $1.15 billion credit facility was amended effective July 14, 2006. The provisions in the amended facility are similar to those in the prior facility, including the covenant that limits total indebtedness of each of Ameren, UE and Genco to 65% of consolidated total 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 amended $1.15 billion credit facility also contains default provisions similar to those in the prior facility, including cross defaults, with respect to a borrower under the facility, that can result from the occurrence of 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 amended facility remain several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. With the termination of CIPS, CILCO and IP as parties to this agreement on September 8, 2006, they are no longer considered subsidiaries for purposes of the cross-default or other provisions, nor are CILCORP or AERG.
Under the amended $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 that remains in the amended facility.
Both the 2006 $500 million credit facility and the 2007 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG, discussed above, 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 amended $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 such borrower will be limited to capital stock dividend payments of $10 million per year each, 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. A similar restriction applies to AERG if its debt-to-operating cash flow ratio, as set forth in the facility, is above a 3.0 to 1.0 ratio. As of December 31, 2006, AERG failed to meet the debt-to-operating cash flow ratio test in the 2006 $500 million credit facility. AERG, therefore, is currently limited in its ability to pay dividends to a maximum of $10 million per fiscal year. As a result of the limitation, CILCO’s and AERG’s net assets restricted for dividend payments were $525 million and $321 million, respectively, as of December 31, 2006. 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 would be limited by dividend restrictions at CILCORP.
The 2006 $500 million credit facility and the 2007 $500 million credit facility also limit the amount of other secured indebtedness issuable by each borrower as follows: for CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other secured debt is limited to $550 million under the 2006 $500 million credit facility and $425 million under the 2007 $500 million credit facility, secured by the pledge of CILCO stock. For AERG, other secured debt is limited to $200 million under the 2006 $500 million credit facility and $100 million under the 2007 $500 million credit facility secured on an equal basis with its obligations under the facilities.
The 2006 $500 million credit facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures (that is, agree to forgo the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture) 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. In addition, the credit facility prohibits CILCO from issuing any preferred stock if, after giving effect to such issuance, the aggregate liquidation value of all CILCO preferred stock issued after July 14, 2006, 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 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, 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.
As of December 31, 2006, the ratio 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 was 50%, 48% 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, were 49%, 54%, 41%, 44% and 29%, 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, 2006, the Ameren Companies were in compliance with their credit facility provisions and covenants.
NOTE 6 - LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2006 and 2005:
(a)
At December 31, 2006, 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 or CILCO, 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).
(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. The average interest rates for the years 2006 and 2005 were as follows:
(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.
(h)
Less than $1 million.
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2006:
(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 $60 million related to CILCORP’s long-term debt fair market value adjustments.
(c)
Excludes $32 million related to IP’s long-term debt fair market value adjustments and includes $35 million for TFN overfunding.
All of the Ameren Companies expect to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing. See Note 5 - 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, 2006:
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. In July 2004, Ameren issued, pursuant to the June Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share, for net proceeds of $445 million. The proceeds from this offering were used to pay the cash portion of the purchase price for Ameren’s acquisition of IP and Dynegy’s 20% interest in EEI and, as described below under IP, to reduce IP debt assumed as part of the acquisition and to pay related premiums.
The purchase of IP on September 30, 2004, included the assumption of IP debt and preferred stock at closing of $1.8 billion. The assumed debt and preferred stock included $936 million of mortgage bonds, $509 million of pollution control indebtedness supported by mortgage bonds, $352 million of TFNs issued by IP SPT, and $13 million of preferred stock not acquired and owned by Ameren. Upon acquisition, total IP debt was increased to fair value by $191 million. The adjustment to the fair value of each debt series is being amortized to interest expense over its remaining life, or to the expected redemption date. As of December 31, 2006, the unamortized balance of this fair market value adjustment was $32 million, as a result of amortization and the redemption of several of IP’s debt series. The following table presents the amortization of the fair value adjustment 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. Under DRPlus and its 401(k) plans, Ameren issued 1.9 million, 2.1 million, and 2.3 million shares of common stock in 2006, 2005, and 2004, respectively, which were valued at $96 million, $109 million, and $107 million for the respective years.
In March 2002, Ameren issued $345 million of adjustable conversion-rate equity security units. The $25 adjustable conversion-rate equity security units each consisted of an Ameren senior unsecured note with a principal amount of $25 maturing on May 15, 2007, and a contract to purchase, for $25, a fraction of a share of Ameren common stock on May 15, 2005. In February 2005, the annual interest rate on the $345 million principal amount
of Ameren’s senior unsecured notes due May 15, 2007 was reset from 5.20% to 4.263%. As part of this remarketing, Ameren also repurchased $95 million in principal amount of the senior unsecured notes, which it subsequently retired. In May 2005, settlement of the stock purchase contracts resulted in Ameren issuing 7.4 million shares of common stock in exchange for $345 million of proceeds.
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.
UE
In January 2005, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $85 million of 5.00% senior secured notes due February 1, 2020, with interest payable semi-annually on February 1 and August 1 of each year, beginning in August 2005. UE received net proceeds of $83 million, which were used to repay short-term debt temporarily incurred to fund the maturity of UE’s $85 million 7.375% first mortgage bonds due 2004.
In July 2005, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.30% senior secured notes due August 1, 2037, with interest payable semi-annually on February 1 and August 1 of each year, beginning in February 2006. UE received net proceeds of $296 million, which were used to repay short-term debt.
On October 20, 2005, the SEC declared effective a Form S-3 shelf registration statement filed by UE and its subsidiary trust on September 23, 2005, amended on October 12, 2005, covering the offering from time to time of up to $1 billion of various forms of long-term debt and preferred securities.
In December 2005, UE issued, pursuant to its October 2005 SEC Form S-3 shelf registration statement, $260 million of 5.40% senior secured notes due February 1, 2016, with interest payable semi-annually on February 1 and August 1 of each year, beginning in August 2006. UE received net proceeds of $256 million, which were used to repay short-term debt.
UE’s debt increased $240 million in the first quarter of 2006 as a result of the capital lease assigned to it in connection with the acquisition from affiliates of NRG Energy, Inc., 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. See Note 2 - Acquisitions for further discussion of the CT facility purchase.
CIPS
In June 2005, $20 million of CIPS’ 6.49% first mortgage bonds matured and were retired.
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 beginning in January 2007. The receivable for this repurchased bond is in Other Current Assets on CIPS’ balance sheet.
See Note 5 - Credit Facilities and Liquidity regarding first mortgage bonds issued by CIPS in September 2006 as security for its obligations under the 2006 $500 million credit facility.
Genco
In November 2005, $225 million of Genco’s 7.75% senior notes matured and were retired with available cash and short-term borrowings.
CILCORP
In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. This resulted in recognition of fair value adjustment increases of $71 million related to CILCORP’s 9.375% senior bonds due 2029 and $40 million related to its 8.70% senior notes due 2009. Amortization related to these fair value adjustments was $6 million, $7 million, and $8 million for the years ended December 31, 2006, 2005, and 2004, respectively, and costs related to repayments during the year were $2 million, $8 million, and $5 million for the years ended December 31, 2006, 2005, and 2004, respectively. These amounts were included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.
In 2005, CILCORP repurchased $74 million in principal amount of its 8.70% senior notes due 2009.
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 5 - 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 both 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 2006 and 2005.
In December 2005, $16 million of CILCO’s 6.13% 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 $95 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 commenced the offer to exchange registered secured notes for the outstanding unregistered senior secured notes under the related registration rights agreement on October 18, 2006, and all of the bonds were exchanged on or before November 16, 2006. In January 2007, $50 million of CILCO’s 7.50% first mortgage bonds matured and were retired. See Note 5 - Credit Facilities and Liquidity regarding first mortgage bonds issued by CILCO in September 2006 as security for its obligations under the 2006 $500 million credit facility and 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
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 $13 million, $16 million, and $14 million for the years ended December 31, 2006, 2005, and 2004, respectively, and was included in interest expense in the consolidated statements of income of Ameren and IP.
In November 2004, pursuant to an equity clawback provision in the related bond indenture, IP redeemed $192.5 million principal amount of its 11.50% series mortgage bonds due 2010. The redemption price was equal to $1,115 per $1,000 principal amount, plus accrued and unpaid interest. Also in November 2004, IP completed a cash tender offer for $351 million of these bonds. The tender offer consideration paid was $1,214 per $1,000 principal amount plus accrued and unpaid interest. This tender offer satisfied IP’s indenture obligation to offer to purchase the bonds resulting from the change of control of IP upon its acquisition by Ameren. In December 2004, IP repurchased an additional $6.5 million principal amount of these bonds at a redemption price of $1,207 per $1,000 principal amount plus accrued unpaid interest. On December 15, 2006, IP redeemed the remaining $33,000 principal amount of these bonds.
In March 2005, $70 million of IP’s 6.75% mortgage bonds matured and were retired with available cash.
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 commenced the offer to exchange registered secured notes for the outstanding unregistered senior secured notes under the related registration rights agreement on October 18, 2006, and all of the bonds were exchanged on or before November 16, 2006.
See Note 5 - Credit Facilities and Liquidity regarding mortgage bonds issued by IP in September 2006 as security for its obligations under the 2006 $500 million credit facility.
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, 2006 and 2005, consolidated balance sheets.
EEI
In December 2005, $8 million and $7 million of EEI’s 6.61% and 8.60% senior medium-term notes, respectively, matured and were retired.
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, 2006, 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.
(b)
Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(c)
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 $18 million, $3 million, $125 million and $1.3 billion, respectively, for which no earnings coverage test is required.
(d)
Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the 2006 $500 million credit facility entered into by these companies. See Note 5 - Credit Facilities and Liquidity for further discussion.
(e)
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.
(f)
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, 2006, CILCO had earnings equivalent to at least 57% of the principal amount of all mortgage bonds outstanding.
(g)
See Note 5 - 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.
In addition, 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 $1.7 billion of free and unrestricted retained earnings at December 31, 2006.
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.
The restrictions on the ability of IP to declare and pay dividends on its common stock that were established by the ICC order approving Ameren’s acquisition of IP terminated in December 2006 with IP’s redemption of the remaining $33,000 of its 11.50% series mortgage bonds due 2010.
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, 2006:
(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 such 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, 2006, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba1, and BBB+, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes, 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, 2006, 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 7 - OTHER INCOME AND EXPENSES
The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended December 31, 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004, and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
January through September 2004 predecessor miscellaneous income and expense amounts were $144 million and $1 million, respectively.
NOTE 8 - 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 pretax net gain or loss on power hedges is included in Operating Revenues - Electric, and the pretax net gain or loss on hedges related to SO2 emission allowances, fuel or power supply, and natural gas are included in Operating Expenses - Fuel and Purchased Power. This pretax net gain or 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, resulting in a $7 million gain for Ameren, a $5 million gain for UE, a $2 million loss for IP and a $1 million loss for Genco for the year ended December 31, 2006 (2005 - $6 million gain for Ameren, less than a $1 million gain for UE, and a $1 million gain for Genco); 2004 - $3 million gain for Ameren and Genco).
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, 2006 and 2005:
(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 $63 million in 2007.
(c)
Represents 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.
(d)
Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2011.
Other Derivatives
The following table represents the net change in market value for the years ended December 31, 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 and Purchased Power.
(a)
Power forwards and FTRs were less than $1 million in 2006.
(b)
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. The valuation of FTRs is complex due to the lack of available historical market data. As of December 31, 2006, the net value of FTRs held by the Ameren Companies was determined to be immaterial.
NOTE 9 - 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 stock 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 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, 2006 and 2005:
(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. See Note 2 - Acquisitions for additional information.
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, 2006 and 2005, 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 10 - 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.
The Pension Protection Act of 2006, signed by President Bush in August 2006, will affect the manner in which companies administer their pension plans. This legislation increases the funding target for qualified plans, increases the level of retirement benefit security over time and reduces the financial exposure of the Pension Benefit Guaranty Corporation (PBGC), among other things. Ameren does not anticipate a material impact on our results of operations, financial position, and liquidity at this time.
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. The
following table presents the incremental effect of applying SFAS No. 158 to individual line items in Ameren’s consolidated balance sheet as of December 31, 2006.
(a)
See Note 1 - Summary of Significant Accounting Policies - Goodwill and Intangible Assets for additional information.
Ameren adopted FSP SFAS 106-2 “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” during the second quarter of 2004, retroactive to January 1, 2004, which resulted in the recognition of a federal subsidy for postretirement benefit costs related to prescription drug benefits. The effect of this subsidy was a reduction of various components of Ameren’s and principally UE’s net periodic postretirement benefit costs. Interest costs were reduced by $4 million, and amortization of losses was reduced by $7 million. The impact of the subsidy on the expected return on plan assets was minimal.
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. Our plans are funded in compliance with income tax regulations and federal funding requirements. 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, 2006:
(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, 2006 and 2005:
(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 2007.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2006 and 2005:
Ameren’s current reconciliation of funded status shows certain amounts that will be recognized as a benefit cost in future years. The unrecognized losses are 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 2006 and 2005.
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Based on our assumptions at December 31, 2006, and the new contribution requirements in the Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009, at which time we would expect a required contribution of $100 million to $150 million. Required contributions of $150 million to $200 million each year are also expected for 2010 and 2011. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 61%, 10%, 11%, 7%, 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.
Ameren uses plan actuaries to determine discount rate assumptions. Ameren’s actuaries have developed 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 constructed 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 2007 and our pension and postretirement plan asset categories as of December 31, 2006 and 2005:
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans during 2006, 2005 and 2004:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries.
(c)
Represents predecessor information for the first nine months of 2004.
The estimated amounts that will be amortized from regulatory assets or accumulated OCI into net periodic benefit cost in 2007 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 (gain) subject to amortization is amortized on a straight-line basis over 10 years.
UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their proportional 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, 2006, 2005 and 2004:
(a)
Includes predecessor information for periods prior to the acquisition date of September 30, 2004. Predecessor amount for pension costs and postretirement costs in 2004 are $7 million and $12 million, respectively.
The expected pension and postretirement benefit payments from qualified trust and company funds, 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, 2006, 2005 and 2004:
(a)
Included in Ameren’s plan for 2006 and 2005.
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
Other
Ameren and CIPS sponsor 401(k) plans for eligible employees. The CIPS 401(k) plan is available only to employees represented by IBEW Local 702. All other CIPS employees are eligible to participate in the Ameren 401(k) plan. The former CIPS IUOE Local 148 plan was merged into the Ameren plan during the first quarter of 2005. IP employees began participating in the Ameren plan during the fourth quarter of 2004. The former CILCO plan was merged into the Ameren plan at the beginning of 2004. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren and CIPS match a percentage of the employee contributions up to certain limits. Ameren’s matching contribution to the 401(k) plan totaled $19 million and $18 million in 2006 and 2005, respectively. Ameren’s and IP’s matching contributions to the 401(k) plans totaled $15 million and $2 million (predecessor), respectively, in 2004. CIPS’ matching contributions to its 401(k) plan were less than $1 million annually in 2006, 2005 and 2004.
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, 2006, 2005 and 2004:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 11 - 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 number of 4 million common shares 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, 2006, and changes during the year ended December 31, 2006, under the 1998 Plan and the 2006 Plan is presented below:
(a)
Includes 220,003 performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in February 2006 under the 1998 Plan and 130,637 share units granted in February 2006 under the 2006 Plan to certain executive officers subject to shareholder approval, which was obtained on May 2, 2006. The share units granted under the 2006 Plan were not considered as granted until approved by shareholders. Accordingly, compensation expense recognition for these awards commenced in May 2006.
(b)
Share units issued under the 1998 Plan vested due to deaths of employees and 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 $11 million, $6 million and $5 million for the years ended December 31, 2006, 2005 and 2004, respectively, and a related tax benefit of $1 million, $2 million and $5 million for the years ended December 31, 2006, 2005 and 2004, respectively. As of December 31, 2006, total compensation cost of $19 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 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 based on assumptions similar 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 and 2004, respectively, 154,086 and 135,340 restricted stock awards were granted. The weighted-average fair value for restricted stock awards granted was $51.21 per share in 2005 and $46.34 per share in 2004. 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 106,212 at December 31, 2006, expire on various dates through 2010. Ameren applied APB Opinion No. 25 in accounting for our stock-based compensation for years prior to 2003. Effective January 1, 2003, Ameren prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of SFAS No. 123. Options granted prior to the SFAS 123 adoption were fully expensed during 2004. Therefore, there is no expense from stock options for the years ended December 31, 2006, and December 31, 2005. See Note 1 - Summary of Significant Accounting Policies for further information.
NOTE 12 - 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, 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004.
(b)
Represents predecessor information for January through September 2004.
(c)
Permanent items primarily include Section 199 production activities for Ameren, UE, Genco, CILCORP and CILCO, company owned life insurance for Ameren and CILCORP, SFAS No. 106-2 Medicare Part D for Ameren, UE, CIPS, CILCORP and CILCO and employee stock ownership plan dividend for Ameren.
(d)
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 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 2004 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from the permanent effect of a litigation settlement ($6 million), plant-related depreciation differences ($2 million), and investment tax credit amortization ($2 million).
(e)
Genco Other for 2006 primarily includes resolution of prior period tax matters.
(f)
Primarily includes life insurance for CILCO and miscellaneous items for other registrants.
(g)
CILCO Other for 2005 primarily includes low-income housing tax credits and resolution of prior-period tax matters.
(h)
Permanent items primarily include SFAS No. 106-2 Medicare Part D for Ameren, UE, CIPS, CILCORP and CILCO and a litigation settlement at CILCORP and CILCO.
The following table presents the components of income tax expense for the years ended December 31, 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004.
(b)
Represents predecessor information for January through September 2004.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2006 and 2005:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
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.
(c)
Includes $39 million, $34 million, $4 million, and $8 million recorded as current assets in the consolidated balance sheet for Ameren, UE, CILCORP, and CILCO, respectively.
Ameren, Genco, CILCORP and IP have Illinois net operating loss carryforwards of $424 million, $2 million, $204 million and $203 million, respectively. These will begin to expire in 2016.
Upon Ameren’s acquisition of IP, IP’s net accumulated deferred income tax liabilities and unamortized accumulated investment tax credits were eliminated.
NOTE 13 - 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.
Electric Power Supply Agreements
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. For native load, CIPS paid an annual capacity charge per megawatt for its forecasted peak demand or actual demand, whichever was greater, plus an energy charge per megawatthour to Marketing Company. For fixed-price retail customers outside of the tariff, CIPS paid Marketing Company the price it received under these contracts. The fees paid by CIPS to Marketing Company for native load and fixed-price retail customers and any other sales by Marketing Company under various long-term wholesale and retail contracts were passed through to
Genco. In addition, under the power supply agreement between Genco and Marketing Company, Genco bore all generation-related operating risks, including plant performance, operations, maintenance, efficiency, employee retention, and other matters. There were no guarantees, bargain purchase options, or other terms that conveyed to CIPS the right to use the property and plant of Genco.
In October 2003, in conjunction with CILCO’s transfer to AERG of substantially all of its generating assets, AERG entered into an electric power supply agreement to supply CILCO with sufficient power to meet its native load requirements. CILCO paid a monthly capacity charge per megawatt based on its system capacity requirements, plus an energy charge per megawatthour. This agreement expired on December 31, 2006. Also in conjunction with CILCO’s generating asset transfer, a bilateral power supply agreement was entered into between AERG and Marketing Company. This agreement provided for AERG to sell excess power to Marketing Company for sales outside the CILCO control area, and it also allowed Marketing Company to sell power to AERG to fulfill CILCO’s native load requirements.
In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco will sell and Marketing Company will purchase all of the capacity available from Genco’s generation fleet and such amount of 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 from these 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 or other expenses are subtracted (excluding those expenses which 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 will sell and Marketing Company will purchase all of the capacity available from AERG’s generation fleet and such amount of 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 the January 2006 ICC order discussed in Note 3 - Rate and Regulatory Matters, an auction was held in September 2006 to procure power for CIPS, CILCO and IP after current power supply contracts expired on December 31, 2006. In conjunction with the auction, there was a limitation of 35% on the amount of power any single supplier could provide of the Ameren Illinois Utilities’ expected annual load. Ameren-affiliated companies were considered one supplier for the purposes of this limitation.
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:
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. By the end of 2006, nearly all of these customers switched to other suppliers as a result of the auction price.
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 are parties to a power supply agreement with Midwest Electric Power, Inc., a subsidiary of EEI, to purchase capacity and energy. This agreement’s term is year-to-year on a calendar basis, unless the purchasing parties unanimously agree to terminate their participation. In December 2005, Marketing Company entered into a power supply agreement with EEI, effective January 2006, whereby EEI will sell 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.
IP had a contract that expired at the end of 2004 with a former affiliate, DMG, to supply power via purchase agreements. The purchased power agreement with DMG obliged DMG to provide power to IP up to the reservation amount, and at the same prices, even if DMG had individual units unavailable at various times.
IP was party to several commercial and industrial electric and gas sales agreements with DMG, which were entered into before Ameren’s acquisition of IP. These were typically yearly contracts that renewed automatically unless cancelled by either party with a 30-day written notice.
Also before Ameren’s acquisition, IP purchased natural gas from Dynegy to serve its gas distribution business under a Gas Industry Standards Board master base contract that terminated October 1, 2004. One transaction was executed in 2004 to provide deliveries from January to March 2004.
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.
IP was a party to transmission and interconnection sales agreements with DYPM, a former affiliate, for the use of IP’s transmission lines and other facilities. The transmission sales agreements expired in April and June 2005. The interconnection sales agreements expired January 1, 2006. On October 1, 2004, pursuant to the sale of IP to Ameren, all continuing contracts with Dynegy and its affiliates became third-party agreements.
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 through Ameren Energy, which served as each affiliate’s agent. To allocate power costs between UE and Genco, an intercompany sale was recorded by the company sourcing the power to the other company. Ameren Energy also acted as agent on behalf of UE and Genco to purchase power when they required it. As further discussed in Note 3 - Rate and Regulatory Matters, 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 on July 7, 2006, UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement of the JDA and agreed to terminate it on December 31, 2006. This action with respect to the JDA was accepted by the FERC in September 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, Ameren Energy, and AFS to their affiliates, including wages, employee benefits, professional services, and other expenses are based on, or are an allocation of, actual costs incurred. Effective September 30, 2004, IP was added to the support services agreements with Ameren Services and AFS. Before that, IP operated under Dynegy’s consolidated group’s Services and Facilities Agreement, whereby other Dynegy affiliates exchanged with IP services such as financial, legal, information technology, and human resources, as well as shared facility space. IP services were exchanged at fully distributed costs, and revenues were not recorded under this agreement. This agreement was terminated in conjunction with IP’s sale to Ameren.
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.
Note Receivable from Former Affiliate
In September 2004, IP’s $2.3 billion note receivable from a former affiliate was eliminated in connection with the sale of IP to Ameren. In January 2004, IP received an additional interest prepayment of $43 million. These notes contained payment provisions pursuant to which semi-
annual interest payments of $86 million were due on April 1 and October 1 of each year.
Transitional Funding Securitization Financing Agreement
IP’s financial statements include related party transactions with IP SPT, its wholly owned unconsolidated subsidiary, which was deconsolidated in accordance with the adoption of FIN 46R effective on December 31, 2003. 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 46R and resulting deconsolidation of IP SPT, these amounts are netted against the current portion of IP’s long-term debt payable to IP SPT on IP’s December 31, 2006, Consolidated Balance Sheet. See Note 1 - Summary of Significant Accounting Policies for further information.
Money Pools
See Note 5 - Credit Facilities and Liquidity for discussion of affiliate borrowing arrangements.
Intercompany Promissory Notes
In November 2004, Genco made a $75 million principal prepayment under its 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. On May 1, 2005, Genco and CIPS amended the maturity date and interest rate of the subordinated note payable to CIPS. 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 5-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 $12 million, $15 million, and $23 million for the years ended December 31, 2006, 2005, and 2004, 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 and $2 million from this note payable to Ameren for the years ended December 31, 2005 and 2004, respectively.
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 at 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 December 31, 2005, respectively.
CILCORP has been granted authority by the FERC in a 2006 order to borrow up to $250 million directly from Ameren. The outstanding borrowings were $73 million and $186 million at December 31, 2006 and 2005, respectively. The average interest rate on these borrowings was 4.65% for the year ended December 31, 2006 (2005 - 5.48%). CILCORP recorded interest expense of $7 million, $6 million, and $5 million for these borrowings for the years ended December 31, 2006, 2005 and 2004 respectively.
Operating Leases
Under an operating lease agreement, Genco is leasing certain CTs at a Joppa, Illinois, site to its parent, Development Company, for an initial term of 15 years, expiring September 30, 2015. Development Company, upon satisfaction of certain conditions, has the option to renew this lease for up to two consecutive five-year renewal terms. Genco recorded operating revenues from the lease agreement of $11 million, $10 million, and $10 million for the three years ended December 31, 2006, 2005, and 2004, respectively. Under an electric power supply agreement with Marketing Company, Development Company supplies the capacity and energy from these leased units to Marketing Company, which in turn supplies the energy to Genco.
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the years ended December 31, 2006, 2005 and 2004. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 5 - Credit Facilities and Liquidity.
(a)
Amounts represent CILCORP and CILCO activity.
(b)
Includes Ameren affiliate transactions subsequent to acquisition date of September 30, 2004.
(c)
Not applicable.
(d)
Amount less than $1 million.
Predecessor IP
The following table presents the impact of related party transactions on predecessor IP’s Consolidated Statement of Income for the nine-month period ended September 30, 2004, based primarily on the various predecessor agreements discussed above:
NOTE 14 - COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the course of daily business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies, 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 an adverse material 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, 2006. The property and liability coverages were renewed on October 1, 2005 and January 1, 2006, respectively.
(a)
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.
(b)
Limit of liability for each incident under Price-Anderson.
(c)
Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation.
(d)
Includes premature decommissioning costs.
(e)
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.
Price-Anderson limits the liability for claims from an incident involving any licensed United States nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years to reflect changes in the Consumer Price Index. Utilities owning 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.
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 self-insures the risk. If a serious nuclear incident occurred, it could have a material but indeterminable adverse effect on our results of operations, financial position, or liquidity.
Leases
The following table presents our lease obligations at December 31, 2006:
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
See Note 2 - Acquisitions and Note 6 - 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 2 - Acquisitions and Note 6 - 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 periods ended December 31, 2006, 2005 and 2004:
(a)
Excludes amounts for IP before the acquisition date of September 30, 2004, and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
January through September 2004 predecessor amount was $4 million.
Other Obligations
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments to procure coal, natural gas, and nuclear fuel. In addition, we 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, 2006:
(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, 2006, less than one million dollars 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 synthetic natural gas purchases pursuant to a 20-year supply contract beginning in April 2011.
Commencing January 1, 2007, CIPS, CILCO and IP are required to obtain all electric supply requirements for customers that do not purchase electric supply from third-party suppliers through the Illinois power procurement auction. See Note 3 - Rate and Regulatory Matters for information on the Illinois power procurement auction and related matters, including pending court appeals that challenge the auction process and the recovery by utilities through rates to customers of costs for power supply resulting from the auction.
CIPS, CILCO and IP entered into power supply contracts with winning bidders of the Illinois power procurement auction held in September 2006. As of January 1, 2007, 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). 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 2007 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 and 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)
Represents 2007 peak forecast load for CIPS, CILCO and IP. Actual load could be different because of weather, among other things.
Environmental Matters
We are subject to various environmental laws and regulations by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, and natural gas storage plants, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, and 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 preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations, as required. The more significant matters are discussed below.
Clean Air Act
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 new rules require significant reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. States are required to finalize 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 proposed rules to implement the federal Clean Air Interstate Rule program; however it is anticipated that the rules will not be finalized until the second quarter of 2007.
The Missouri Department of Natural Resources formally proposed rules to implement the federal Clean Air Mercury and Clean Air Interstate Rules in November 2006. These rules substantially follow the federal rules. In December 2006, the Missouri Air Conservation Commission held a public hearing on these proposed rules. The Missouri Air Conservation Commission approved the rules at their February 2007 meeting. The rules will be effective after publication in the Missouri Register targeted for April 2007. The rules will also need to be approved by the EPA. When they are fully implemented, it is estimated that these rules will reduce mercury emissions 81% by 2018 and reduce NOx emissions 30% and SO2 emissions 75% by 2015.
The Illinois EPA proposed rules for mercury that are significantly stricter than the federal rules. Illinois has also proposed Clean Air Interstate Rule program rules for NOx that are more stringent than the federal program’s. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement on Illinois’ mercury regulations. Under the agreement, Illinois generators may delay the compliance date for mercury reductions in exchange for accelerated installation of NOx and SO2 controls. The agreement with the Illinois EPA also restricts purchasing SO2 and NOx emission allowances to meet specific allowed emission rates set forth in the agreement. The Joint Committee on Administrative Review approved the Illinois mercury regulations in December 2006, and the Illinois Pollution Control Board issued a final order adopting the mercury regulations in late December 2006. The final rule was published in the Illinois Register in January 2007. The rule will also need to be approved by the EPA. When they are fully implemented, it is estimated that these rules will reduce mercury emissions 90%, NOx emissions 50% and SO2 emissions 70% by 2015.
The table below presents estimated capital costs based on current technology to comply with both (1) the federal Clean Air Interstate Rule and Clean Air Mercury Rule through 2016, and (2) Illinois’ mercury regulations pursuant to the agreement described above. 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 credits 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 by June 2007 and the federal fine particulate ambient standard by April 2008. The costs in the table assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet this new standard in the St. Louis region. Should Missouri develop an alternative plan to comply with this standard, the cost impact could be material to UE. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for ozone and fine particulate. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.
Emission Credits
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program 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 tons of SO2 and NOx emission allowances held and the related SO2 and NOx book values that are carried as intangible assets as of December 31, 2006.
(a)
Vintages are from 2006 to 2016. Each company possesses additional allowances for use in periods beyond 2016. Units are in millions of SO2 allowances (currently one allowance equals one ton emitted).
(b)
Vintages are from 2006 to 2008. Units are in NOx allowances (one allowance equals one ton emitted).
(c)
Includes value assigned to AERG and EEI allowances as a result of purchase accounting of $78 million.
The following table presents the distribution by company and year of the NOx emission allowances that were allocated by the Illinois EPA on September 12, 2006, for 2007 and 2008.
(a)
These NOx allowances are included in the total allowances table above. Units are in NOx allowances (one allowance equals one ton emitted).
Allocations of NOx allowances for UE’s Missouri generating facilities will be 10,178 tons per emissions season in 2007 and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. New 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 requiring a change in the way Acid Rain Program allowances are 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 be surrendered at a ratio of two allowances for every ton of emission in 2010 through 2014. Beginning in 2015, the Clean Air Interstate Rule program will require SO2 allowances to be surrendered at a ratio of 2.86 allowances for every ton of emission.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming are the subjects of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Coal-fired power plants are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity from the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including enhanced generation at our nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.
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 carbon dioxide within deep unused coal seams, mature oil fields, and saline reservoirs.
The impact of future initiatives related to greenhouse gas emissions and global warming on us are unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal 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 under the Clean Water Act rules that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts. These rules pertain to 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. We estimate our compliance costs associated with conducting field studies and installing fish collection systems to determine the aquatic impact of our intake structures to be $3 million to $4 million dollars over the next three to four years. These studies will determine what, if any, additional technology must be applied at nine of our existing power plants. On January 25, 2007, the federal Second Circuit Court of Appeals remanded many provisions of these rules to EPA for revision. Until 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 2008.
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 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. The information request required Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. These information requests are being complied with, but we cannot predict the outcome of this matter.
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, 2006, CIPS, CILCO and IP owned or were otherwise responsible for 14, four, and 25 former MGP sites, respectively, in Illinois. 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 their former MGP sites in Illinois from their 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, 2006, CIPS, CILCO and IP had recorded liabilities of $25 million, $3 million and $66 million, respectively, to represent estimated minimum obligations.
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 3 - 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. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site, and the environmental risk) and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. As of December 31, 2006, UE had recorded $8 million to represent its estimated minimum obligation for its MGP sites. 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, 2006, UE had recorded $5 million to represent its estimated minimum obligation for these sites. 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 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 used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.
In October 2002, UE was included in a Unilateral Administrative Order issued by the EPA listing potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Solutia’s former chemical waste landfill and the resulting impact area in the Mississippi River. UE was asked to participate in response activities that involve the installation of a barrier wall around a chemical waste site and three recovery wells to divert groundwater flow. The projected cost for this remedy method is $25 million to $30 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requesting its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection; it is now seeking to discharge its environmental liabilities. In March 2004, Pharmacia Corporation, the former parent company of Solutia, confirmed its intent to comply with the EPA’s Unilateral Administrative Order.
The status of future remediation at Sauget Area 2 and compliance with the Unilateral Administrative Order is
uncertain, so we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity. Site investigation activities have been performed pursuant to the oversight of the EPA and are largely concluded. In December 2004, the U.S. Supreme Court, in Cooper Industries, Inc., vs. Aviall Services, Inc., limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, it is possible that UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders. Any liability or responsibility that may be imposed on UE as a result of this Sauget, Illinois, environmental matter was not transferred to CIPS as a part of UE’s May 2005 Illinois utility service territory transfer to CIPS.
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 $4 million at December 31, 2006, 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 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.
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. At the FERC’s direction, outside experts were hired by UE to review the cause of the incident. Their reports and reports by FERC staff indicated design, construction, and human error as causes of the breach. In their report, UE’s outside experts concluded that restoration of the upper reservoir, if undertaken, will require a complete rebuild of the entire dam with a completely different design concept, not simply a repair of the breached area. FERC agreed with this conclusion and rejected repair as an option.
The FERC investigation of the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation that the FERC’s Office of Enforcement conducted into alleged violations of license conditions and FERC regulations by UE as the licensee of the Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply with a new dam safety program developed in connection with the settlement.
In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk Plant, assuming successful resolution of outstanding issues with authorities of the state of Missouri. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer.
UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all damages and liabilities (but not penalties) caused by the breach, plus the cost of rebuilding the plant, will be covered by insurance. UE expects the total cost for clean up, damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $131 million to $151 million. As of December 31, 2006, UE had paid $65 million and accrued a $66 million liability, including costs resulting from the FERC stipulation and consent discussed above, while expensing $30 million and recording a $101 million receivable due from insurance companies. As of December 31, 2006, UE has received $16 million from insurance companies, which reduces the insurance receivable balance to $85 million. As of December 31, 2006, UE had a $10 million receivable due from insurance companies related to rebuilding the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.
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 in St. Louis, alleges negligence, violations of the Missouri Clean Water Act and various other statutory and common law claims. The business owners’ suit, which was filed in the Missouri circuit court in Reynolds County, contains similar allegations and seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages. In January 2007, the Missouri Department of Natural Resources filed a petition to intervene as a plaintiff in the attorney general’s lawsuit.
Until the reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, a final decision about whether the plant will be rebuilt is made, and future regulatory treatment for the facility is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Waste Disposal
In July 2002, the Illinois Attorney General’s Office advised us that it would be commencing an enforcement action concerning an inactive waste disposal site near Coffeen, Illinois. This is the location of a disposal facility that is permitted by the Illinois EPA to receive fly ash from
Genco’s Coffeen power plant. The Illinois attorney general also notified the disposal facility’s current and former owners about the proposed enforcement action. The Attorney General’s Office advised us that it may initiate an action under CERCLA (Superfund) to recover past costs incurred at the site ($0.3 million) and to obtain a declaratory judgment as to liability for future costs. Neither Genco, the current owner of the Coffeen power plant, nor CIPS, the prior owner of the Coffeen power plant, owned or operated the disposal facility. We do not expect that this matter will have a material adverse effect on Ameren’s, CIPS’ or Genco’s results of operations, financial position, or liquidity.
Sustainable Energy Plan
In July 2005, the ICC entered a resolution affirming the Illinois governor’s Sustainable Energy Plan and an ICC staff report dated July 7, 2005. CIPS, CILCO and IP were asked to file documentation explaining how they intend to implement the plan. The Ameren Illinois Utilities continue to give consideration to this plan. The plan calls for, among other things, a renewable portfolio standard whereby 2% of the bundled retail load will be supplied by renewable energy resources in 2007, 3% in 2008, 4% in 2009, 5% in 2010, 6% in 2011, 7% in 2012, and 8% in 2013. It also sets an energy-efficiency portfolio standard whereby there will be a 10% reduction in projected annual load growth by 2007-2008, 15% by 2009 to 2011, 20% by 2012 to 2014, and 25% by 2015 to 2017.
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 185 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, 2006, the average number of parties is 68.
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 or CILCO has contractually agreed to indemnify Genco or AERG for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if awarded, typically would be shared among the named defendants.
From October 1, 2006, through December 31, 2006, four additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the circuit court of Madison County, Illinois. Two lawsuits were dismissed and seven were settled. The following table presents the status as of December 31, 2006, of the asbestos-related lawsuits that have been filed against the Ameren Companies:
(a)
Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants.
As of December 31, 2006, five 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.
The ICC order approving Ameren’s acquisition of IP effective September 30, 2004, also approved 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 will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.
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.
Regulation
Regulatory changes enacted and being considered at the federal and state levels continue to change the structure of the utility industry and utility regulation, as well as to encourage increased competition. At this time, we are unable to predict the impact of these changes on our future results of operations, financial position, or liquidity. See Note 3 - Rate and Regulatory Matters for further information.
NOTE 15 - 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. It is assumed that the Callaway nuclear plant site will be decommissioned based on immediate dismantlement method 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. 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 2006, 2005 and 2004. 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 a decommissioning cost estimate when the next study is conducted. 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 in 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.
NOTE 16 - 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, 2006 and 2005:
(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 15 - Callaway Nuclear Plant for further information. We have classified these investments in debt and equity securities as available for sale and have recorded all such investments at their fair market value at December 31, 2006 and 2005. Investments by the nuclear decommissioning trust fund are allocated 60% to 70% to equity securities, with the balance invested in fixed-income securities.
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, 2006, 2005 and 2004:
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, 2006 and 2005:
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, 2006:
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust funds. 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 licenses for our nuclear facilities expire. 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, aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2006:
NOTE 17 - SEGMENT INFORMATION
Prior to the third quarter of 2006, Ameren reported one segment, Utility Operations, which comprised electric generation and electric and gas transmission and distribution operations. Ameren holding company activity was listed in a category called Other. As a result of the following changes in circumstances, Ameren, UE, CILCORP and CILCO changed their segments in the third quarter of 2006:
•
the Ameren Companies’ chief operating decision-making group began to assess performance and to allocate resources based on a new segment structure, and the group made related organizational and management reporting changes in the third quarter of 2006;
•
electric generation deregulation in Illinois, which became effective January 1, 2007;
•
the expiration of affiliate power supply agreements for CIPS and CILCO and other supply agreements for IP on December 31, 2006;
•
the July 2006 termination of the JDA among UE, Genco and CIPS, effective December 31, 2006; and
•
the September 2006 completion of a statewide auction to procure power for CIPS, CILCO and IP for 2007 and beyond and Marketing Company’s sale in that auction of power being acquired from Genco and AERG.
In the third quarter of 2006, Ameren determined that it had 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 and other non-rate-regulated activities, which are included 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 primarily consists of the operations or activities of Genco, the
CILCORP parent company, AERG, EEI, and Marketing Company. Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company.
UE determined it had 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 determined they had two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO comprises 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. Other for CILCORP and CILCO comprises leveraged lease investments, parent company activity, and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.
Prior-period presentation has been adjusted for comparative purposes.
The following tables present information about the reported revenues and specified items included in net income of Ameren for the years ended December 31, 2006, 2005 and 2004, and total assets as of December 31, 2006, 2005 and 2004.
(a)
Represents net income available to common shareholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
(b)
Includes cumulative effect of change in accounting principal net of income taxes of $(22) for consolidated Ameren.
(c)
Elimination of UE’s CT purchases from Non-rate-regulated Generation.
(d)
Excludes amounts for IP prior to acquisition date of September 30, 2004.
The following tables present information about the reported revenues and specified items included in net income of UE for the years ended December 31, 2006, 2005 and 2004, and total assets as of December 31, 2006, 2005 and 2004.
(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, 2006, 2005 and 2004, and total assets as of December 31, 2006, 2005 and 2004.
(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, 2006, 2005 and 2004, and total assets as of December 31, 2006, 2005 and 2004.
(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)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
Only Ameren, as a “large accelerated filer” with respect to the reporting requirements of the Exchange Act, 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 2006 fiscal year. UE, CIPS, Genco, CILCORP, CILCO and IP are not accelerated filers. They were therefore not 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 2006 fiscal year.
(a)
Evaluation of Disclosure Controls and Procedures
As of December 31, 2006, 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
Ameren’s 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). Upon making that evaluation under the framework in Internal Control - Integrated Framework issued by the COSO, management concluded that Ameren’s internal control over financial reporting was effective as of December 31, 2006. Management’s assessment of the effectiveness of Ameren’s internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8.
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.
(c)
Change in Internal Controls
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 2006 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 and 407(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2007 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 2007 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’ 2007 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 committee to perform such committee functions for their boards of directors. This arrangement is permitted under exemptions provided in the NYSE listing standards for companies such as UE and CILCO, which list only preferred stock (nonconvertible and nonparticipating) on the NYSE. CIPS, Genco, CILCORP and IP 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 committee and Stephen F. Brauer, Susan S. Elliott, Richard A. Liddy, and Richard A. Lumpkin 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 and controller, 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 2007 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 2007 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’ 2007 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, 2006, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plan.
(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, 366,119 of the shares 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 2007 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 2007 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, 2007. 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, 2007, 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 DIRECTOR INDEPENDENCE.
Information required by Item 404 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2007 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 2007 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’ 2007 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 ACCOUNTING 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 2007 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 186.
(b)
Exhibits are listed in the Exhibit Index commencing on page 186.
CILCORP (Parent Company Only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2006
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 6 - 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 14 - 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, 2006
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 6 - 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 14 - 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.
(b)
Ameren 2004 amounts include financial activity of IP subsequent to the September 30, 2004, acquisition date. Amounts for IP include predecessor and successor financial information in 2004, the year of its acquisition.
(c)
Amount includes $6 million related to IP’s balance at the date of acquisition on September 30, 2004.
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.
Supplemental Information to be Furnished with Reports Filed
Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered
Securities Pursuant to Section 12 of the Act
No annual report, proxy statement, form of proxy or other proxy soliciting material has been sent to security holders of Illinois Power Company during the period covered by this Annual Report on Form 10-K for the fiscal year ended December 31, 2006.
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.