We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
Reference is made to Note 1 – Summary of Significant Accounting Policies, Note 3 – Rate and Regulatory Matters, Note 13 – Related Party Transactions, and Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters and Note 7 – Related Party Transactions in this report.
The following table presents insurance coverage at UE’s Callaway nuclear plant at June 30, 2007. The property coverage was renewed on October 1, 2006. The nuclear liability coverage anniversary was January 1, 2007.
Price-Anderson limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. 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.
Subsequent to the terrorist attacks on September 11, 2001, both American Nuclear Insurers and Nuclear Electric Insurance Ltd. confirmed that terrorist attacks would be covered under their policies, subject to applicable policy limits. Both companies, however, revised their policy terms to include an industry aggregate for all “non-certified” terrorist acts as defined by the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The non-certified American Nuclear Insurers nuclear liability cap is a $300 million shared industry aggregate during the policy period. The aggregate for all Nuclear Electric Insurance Ltd. policies which apply to non-certified property claims within a 12-month period is $3.2 billion, plus any amounts available through reinsurance or indemnity from an outside source.
If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident occurred, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.
As of June 30, 2007, the commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2006. The following table presents the total estimated natural gas purchase commitments at June 30, 2007:
As of June 30, 2007, the commitments for the procurement of nuclear fuel have materially changed from amounts previously disclosed as of December 31, 2006. The following table presents the total estimated nuclear fuel purchase commitments at June 30, 2007:
At this time, UE does not expect to require new baseload generation capacity until at least 2018. However, due to the significant time required to plan, acquire permits for and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. During the three months ended June 30, 2007, UE entered into a commitment to purchase heavy forgings needed to construct a nuclear plant. This commitment does not mean a decision has been made to build a nuclear plant. The purpose of entering into the forgings purchase commitment was to secure access to heavy forgings, which are long lead-time materials, in the event that UE decides to build a nuclear plant. As of June 30, 2007, UE’s commitments to purchase heavy forgings totaled $88 million through 2010 ($3.5 million in 2007, $6.5 million in 2008, $7.5 million in 2009 and $70.5 million in 2010).
As part of the electric settlement agreement in Illinois, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock-in prices for 400 to 1,000 megawatts annually of their baseload power requirements from 2008 to 2012 at relevant market prices. These contracts have been executed but are not effective until enactment of Proposed Legislation by the Illinois governor. See Note 2 – Rate and Regulatory Matters for information on the electric agreement in Illinois.
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, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, 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.
Illinois and Missouri must also develop attainment plans to meet the federal eight-hour ozone ambient standard, the federal fine particulate ambient standard and the Clean Air Visibility rule. Both states have filed ozone attainment plans for the St. Louis area. The state attainment plans for fine particulate must be submitted to the EPA by April 2008 and the plans for the Clean Air Visibility rule must be submitted to the EPA by December 2007. 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.
As part of the electric agreement in Illinois that is subject to enactment of Proposed Legislation, a minimum percentage of CIPS’, CILCO’s and IP’s total supply to serve the load of eligible retail customers to be procured in each of the following years would be committed to being generated from renewable energy resources, subject to limits on customer rate impacts:
To the extent available, at least 75% of the renewable energy should come from wind generation according to the agreement. A provision for full and timely cost recovery of the cost of the commitments is also included in the agreement. We are in the process of determining our compliance plans. See Note 2 – Rate and Regulatory Matters for information on the electric settlement agreement in Illinois.
Missouri has enacted voluntary goals for total power to be supplied from renewable energy sources while the federal government continues to consider mandatory thresholds.
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
In April 2007, the U.S. Supreme Court issued a decision that determined that the EPA has authority to regulate carbon dioxide and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” Unless the U.S. Congress enacts legislation directing otherwise, the EPA could begin to regulate such emissions.
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.
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 June 30, 2007, 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 June 30, 2007, CIPS, CILCO and IP had recorded liabilities of $25 million, $5 million and $78 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. 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 June 30, 2007, UE had recorded $6 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 June 30, 2007, UE had recorded $4 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, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties (PRPs) to evaluate the extent of potential contamination with respect to Sauget Area 2.
Sauget Area 2 investigation activities under the oversight of the EPA are largely completed and will be submitted to the EPA by the end of 2007. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement the selected alternative. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities of Solutia related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection.
In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $4 million at June 30, 2007, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.
In addition, our operations, or those of our predecessor companies, involve the use, disposal 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.
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.
damages and liabilities (but not penalties) caused by the breach, plus the cost of rebuilding the plant, will be covered by insurance. Based on recent settlement discussions, 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 $182 million to $202 million. As of June 30, 2007, UE had paid $82 million and accrued a $100 million liability, including costs resulting from the FERC-approved stipulation and consent agreement discussed above, while expensing $31 million and recording a $151 million receivable due from insurance companies. As of June 30, 2007, UE has received $35 million from insurance companies, which reduced the insurance receivable balance to $116 million. As of June 30, 2007, UE had a $27 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.
As of June 30, 2007, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.
IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms.
Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered
by IP from a $20 million trust fund established by IP 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.
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.
UE, CIPS, Genco, CILCORP, CILCO, IP and EEI are participants in Ameren’s plans and 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 three months and six months ended June 30, 2007 and 2006:
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 – Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI 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 has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 – Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI and other non-rate-regulated activities, which are included in Other.
The following table presents information about the reported revenues and net income of Ameren for the three months and six months ended June 30, 2007 and 2006, and total assets as of June 30, 2007 and December 31, 2006.
The following table presents information about the reported revenues and net income of UE for the three months and six months ended June 30, 2007 and 2006, and total assets as of June 30, 2007 and December 31, 2006.
The following table presents information about the reported revenues and net income of CILCORP for the three months and six months ended June 30, 2007 and 2006, and total assets as of June 30, 2007 and December 31, 2006.
The following table presents information about the reported revenues and net income of CILCO for the three months and six months ended June 30, 2007 and 2006, and total assets as of June 30, 2007 and December 31, 2006.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Ameren’s earnings in the second quarter and first half of 2007 were favorably affected by higher electric margins in its non-rate-regulated electric generation business segment due to the replacement of below-market power sales contracts that expired in 2006. Those contracts were replaced with higher-priced, market-based contracts in 2007. Electric and gas margins in the first half of 2007 in Ameren’s Missouri and Illinois rate-regulated business segments benefited from greater cooling and heating demand caused by favorable weather conditions. The earnings impact of higher power sales contract prices and favorable weather was reduced by a planned maintenance and refueling outage at UE’s Callaway nuclear plant in the second quarter of 2007, higher fuel costs and increased costs of operating and investing in Ameren’s Missouri and Illinois rate regulated segments, among other things.
Ameren’s earnings in the first half of 2007 were reduced by $19 million (after taxes), or 9 cents per share, as a result of the cost of restoration efforts associated with severe January 2007 storms. Storm-related costs in the first half of 2006 reduced net income by an estimated $6 million (after taxes), or 3 cents per share. In addition, costs related to participation in the MISO Day Two Energy Market were $10 million (after taxes), or 5 cents per share, higher in the first half of 2007 over the same period in 2006 because of a March 2007 FERC order that reallocated such costs among market participants retroactive to 2005. Ameren’s net income in the first quarter of 2007 benefited from the reversal of a $10 million charge (after taxes), or
5 cents per share, originally recorded in 2006 related to funding for low-income energy assistance and energy efficiency programs in Illinois. These commitments were terminated in the first quarter of 2007 as a result of credit rating downgrades resulting from Illinois legislative actions during that period.
In March and June 2007, final rate orders were received from the MoPSC for pending UE gas and electric rate cases, respectively. Unfortunately, these cases, which included important and complex issues, were litigated during a time when UE faced a very challenging environment as a result of unprecedented storms in 2006 and early 2007, and the breach of the upper reservoir of the Taum Sauk pumped-storage hydroelectric facility. Consequently, the results of UE’s Missouri electric rate case were mixed. UE was successful on some major issues, such as the treatment of the expiration of the cost-based EEI power supply contract and the full inclusion of millions of dollars of investment in peaking generation assets in rate base. However, the MoPSC denied UE’s request to implement a fuel and purchased power cost recovery mechanism, extended the period over which UE will recover the investments in its generation fleet and provided a below-normal return on equity. Consequently, the cash flows and returns on equity in the Missouri Regulated segment and at UE, at least in the interim, will be below where Ameren and UE believe they should be. With increasing fuel and purchased power costs, and lacking a pass-through mechanism, coupled with increased capital and operations and maintenance expenditures on UE’s distribution system reliability, UE expects to be entering a period where more frequent rate case filings will be necessary.
In Illinois, last fall the Ameren Illinois Utilities received an electric delivery service rate order from the ICC. The related rehearing process was completed this spring. The results of these rate cases did not provide the ability to recover the current level of operating expenses. With cost disallowances and the cost of service in these cases basically based on 2004 cost levels, the return on equity for the Ameren Illinois Utilities are expected to be less than 5% in 2007, which does not include the costs of the settlement, discussed below, that will not be recoverable from ratepayers. As a result of these expected low returns, the Ameren Illinois Utilities plan to file additional delivery service rate cases by the end of this year. The environment in which these cases were litigated was challenging because the issues with the transition to new rates in Illinois were significant. In July 2007, a significant step was taken towards resolving the transition issues with the constructive settlement on electric rate issues among key stakeholders in Illinois. An approximately $1-billion state-wide rate relief package is expected to be funded by contributions of $150 million from Ameren-affiliated companies and $851 million from other electric utilities and generating companies. Ameren expects earnings per share would be reduced by approximately 26, 11, 7 and 1 cents per share in 2007, 2008, 2009 and 2010, respectively, should legislation passed by the Illinois General Assembly in late July be signed by the governor of Illinois. The Illinois settlement is a solution that Ameren believes provides significant benefits to the Ameren Illinois Utilities’ customers, and addresses key stakeholders’ concerns about how power is to be procured in Illinois in the future. Ameren believes the solution also provides legislative,
regulatory and legal certainty, and a viable competitive market in Illinois.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries, 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. Ameren’s principal subsidiaries are listed below.
| · | UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. |
| · | CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. |
| · | Genco operates a non-rate-regulated electric generation business. |
| · | CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG) in Illinois. |
| · | IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. |
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 period. All tabular dollar amounts are in millions, unless otherwise indicated.
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 2006 revenues were directly subject to state or federal regulation. This regulation can have a material impact on the price we charge for our services. 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 business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power recovery mechanisms for our Illinois electric delivery businesses. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, for a discussion of recently-decided rate cases and the comprehensive rate relief program and settlement agreement in Illinois. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Ameren’s net income increased to $143 million, or 69 cents per share, in the second quarter of 2007 from $123 million, or 60 cents per share, in the second quarter of 2006. Net income in the Non-rate-regulated Generation segment in the three months ended June 30, 2007, increased by $43 million from the prior-year period, while net earnings in the Missouri Regulated and Illinois Regulated segments declined by $12 million and $14 million, respectively.
Ameren’s net income increased to $266 million, or $1.29 per share, in the first six months of 2007 from $193 million, or 94 cents per share, in the first six months of 2006. Net income increased in the Illinois Regulated and Non-rate-regulated Generation segments by $6 million and $86 million, respectively, in the first half of 2007 compared to the prior-year period, while net income in the Missouri Regulated segment decreased by $24 million.
Earnings were favorably impacted in the second quarter and first six months of 2007 as compared with the same periods in 2006 by:
| · | higher margins in the Non-rate-regulated Generation segment due to the replacement of below-market |
| | power sales contracts, which expired in 2006, with higher-priced contracts; |
| · | favorable weather conditions; |
| · | the absence of costs in the current year periods that were incurred in the second quarter of the prior year related to the reservoir breach at UE’s Taum Sauk plant (5 cents per share); |
| · | higher delivery service rates on Illinois Regulated sales; |
| · | the lack of FERC fees related to UE’s Osage hydroelectric plant in the current year period that were incurred in the prior year period and the capitalization of fees, pursuant to a MoPSC order, in the current year period; and |
| · | lower emission allowance costs and other factors. |
Earnings were negatively impacted in the second quarter and first six months of 2007 as compared with the same periods in 2006 by:
| · | the cost of UE’s Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007 exceeding the cost of the unplanned outage at the Callaway plant in the second quarter of 2006 (9 cents per share); |
| · | increased fuel and transportation prices (5 cents per share and 8 cents per share, respectively); |
| · | higher labor and employee benefit costs (2 cents per share and 8 cents per share, respectively); |
| · | increased bad debt reserves (3 cents per share and 5 cents per share, respectively); |
| · | increased depreciation expense (2 cents per share and 7 cents per share, respectively); and |
| · | higher financing costs (4 cents per share and 8 cents per share, respectively). |
In addition to the above items affecting both periods, earnings were favorably impacted in the first six months of 2007 as compared with the first six months of 2006 by the reversal of an accrual originally recorded in 2006 in the Illinois Regulated segment for contributions to assist customers through the Illinois Customer-Elect electric rate increase phase-in plan
(5 cents per share). The commitment to make these contributions was terminated in 2007 as a result of credit rating agency downgrades resulting from Illinois legislative actions.
In addition to the above items affecting both periods, earnings were negatively impacted in the first six months of 2007 as compared with the first six months of 2006 by costs associated with electric outages caused by a severe ice storm in January 2007 (9 cents per share) and by a FERC order in March 2007 that reallocated costs related to participation in the MISO Day Two Energy Market among market participants retroactive to 2005 (5 cents per share).
An increase in the number of common shares outstanding reduced Ameren’s earnings per share in the 2007 periods compared with the 2006 periods. Per share information presented above is based on average shares outstanding in 2006.
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 three months and six months ended June 30, 2007 and 2006:
| | | | | | |
| | Three Months | | | Six Months | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| Net income (loss): | | | | | | | | | | | |
UE(a) | $ | 79 | | | $ | 90 | | | $ | 116 | | | $ | 140 | |
| CIPS | | 5 | | | | 15 | | | | 15 | | | | 13 | |
| Genco | | 17 | | | | 2 | | | | 60 | | | | 8 | |
| CILCORP | | 12 | | | | 1 | | | | 32 | | | | 9 | |
| IP | | 7 | | | | 16 | | | | 19 | | | | 19 | |
Other(b) | | 23 | | | | (1 | ) | | | 24 | | | | 4 | |
| Ameren net income | $ | 143 | | | $ | 123 | | | $ | 266 | | | $ | 193 | |
| (a) | Includes earnings from a non-rate-regulated 40% interest in EEI. |
| (b) | Includes earnings from non-rate-regulated operations and a 40% interest in EEI held by Development Company, corporate general and administrative expenses, and intercompany eliminations. |
Below is a table of income statement components by segment for the three months and six months ended June 30, 2007 and 2006:
| | | | | | | | | | | | | | | |
| | Missouri Regulated | | | Illinois Regulated | | | Non-rate-regulated Generation | | | Other / Intersegment Eliminations | | | Total | |
Three Months 2007: | | | | | | | | | | | | | | |
| Electric margin | $ | 494 | | | $ | 207 | | | $ | 251 | | | $ | (15 | ) | | $ | 937 | |
| Gas margin | | 14 | | | | 64 | | | | - | | | | (2 | ) | | | 76 | |
| Other revenues | | (1 | ) | | | (1 | ) | | | - | | | | 2 | | | | - | |
| Other operations and maintenance | | (223 | ) | | | (130 | ) | | | (92 | ) | | | 19 | | | | (426 | ) |
| Depreciation and amortization | | (84 | ) | | | (53 | ) | | | (27 | ) | | | (5 | ) | | | (169 | ) |
| Taxes other than income taxes | | (60 | ) | | | (30 | ) | | | (6 | ) | | | - | | | | (96 | ) |
| Other income and (expenses) | | 9 | | | | 6 | | | | 1 | | | | - | | | | 16 | |
| Interest expense | | (51 | ) | | | (32 | ) | | | (28 | ) | | | 3 | | | | (108 | ) |
| Income taxes | | (30 | ) | | | (11 | ) | | | (37 | ) | | | - | | | | (78 | ) |
| Minority interest and preferred dividends | | (2 | ) | | | (1 | ) | | | (6 | ) | | | - | | | | (9 | ) |
| Net income | $ | 66 | | | $ | 19 | | | $ | 56 | | | $ | 2 | | | $ | 143 | |
Three Months 2006: | | | | | | | | | | | | | | | | | | | |
| Electric margin | $ | 496 | | | $ | 209 | | | $ | 165 | | | $ | (16 | ) | | | 854 | |
| Gas margin | | 10 | | | | 60 | | | | - | | | | (2 | ) | | | 68 | |
| Other revenues | | - | | | | (1 | ) | | | - | | | | 1 | | | | - | |
| Other operations and maintenance | | (196 | ) | | | (124 | ) | | | (82 | ) | | | 8 | | | | (394 | ) |
| Depreciation and amortization | | (81 | ) | | | (48 | ) | | | (27 | ) | | | (6 | ) | | | (162 | ) |
| Taxes other than income taxes | | (59 | ) | | | (27 | ) | | | (6 | ) | | | 2 | | | | (90 | ) |
| Other income and (expenses) | | 7 | | | | 4 | | | | 1 | | | | (2 | ) | | | 10 | |
| Interest expense | | (44 | ) | | | (22 | ) | | | (26 | ) | | | 5 | | | | (87 | ) |
| Income taxes | | (52 | ) | | | (17 | ) | | | (7 | ) | | | 8 | | | | (68 | ) |
| Minority interest and preferred dividends | | (3 | ) | | | (1 | ) | | | (5 | ) | | | 1 | | | | (8 | ) |
| Net income | $ | 78 | | | $ | 33 | | | $ | 13 | | | $ | (1 | ) | | $ | 123 | |
Six Months 2007: | | | | | | | | | | | | | | | | | | | |
| Electric margin | $ | 909 | | | $ | 379 | | | $ | 501 | | | $ | (30 | ) | | $ | 1,759 | |
| Gas margin | | 41 | | | | 179 | | | | - | | | | (4 | ) | | | 216 | |
| Other revenues | | - | | | | 1 | | | | - | | | | (1 | ) | | | - | |
| Other operations and maintenance | | (446 | ) | | | (256 | ) | | | (160 | ) | | | 40 | | | | (822 | ) |
| Depreciation and amortization | | (171 | ) | | | (108 | ) | | | (54 | ) | | | (12 | ) | | | (345 | ) |
| Taxes other than income taxes | | (117 | ) | | | (66 | ) | | | (14 | ) | | | (1 | ) | | | (198 | ) |
| Other income and (expenses) | | 16 | | | | 10 | | | | 2 | | | | 2 | | | | 30 | |
| Interest expense | | (97 | ) | | | (61 | ) | | | (53 | ) | | | 5 | | | | (206 | ) |
| Income taxes | | (43 | ) | | | (27 | ) | | | (83 | ) | | | 4 | | | | (149 | ) |
| Minority interest and preferred dividends | | (3 | ) | | | (3 | ) | | | (13 | ) | | | - | | | | (19 | ) |
| Net income | $ | 89 | | | $ | 48 | | | $ | 126 | | | $ | 3 | | | $ | 266 | |
Six Months 2006: | | | | | | | | | | | | | | | | | | | |
| Electric margin | $ | 870 | | | $ | 349 | | | $ | 349 | | | $ | (28 | ) | | | 1,540 | |
| Gas margin | | 35 | | | | 170 | | | | - | | | | (1 | ) | | | 204 | |
| Other revenues | | 1 | | | | (1 | ) | | | - | | | | - | | | | - | |
| Other operations and maintenance | | (367 | ) | | | (248 | ) | | | (151 | ) | | | 20 | | | | (746 | ) |
| Depreciation and amortization | | (161 | ) | | | (95 | ) | | | (53 | ) | | | (14 | ) | | | (323 | ) |
| Taxes other than income taxes | | (118 | ) | | | (70 | ) | | | (14 | ) | | | (1 | ) | | | (203 | ) |
| Other income and (expenses) | | 9 | | | | 6 | | | | 1 | | | | (1 | ) | | | 15 | |
| Interest expense | | (80 | ) | | | (45 | ) | | | (51 | ) | | | 12 | | | | (164 | ) |
| Income taxes | | (72 | ) | | | (21 | ) | | | (29 | ) | | | 10 | | | | (112 | ) |
| Minority interest and preferred dividends | | (4 | ) | | | (3 | ) | | | (12 | ) | | | 1 | | | | (18 | ) |
| Net income | $ | 113 | | | $ | 42 | | | $ | 40 | | | $ | (2 | ) | | $ | 193 | |
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three months and six months ended June 30, 2007, compared with the same periods in 2006. 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. 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 may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
| | | | | | | | | | | | | | | | | | | | | |
Three Months | Ameren(a) | | | UE | | | CIPS | | | Genco | | | CILCORP | | | CILCO | | | IP | |
| Electric revenue change: | | | | | | | | | | | | | | | | | | | | |
| Effect of weather (estimate) | $ | 28 | | | $ | 14 | | | $ | 6 | | | $ | - | | | $ | 2 | | | $ | 2 | | | $ | 6 | |
Interchange revenues- affiliated(b) | | - | | | | (49 | ) | | | - | | | | (28 | ) | | | - | | | | - | | | | - | |
| Interchange revenues- other | | 31 | | | | 31 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Other (estimate) | | 77 | | | | (15 | ) | | | 6 | | | | (25 | ) | | | 62 | | | | 62 | | | | 3 | |
| Total | $ | 136 | | | $ | (19 | ) | | $ | 12 | | | $ | (53 | ) | | $ | 64 | | | $ | 64 | | | $ | 9 | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation and other | $ | 2 | | | $ | 3 | | | $ | - | | | $ | (14 | ) | | $ | 11 | | | $ | 12 | | | $ | - | |
Emission allowance costs | | 6 | | | | 2 | | | | - | | | | 1 | | | | 5 | | | | 2 | | | | - | |
Price | | (24 | ) | | | (24 | ) | | | - | | | | - | | | | (1 | ) | | | (1 | ) | | | - | |
| Purchased power | | (37 | ) | | | 39 | | | | (14 | ) | | | 90 | | | | (55 | ) | | | (55 | ) | | | (7 | ) |
| Total fuel and purchased power change | $ | (53 | ) | | $ | 20 | | | $ | (14 | ) | | $ | 77 | | | $ | (40 | ) | | $ | (42 | ) | | $ | (7 | ) |
Net change in electric margins | $ | 83 | | | $ | 1 | | | $ | (2 | ) | | $ | 24 | | | $ | 24 | | | $ | 22 | | | $ | 2 | |
Net change in gas margins | $ | 8 | | | $ | 4 | | | $ | 1 | | | $ | - | | | $ | 2 | | | $ | 2 | | | $ | (2 | ) |
Six Months | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effect of weather (estimate) | $ | 46 | | | $ | 21 | | | $ | 11 | | | $ | - | | | $ | 6 | | | $ | 6 | | | $ | 8 | |
Interchange revenues- affiliated(b) | | - | | | | (121 | ) | | | - | | | | (46 | ) | | | - | | | | - | | | | - | |
| Interchange revenues- other | | 92 | | | | 92 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Other (estimate) | | 245 | | | | (5 | ) | | | 52 | | | | (11 | ) | | | 141 | | | | 141 | | | | 31 | |
| Total | $ | 383 | | | $ | (13 | ) | | $ | 63 | | | $ | (57 | ) | | $ | 147 | | | $ | 147 | | | $ | 39 | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel: | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation and other | $ | (7 | ) | | $ | 11 | | | $ | - | | | $ | (29 | ) | | $ | 13 | | | $ | 14 | | | $ | - | |
Emission allowance costs | | 22 | | | | 5 | | | | - | | | | 6 | | | | 9 | | | | 6 | | | | - | |
Price | | (42 | ) | | | (35 | ) | | | - | | | | (2 | ) | | | (6 | ) | | | (6 | ) | | | - | |
| Purchased power | | (137 | ) | | | 73 | | | | (47 | ) | | | 165 | | | | (125 | ) | | | (125 | ) | | | (19 | ) |
| Total fuel and purchased power change | $ | (164 | ) | | $ | 54 | | | $ | (47 | ) | | $ | 140 | | | $ | (109 | ) | | $ | (111 | ) | | $ | (19 | ) |
Net change in electric margins | $ | 219 | | | $ | 41 | | | $ | 16 | | | $ | 83 | | | $ | 38 | | | $ | 36 | | | $ | 20 | |
Net change in gas margins | $ | 12 | | | $ | 6 | | | $ | 3 | | | $ | - | | | $ | 3 | | | $ | 3 | | | $ | - | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | Includes revenues from sales transferred between UE and Genco under the former JDA, which terminated on December 31, 2006. |
Ameren
Ameren’s electric margin increased by $83 million and $219 million, for the three months and six months ended June 30, 2007, compared with the same periods in 2006. The following items had a favorable impact on electric margins for the second quarter and first six months of 2007 as compared to the year-ago periods:
| · | Non-rate-regulated Generation selling more power at market-based prices in the second quarter and first six months of 2007 compared with sales under below market-based power supply agreements, which expired on December 31, 2006; |
| · | Illinois electric delivery service rate increases which commenced January 2, 2007; |
| · | emission allowance costs were $6 million and $22 million lower, for the three months and six months ended June 30, 2007, respectively; |
| · | favorable weather conditions increased electric margins by $13 million and $22 million for the three months and six months ended June 30, 2007; |
| · | MISO costs were $8 million lower for the quarter compared with the same period in 2006; |
| · | return to normal rainfall levels, which increased hydroelectric generation; |
| · | the lack of $6 million in fees levied by FERC in the first quarter of 2006 upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant and the subsequent May 2007 MoPSC rate order that directed AmerenUE to transfer $4 million of the total fees to an asset account, which will be amortized over 25 years; |
| · | UE’s electric rate increase that went into effect June 4, 2007; and |
| · | storm-related outages in the second quarter of 2006 that decreased interchange margin by $3 million. |
The following items had an unfavorable impact on electric margins for the second quarter and first six months of 2007 as compared to the year-ago periods:
| · | an 11% increase in coal and related transportation prices for both the second quarter and the first six months of 2007; |
| · | MISO costs were $13 million higher for the six months ended June 30, 2007, compared with the same period in 2006. Costs related to participation in the MISO Day Two Energy Market were higher for the year because of a March 2007 FERC order that reallocated costs related to participation in the MISO Day Two Energy Market among market participants retroactive to 2005; |
| · | elimination of bundled power and delivery service tariffs in Illinois Regulated operations; and |
| · | reduced power plant availability, primarily at UE’s and AERG’s plants. |
Ameren’s gas margin increased by $8 million, or 12%, and $12 million, or 6%, for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006 primarily because of favorable weather conditions as was evidenced by a 38% and 16% increase in heating degree-days for the three months and six months ended June 30, 2007, respectively.
Missouri Regulated
UE
UE’s electric margin increased $1 million for the three months ended and $41 million for the six months ended June 30, 2007, compared to the same periods in 2006. The increase in the six month period was primarily due to:
| · | an increase in margins on interchange sales primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated under the JDA at cost, in the spot market at higher market prices; |
| · | the lack of $6 million in fees levied by FERC in the first quarter of 2006 upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant and the subsequent June 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which will be amortized over 25 years; |
| · | return to normal rainfall levels, which increased hydroelectric generation; |
| · | increased electric rates as approved by the MoPSC effective June 4, 2007; |
| · | favorable weather conditions which increased electric margin by $10 million and $13 million for the three months and six months ended June 30, 2007, respectively; |
| · | MISO costs, excluding the March 2007 FERC order, discussed below, were $4 million lower for the second quarter and $17 million lower for the six months ended June 30, 2007, compared to the same periods in 2006; and |
| · | spring storm-related outages in the second quarter of 2006, which reduced 2006 electric margins by $3 million. |
Factors that had an unfavorable impact on electric margin for the three months and six months ended June 30, 2007, as compared to the same periods in the prior year were as follows:
| · | reduced power plant availability because of planned maintenance activities; |
| · | the 38-day planned refueling and maintenance outage at the Callaway nuclear plant in the second quarter of 2007, which was offset by the unplanned outage that occurred at the Callaway nuclear plant during the second quarter of 2006; |
| · | a 14% increase in coal and related transportation prices; and |
| · | MISO costs were $11 million higher for the six months ended June 30, 2007, compared to the same period in 2006, due to the March 2007 FERC order. |
UE’s gas margin increased by $4 million and $6 million for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006 primarily because of favorable weather conditions as evidenced by a 62% and 16% increase in heating degree-days for the three months and six months ended June 30, 2007, respectively. The impact of the gas rate increase, as approved by the MoPSC effective April 1, 2007, was minimal in the second quarter.
Illinois Regulated
Illinois Regulated’s electric margin declined by $2 million during the second quarter, but increased $30 million for the six months ended June 30, 2007, compared with the same periods in 2006. Illinois Regulated’s gas margin increased by $4 million, or 7%, and $9 million, or 5%, for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006.
CIPS
CIPS’ electric margin decreased by $2 million, or 3%, for the three months ended June 30, 2007, but increased $16 million, or 14%, for the six months ended June 30, 2007, compared to the same periods in 2006. The increase in electric margin for the six-month period was primarily because of the combined effect of the elimination of bundled tariffs, including below-average seasonal rates, the expiration of below-market power supply contracts, and the January 1, 2007, implementation of delivery service tariffs and the pass-through of purchased power costs and favorable weather conditions that increased electric margins for the six months ended June 30, 2007 by $4 million.
CIPS’ electric margin for the six months ended June 30, 2007, was reduced by $4 million because of a March 2007 FERC order that reallocated costs among market participants retroactive to 2005.
CIPS’ gas margin increased by $1 million, or 7%, and $3 million, or 8%, for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006 primarily because of favorable weather conditions as evidenced by a 16% increase in year-to-date heating degree-days compared to the first six months of 2006.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for the three months and six months ended June 30, 2007, as compared with the same periods in 2006:
| | | | | | |
| | Three Months | | | Six Months | |
| CILCO (Illinois Regulated) | $ | (1 | ) | | $ | (5 | ) |
| CILCO (AERG) | | 23 | | | | 41 | |
| Total change in electric margin | $ | 22 | | | $ | 36 | |
CILCO’s (Illinois Regulated) electric margin decreased by $1 million, or 3%, and $5 million, or 7%, for the three months and six months ended June 30, 2007, respectively, compared to the same periods in 2006. The margin decrease was a result of the combined effect of the elimination of bundled tariffs, including below-average seasonal rates, the expiration of below-market power supply contracts, and the January 1, 2007, implementation of delivery service tariffs and the pass-through of purchased power costs.
Year-to-date MISO costs increased $3 million because of the March 2007 FERC order noted above.
The decrease in electric margin was reduced by favorable weather conditions, which increased electric margin by $2 million for the six months ended June 30, 2007.
See Non-rate-regulated Generation below for a detailed explanation of CILCO’s (AERG) change in electric margin for the three months and six months ended June 30, 2007, as compared with the same periods in 2006.
CILCO’s (Illinois Regulated) gas margin increased by $2 million and $3 million for the three months and six months ended June 30, 2007, respectively, compared to the same periods in 2006. Favorable weather conditions as evidenced by a 10% and 15% increase in heating degree-days for the second quarter and six months ended June 30, 2007, respectively, together with growth in the industrial sector were primarily responsible for the favorable impact.
IP
IP’s electric margin increased by $2 million, or 2%, and $20 million, or 12%, for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006 primarily because of the combined effect of the elimination of bundled tariffs, including below-average winter rates, the expiration of below-market power supply contracts, and the January 1, 2007, implementation of delivery service tariffs and the pass-through of purchased power costs. Favorable weather conditions also increased margin by $2 million for the six months ended June 30, 2007.
The March 2007 FERC order, referenced above, reduced IP’s electric margin by $12 million, in the first six months of 2007 as compared to the same period a year ago.
IP’s gas margin declined $2 million for the three months ended June 30, 2007, and was unchanged for the six months ended June 30, 2007, compared to the same periods in 2006, primarily because of favorable weather conditions as evidenced by a 35% and 15% increase in heating-degree days for the second quarter and six months ended June 30, 2007, respectively, partially offset by reduced transportation and other gas margins.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $86 million, or 52%, and $152 million, or 44%, for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006.
Genco
Genco’s electric margin increased by $24 million, or 27%, and $83 million, or 49%, for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006, primarily because of:
| · | selling power at market-based prices in the second quarter of 2007 compared with selling power at below-market prices pursuant to cost-based power supply agreements, which expired on December 31, 2006; |
| · | increased power plant availability due to reduced planned outages this year; |
| · | reduced emission allowance costs; and |
| · | lower MISO costs totaling $9 million for the six months ended June 30, 2007, compared to the first half of 2006, as a result of the March 2007 FERC order. |
Genco’s increase in electric margin was reduced by:
| · | the loss of margins on sales supplied with power acquired through the JDA; and |
| · | a 2% increase in coal and related transportation prices for the six months ended June 30, 2007 compared to the first half of 2006. |
CILCO (AERG)
For the three- and six-month periods ended June 30, 2007, AERG’s electric margin increased by $23 million, or 84%, and $41 million, or 65%, respectively, compared with the same periods in 2006 primarily because of:
| · | selling power at market-based prices in the second quarter of 2007 compared with sales under cost-based power supply agreements, which expired on December 31, 2006; and |
| · | reduced emission costs for both the second quarter and six months ended June 30, 2007, compared to the same prior year periods. |
The increase in electric margin was reduced by:
| · | a 16% increase in coal and related transportation prices for the six months ended June 30, 2007, compared to the first half of 2006; and |
| · | reduced plant availability because of planned extensive maintenance activities, which commenced in February 2007. |
EEI
EEI’s electric margins increased by $10 million and $8 million for the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006 primarily because of higher market prices and increased sales partially offset by an increase in coal and related transportation prices.
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Ameren
Three months - Other operations and maintenance expenses increased $32 million in the second quarter of 2007 compared with the second quarter of 2006 primarily because of
$35 million of maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007, which lasted 38 days. Refueling and maintenance outages occur approximately every 18 months and typically include fuel replacement, maintenance, and inspections. Additionally, higher non-Callaway labor costs, increased bad debt reserves and higher tree trimming expenditures resulted in increased other operations and maintenance expenses in the current year period. In the second quarter of 2006, Ameren recorded $10 million of costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant and $7 million of losses on the sale of noncore properties. The absence of such items in the current year period resulted in a reduction of the increase in other operations and maintenance expenses between periods.
Six months - Other operations and maintenance expenses increased $76 million in the first six months of 2007 compared with the first six months of 2006 primarily because of expenditures of $29 million related to a severe ice storm in January 2007 in UE’s and CIPS’ service territories and $35 million of maintenance and labor costs associated with the Callaway refueling and maintenance outage in the second quarter of 2007 as noted above. Higher non-Callaway labor costs and bad debt reserves also increased other operations and maintenance expenses in the first six months of 2007 compared to the prior-year period. Reducing the effect of these items was the absence of Taum Sauk costs and noncore property sale losses in the current year period, as noted above, and the reversal of an accrual of $15 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan.
Variations in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three months – Other operations and maintenance expenses increased $26 million in the second quarter of 2007 compared with the second quarter of 2006 primarily because of
$35 million of maintenance and labor costs associated with the Callaway refueling and maintenance outage in the second quarter of 2007, increased tree trimming expenditures, and insurance premiums paid to an affiliate for replacement power coverage. Reducing the effect of these items was the absence in the current year period of costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant.
Six months - Other operations and maintenance expenses increased $79 million in the first six months of 2007 compared with the first six months of 2006 primarily because of ice storm repair expenditures of $26 million, costs associated with the Callaway refueling and maintenance outage of $35 million, higher non-Callaway labor costs, and insurance premiums for replacement power coverage of $9 million paid to an affiliate. Reducing the effect of these items was the absence in the current year period of costs related to the Taum Sauk reservoir breach, as noted above.
Illinois Regulated
Other operations and maintenance expenses increased $6 million and $8 million in the Illinois Regulated segment in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006.
CIPS
Three months – Other operations and maintenance expenses were comparable between periods.
Six months - Other operations and maintenance expenses increased $8 million in the first six months of 2007 compared with the first six months of 2006 primarily because of storm repair expenditures of $3 million, higher labor costs and increased bad debt reserves as a result of the transition to higher electric rates in Illinois. The reversal of the customer assistance program accrual of $4 million established in 2006, as noted above, reduced the impact of these increases.
CILCO (Illinois Regulated)
Three months – Other operations and maintenance expenses were comparable between periods.
Six months - Other operations and maintenance expenses decreased $3 million in the first six months of 2007 compared with the first six months of 2006 primarily because of lower employee benefit costs and the reversal of the customer assistance program accrual of $3 million established in 2006, as noted above. Reducing the benefit of these items was an increase in bad debt reserves.
IP
Three months – Other operations and maintenance expenses increased $2 million in the second quarter of 2007 compared with the second quarter of 2006 primarily because of higher bad debt reserves.
Six months - Other operations and maintenance expenses were comparable between periods. The reversal of the customer assistance program accrual of $8 million established in 2006 as noted above, lower transmission and distribution expenses, and decreased injuries and damages reserves were offset by higher employee benefit costs and increased bad debt reserves.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $10 million and $9 million in the Non-rate-regulated Generation segment in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006.
Genco
Three months – Other operations and maintenance expenses were comparable between periods.
Six months - Other operations and maintenance expenses increased $4 million in the first six months of 2007 compared with the first six months of 2006 primarily because of higher labor costs.
CILCORP (Parent Company Only)
Three months – Other operations and maintenance expenses increased $4 million in the second quarter of 2007 compared with the second quarter of 2006 primarily because of higher employee benefit costs.
Six months - Other operations and maintenance expenses were comparable between periods as the absence of a write-off in 2007 as occurred in the prior year period of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP was offset by increased employee benefit costs in the current year period.
CILCO (AERG)
Three and six months - Other operations and maintenance expenses increased $2 million and $4 million, respectively, for the three months and six months ended June 30, 2007, as compared to the prior year periods primarily because of higher plant maintenance costs due to an extended scheduled plant outage.
EEI
Three months and six months - Other operations and maintenance expenses were comparable between periods.
Depreciation and Amortization
Ameren
Three and six months – Ameren’s depreciation and amortization expenses increased $7 million and $22 million in
the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006. The increases were primarily because of capital additions in 2006 and the start of amortization of a regulatory asset in 2007 associated with acquisition integration costs at IP, as required by an ICC order.
Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three and six months – Depreciation and amortization expenses increased $3 million and $10 million, respectively, in the three months and six months ended June 30, 2007, primarily because of capital additions in 2006, including CTs purchased in the second quarter of 2006, and storm-related expenditures in 2006.
Illinois Regulated
Depreciation and amortization expenses increased $5 million and $13 million in the Illinois Regulated segment in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006.
CIPS & CILCO (Illinois Regulated)
Three and six months - Depreciation and amortization expenses were comparable between periods.
IP
Three and six months – Depreciation and amortization expenses increased $5 million and $11 million, respectively, primarily because of amortization in 2007 of a regulatory asset associated with acquisition integration costs, as required by an ICC order.
Non-rate-regulated Generation
Three and six months - Depreciation and amortization expenses were comparable in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three months and six months ended June 30, 2007, compared with the same periods in 2006.
Taxes Other Than Income Taxes
Ameren
Three months – Ameren’s taxes other than income taxes increased $6 million in the second quarter of 2007 compared with the second quarter of 2006 primarily because of higher payroll taxes.
Six months - Ameren’s taxes other than income taxes decreased $5 million in the first six months of 2007 compared with the first six months of 2006 primarily because of lower gross receipts and property taxes.
Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three and six months – Taxes other than income taxes were comparable between periods.
Illinois Regulated
Taxes other than income taxes in Illinois Regulated were comparable in the second quarter of 2007 with the second quarter of 2006. Taxes other than income taxes decreased
$4 million in the six months ended June 30, 2007, compared with the same period in 2006.
CIPS
Three months – Taxes other than income taxes were comparable between periods.
Six months - Taxes other than income taxes decreased $3 million in the first six months of 2007 compared with the first six months of 2006 primarily because of lower property taxes and lower gross receipts taxes.
CILCO (Illinois Regulated) & IP
Three and six months – Taxes other than income taxes were comparable between periods.
Non-rate-regulated Generation
Three and six months - Taxes other than income taxes were comparable in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three months and six months
ended June 30, 2007, compared with the same periods in 2006.
Other Income and Expenses
Ameren
Three and six months – Miscellaneous income increased $9 million and $18 million in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006, primarily as a result of increased interest income. Miscellaneous income in each period includes interest income on industrial development revenue bonds acquired by UE in conjunction with its purchase of CTs. These amounts are offset by an equivalent amount of interest expense associated with capital leases for the CTs recorded in interest charges on Ameren’s and UE’s statements of income. Miscellaneous expense increased $3 million in both the three- and six-month periods ended June 30, 2007, compared with the same periods in 2006 as discussed below.
Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three and six months – Miscellaneous income increased $4 million and $8 million for the three months and six months ended June 30, 2007, compared with the same periods in 2006, primarily as a result of increased interest income. As discussed above, miscellaneous income includes interest income related to industrial revenue bonds that is offset in interest charges on UE’s statement of income. Miscellaneous expense increased $4 million in both the three months and six months ended June 30, 2007, compared with the same periods in 2006, as a result of expenses related to UE’s electric rate case.
Illinois Regulated
Miscellaneous income increased $2 million and $3 million in the Illinois Regulated segment in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006. Miscellaneous expense was comparable between periods.
CIPS & CILCO (Illinois Regulated)
Three and six months - Other income and expenses were comparable between periods.
IP
Three and six months – Miscellaneous income increased $3 million and $4 million for the three months and six months ended June 30, 2007, compared with the same periods in 2006, primarily as a result of increased interest income. Miscellaneous expense was comparable between periods.
Non-rate-regulated Generation
Other income and expenses were comparable in the Non-rate-regulated Generation segment and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three months and six months ended June 30, 2007, compared with the same periods in 2006.
Interest
Ameren
Three and six months - Interest expense increased $21 million and $42 million in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and other items noted below. Interest expense recognized on UE’s capital leases associated with the purchase of CTs is offset by an equivalent amount of interest income recorded in other income and expenses on Ameren’s and UE’s statement of income. With the adoption of FIN 48, we also began to record interest amounts associated with uncertain tax positions as interest expense rather than income tax expense. These interest charges were $5 million and $7 million for the three months and six months ended June 30, 2007, respectively.
Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2007, compared with the same periods in 2006, were as follows:
Missouri Regulated
UE
Three and six months – Interest expense increased $7 million and $17 million for the three months and six months ended June 30, 2007, compared with the same periods in 2006 primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings. As discussed above, interest charges include interest expense related to capital leases that is offset in other income and expenses on UE’s statement of income. Interest expense recorded in conjunction with the adoption of FIN 48 was
$2 million and $3 million for the three months and six months ended June 30, 2007, respectively.
Illinois Regulated
Interest expense increased $10 million and $16 million in the Illinois Regulated segment in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006.
CIPS
Three and six months – Interest expense increased $2 million and $3 million for the three months and six months ended June 30, 2007, compared with the same periods in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
CILCO (Illinois Regulated)
Three and six months - Interest expense was comparable between periods.
IP
Three and six months – Interest expense increased $8 million and $12 million for the three months and six months ended June 30, 2007, compared with the same periods in 2006, primarily because of the issuance of $75 million senior secured notes in 2006 and increased short-term borrowings and higher interest rates due to reduced credit ratings.
Non-rate-regulated Generation
Interest expense was comparable at Non-rate-regulated Generation and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three months and six months ended June 30, 2007, compared with the same periods in 2006.
Income Taxes
Ameren
Three and six months - Ameren’s effective tax rate decreased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year. Variations in effective tax rates in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three and six months – The effective tax rate decreased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year, primarily because of implementation of changes ordered by the MoPSC. Also, the effective tax rate for the three- and six-month periods in 2006 was increased by the effect of higher
non-deductible expenses than the same periods in 2007.
Illinois Regulated
The effective tax rate increased in the Illinois Regulated segment in the three months and six months ended June 30, 2007, respectively, compared with the same periods in 2006, due to items detailed below:
CIPS
Three and six months – The effective tax rate increased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year, primarily because of a decrease in reserves for uncertain tax positions in 2006 for tax returns filed in prior years when compared to the same periods in 2007.
CILCO (Illinois Regulated)
Three and six months – The effective tax rate decreased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year, primarily because of an increase in expenses deductible for tax which were not expensed for book purposes.
IP
Three months – The effective tax rate decreased in the second quarter of 2007 compared with the second quarter of 2006 primarily because of an increase in expenses deductible for tax which were not expensed for book purposes.
Six months – The effective tax rate was comparable between periods.
Non-rate-regulated Generation
The effective tax rate increased in the Non-rate-regulated Generation segment in the three month and six month periods ended June 30, 2007, compared with the same periods in 2006, due to the items detailed below:
Genco
Three months – The effective tax rate decreased in the second quarter of 2007 compared with the second quarter of 2006 primarily because of an increase in reserves for uncertain tax positions in 2006 for tax returns filed in prior years.
Six months – The effective tax rate decreased in the first six months of 2007 compared with the first six months of 2006 primarily because of an increase in reserves for uncertain tax positions in 2006 for tax returns filed in prior years, along with an increase in expenses in 2007 that were deductible for tax purposes, but were not expensed for book purposes.
CILCO (AERG)
Three and six months – The effective tax rate increased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year, primarily because of a decrease in reserves for uncertain tax positions in 2006 for tax returns filed in prior years.
CILCORP (Parent Company Only)
Three and six months – The effective tax rate increased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year, primarily because of a decrease in expenses deductible for tax that were not deductible for book purposes.
EEI
Three and six months – The effective tax rate decreased in the three months and six months ended June 30, 2007, as compared with the same periods in the prior year, primarily because of an increase in expenses deductible for tax purposes which were not expensed for book purposes.
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, Genco and AERG principally rely on power sales to Marketing Company, which 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 could supply to CIPS, CILCO and IP through the Illinois power procurement auction was limited to 35% of CIPS’, CILCO’s and IP’s aggregate annual load. In addition to cash flows from operating activities, the Ameren Companies 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 June 30, 2007, 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 and in the case of Ameren subsidiaries, equity infusions from Ameren. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for a discussion of a comprehensive rate relief and customer assistance program in Illinois that among other things, would change the process for power procurement in Illinois in the future and would impact future cash flows of the Ameren Companies, except UE, subject to enactment of enabling legislation.
The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2007 and 2006:
| | | | | | | | | |
| | Net Cash Provided By Operating Activities | | | Net Cash Used In Investing Activities | | | Net Cash Provided By (Used In) Financing Activities | |
| | 2007 | | | 2006 | | | Variance | | | 2007 | | | 2006 | | | Variance | | | 2007 | | | 2006 | | | Variance | |
Ameren(a) | $ | 543 | | | $ | 619 | | | $ | (76 | ) | | $ | (754 | ) | | $ | (795 | ) | | $ | 41 | | | $ | 761 | | | $ | 131 | | | $ | 630 | |
| UE | | 145 | | | | 258 | | | | (113 | ) | | | (381 | ) | | | (475 | ) | | | 94 | | | | 444 | | | | 198 | | | | 246 | |
| CIPS | | 44 | | | | 80 | | | | (36 | ) | | | (1 | ) | | | (24 | ) | | | 23 | | | | 99 | | | | (55 | ) | | | 154 | |
| Genco | | 115 | | | | 63 | | | | 52 | | | | (81 | ) | | | (64 | ) | | | (17 | ) | | | (34 | ) | | | 2 | | | | (36 | ) |
| CILCORP | | 62 | | | | 112 | | | | (50 | ) | | | (85 | ) | | | (6 | ) | | | (79 | ) | | | 127 | | | | (86 | ) | | | 213 | |
| CILCO | | 89 | | | | 119 | | | | (30 | ) | | | (85 | ) | | | (48 | ) | | | (37 | ) | | | 88 | | | | (51 | ) | | | 139 | |
| IP | | 73 | | | | 85 | | | | (12 | ) | | | (93 | ) | | | (82 | ) | | | (11 | ) | | | 163 | | | | (2 | ) | | | 165 | |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
Ameren’s cash from operations decreased in the first six months of 2007, as compared with the first six months of 2006. Working capital investment increased as a result of the collection of higher electric rates from customers lagging payments for power purchases. In addition, other operations and maintenance expenses increased, as discussed in Results of Operations, primarily as a result of the Callaway nuclear plant refueling and maintenance outage and storm-related outage repairs. Positive impacts on cash flow from operations included increases in electric and gas margins, and a decrease in income taxes paid (net of refunds) of $90 million.
At UE, cash from operating activities decreased in the first six months of 2007, as compared with the first six months of 2006. Storm repair costs and increased other operations and maintenance expenses as a result of the Callaway nuclear plant refueling and maintenance outage were only partially offset by increased electric and gas margins, as discussed in Results of Operations. In addition, there was an increase in accounts receivable, primarily because of higher prices for interchange sales. Compared to the prior-year period, decreases in cash paid for Taum Sauk costs (net of insurance recoveries) of $33 million, and a decrease in income tax payments (net of refunds) of $69 million benefited cash flow from operations.
At CIPS, cash from operating activities decreased in the first six months of 2007, as compared with the first six months of 2006. Electric and gas margins were higher, but other operations and maintenance expenses also increased, as discussed in Results of Operations. An increased investment in working capital, as a result of the collection of higher electric rates from customers lagging payments for power purchases and an increase in past due customer accounts were the primary reasons for the overall decrease in operating cash flows. Income tax payments (net of refunds) decreased $23 million, benefiting cash flows from operations.
Genco’s cash from operating activities increased in the first six months of 2007 compared to the 2006 period, primarily because of an increase in electric margins, as
discussed in Results of Operations, and a reduction in cash spent for fuel inventory, due to large cash outlays made in 2006 to replenish coal inventory after disruptions in rail deliveries caused by train derailments. Reducing these increases in cash from operating activities was an increase in income tax payments (net of refunds) of $12 million.
Cash from operating activities decreased for CILCORP and CILCO in the six months ended June 30, 2007, compared with the same period of 2006. The positive cash effect of the increased electric margins discussed in Results of Operations was reduced by an increased investment in working capital, as a result of the collection of higher electric rates from customers lagging payments for power purchases and an increase in past due customer accounts. Income tax payments (net of refunds) were comparable year over year for CILCORP and decreased $5 million for CILCO.
IP’s cash from operations decreased in the six months ended June 30, 2007, compared with the 2006 period, despite higher electric margins as discussed in Results of Operations. An increased investment in working capital, as a result of the collection of higher electric rates from customers lagging payments for power purchases and an increase in past due customer accounts were the primary reasons for the overall decrease in operating cash flows. Income tax payments (net of refunds) decreased by $4 million.
Cash Flows from Investing Activities
Ameren had a decrease in cash used in investing activities in the first six months of 2007 compared to the first six months of 2006. Net cash used for capital expenditures and CT acquisitions decreased in 2007 as increased storm repair costs and scrubber projects and upgrades at various power plants were more than offset by the lack of CT acquisitions in 2007 as occurred in 2006. In addition, a $29 million decrease in emission allowance purchases reduced cash flows from investing activities.
UE’s cash used in investing activities decreased in the first six months of 2007, compared to the same period in 2006, principally because of the $292 million expended for CT purchases in 2006, partially offset by a $133 million increase in capital expenditures in the first six months of 2007 as compared with the first six months of 2006. The increased capital expenditures in 2007 were related to storm costs, a scrubber project, and other power plant upgrades. In the 2006 period, UE received proceeds of $67 million from an intercompany note. The absence of these proceeds in the 2007 period further reduced cash from investing activities compared to the same period in 2006.
CIPS had a reduction in its net use of cash from investing activities during 2007 as compared to the same period in 2006. The net $23 million reduction was primarily due to changes in money pool advances. In the 2007 period, CIPS received net money pool repayments of $1 million but in 2006 had net advances to the money pool of $17 million.
Genco’s cash used in investing activities increased in the first six months of 2007 compared with the 2006 period. Capital expenditures increased $38 million, principally due to a scrubber project at one of its plants, while emission allowance purchases decreased by $21 million.
CILCORP’s and CILCO’s cash used in investing activities increased in the six months ended June 30, 2007,
compared with the same period in 2006. Cash flow used in investing activities increased as a result of a $79 million increase in capital expenditures, primarily due to a scrubber project and plant upgrades at CILCO subsidiary AERG, the absence in 2007 of $11 million of proceeds in 2006 from the sale of leveraged leases, and (for CILCORP only) the absence in 2007 of a 2006 note receivable payment from Resources Company in the amount of $42 million. The receipt of a $42 million repayment of prior year money pool advances and a $12 million reduction of emission allowance purchases increased cash used in investing activities.
IP’s cash used in investing activities increased in the first six months of 2007 compared to the same period in 2006 as a result of increased capital expenditures.
See Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.
We continually review our power supply needs. As a result, we could modify plans 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 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.
Cash Flows from Financing Activities
Cash provided by financing activities increased for Ameren in the first six months of 2007 from the year-ago period. Cash from financing activities increased as a result of a
$425 million debt issuance in June 2007 by UE, which was larger than the prior year’s issuances totaling $232 million. The proceeds of the $425 million offering were used to reduce short-tem debt at UE. Short-term debt increased $803 million year over year. The increase in short-term debt was used to pay maturing long-term notes and to fund working capital requirements at Ameren’s subsidiaries. Cash was reduced by a $9 million decrease in common stock issuances, and a $357 million increase in long-term debt redemptions, repurchases and maturities, including the maturity of $350 million in notes at Ameren Corporation in the first six months of 2007.
UE’s cash from financing activities increased for the first six months of 2007, compared to the same period last year, primarily due to the issuance of $425 million in long-term debt in June 2007. The proceeds were used to reduce short-tem debt. Overall, short-term debt decreased $92 million in 2007 compared to the same period in 2006. Short-term borrowings were used in 2007 to fund working capital requirements, and in 2006 principally to fund the acquisition of CTs. In 2007 compared to 2006, cash from financing activities was decreased by a
$43 million increase in dividend payments and $40 million in net repayments on an intercompany borrowing arrangement with Ameren.
CIPS had a net source of cash from financing activities for the six months ended June 30, 2007, compared to a net use of cash for the first six months of 2006. Cash from financing activities increased as a result of a $100 million increase in short-tem debt, a $25 million decrease in dividends paid, a $20 million reduction in long-term debt maturities, and the absence in 2007 of a 2006 intercompany note payment to UE in the amount of $67 million. Reducing these positive effects was the absence in 2007 of $61 million in proceeds from long-term debt issuances in 2006.
Genco had a net use of cash from financing activities for the six months ended June 30, 2007, compared to a net source of cash for the first six months of 2006. The increase in cash used in financing activities in 2007 was a result of a $42 million increase in dividend payments and the absence in 2007 of a $50 million capital contribution that was received in 2006. Reducing the net cash used in financing activities was an increase in net money pool borrowings of $59 million in the first six months of 2007 compared to the same period in 2006.
CILCORP and CILCO had a net source of cash from financing activities for the six months ended June 30, 2007, compared to a net use of cash for the first six months of 2006. Short-term debt increased year over year by $250 million for CILCORP and $125 million for CILCO. Dividends were not paid by either company in 2007, compared to $50 million paid in 2006. Also benefiting cash in 2007 compared to 2006 was the absence of money pool repayments in 2007, compared to 2006 repayments of $89 million at CILCORP and $95 million at CILCO. Cash flows from financing activities were reduced by a $43 million increase in CILCORP note repayments, a $96 million reduction in long-term debt proceeds at both CILCORP and CILCO, and increased redemptions, repurchases, and maturities of long-term debt of $38 million and $50 million at CILCORP and CILCO, respectively.
IP had a net source of cash from financing activities in the first six months of 2007, compared to a net use of cash in the same period of the prior year. Cash was benefited by
$250 million of short-term debt in 2007 compared to none in 2006, and by an $8 million decrease in TFN overfunding, but was reduced by the lack of long-term debt proceeds in 2007, compared to $75 million in 2006, and by a $22 million increase in net repayments of money pool borrowings.
Short-term Borrowings and Liquidity
Short-term borrowings typically consist of drawings under committed bank credit facilities and commercial paper issuances. 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, see Note 3 – Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.
The following table presents the various committed bank credit facilities of the Ameren Companies and AERG and their availability as of June 30, 2007:
| | | | | | | |
Credit Facility | Expiration | Amount Committed | | | Amount Available | |
Ameren, UE and Genco: | | | | | | |
Multiyear revolving(a) | July 2010 | $ | 1,150 | | | $ | 369 | |
CIPS, CILCORP, CILCO, IP and AERG: | | | | | | | | |
2007 Multiyear revolving(b) | January 2010 | | 500 | | | | 75 | |
2006 Multiyear revolving(c) | January 2010 | | 500 | | | | - | |
| (a) | Ameren Companies may access this credit facility through intercompany borrowing arrangements. The maximum amount available to Ameren, UE and Genco is $1.15 billion, $500 million and $150 million, respectively. |
| (b) | The maximum amount available to each borrower at June 30, 2007, including for the issuance of letters of credit, was limited as follows: CILCORP - $125 million, IP - $200 million and AERG - $100 million. CIPS and CILCO have the option of permanently reducing their ability to borrow under the 2006 $500 million credit facility and shifting such capacity, up to the same limits, to the 2007 $500 million credit facility. In July 2007, CILCO shifted $75 million of its sublimit under the 2006 $500 million credit facility to this facility. |
| (c) | The maximum amount available to each borrower at June 30, 2007, including for issuance of letters of credit, was limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. In July 2007, CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of July 31, 2007, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility. |
In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents.
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 (net of any issuance discounts and including any redemption premiums) for the six months ended June 30, 2007 and 2006, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.
| | | | |
| | | Six Months | |
| | Month Issued, Redeemed, Repurchased or Matured | 2007 | | | 2006 | |
Issuances | | | | | | |
Long-term debt | | | | | | |
UE: | | | | | | |
6.40% Senior secured notes due 2017 | June | $ | 425 | | | $ | - | |
CIPS: | | | | | | | | |
6.70% Senior secured notes due 2036 | June | | - | | | | 61 | |
| | | | |
| | | Six Months | |
| | Month Issued, Redeemed, Repurchased or Matured | 2007 | | | 2006 | |
CILCO: | | | | | | | | |
6.20% Senior secured notes due 2016 | June | | - | | | | 54 | |
6.70% Senior secured notes due 2036 | June | | - | | | | 42 | |
IP: | | | | | | | | |
6.25% Senior secured notes due 2016 | June | | - | | | | 75 | |
| Total Ameren long-term debt issuances | | $ | 425 | | | $ | 232 | |
Common stock | | | | | | | | |
Ameren: | | | | | | | | |
DRPlus and 401(k) | Various | $ | 48 | | | $ | 57 | |
| Total common stock issuances | | $ | 48 | | | $ | 57 | |
| Total Ameren long-term debt and common stock issuances | | $ | 473 | | | $ | 289 | |
Redemptions, Repurchases and Maturities | | | | | | | | |
Long-term debt | | | | | | | | |
Ameren: | | | | | | | | |
2002 5.70% notes due 2007 | February | $ | 100 | | | $ | - | |
Senior notes due 2007 | May | | 250 | | | | - | |
CIPS: | | | | | | | | |
7.05% First mortgage bonds due 2006 | June | | - | | | | 20 | |
CILCORP: | | | | | | | | |
9.375% Senior notes due 2029 | March/April | | - | | | | 12 | |
CILCO: | | | | | | | | |
7.50% First mortgage bonds due 2007 | January | | 50 | | | | - | |
IP: | | | | | | | | |
Note payable to IP SPT: | | | | | | | | |
5.65% Series due 2008 | Various | | 43 | | | | - | |
5.54% Series due 2007 | Various | | - | | | | 54 | |
| Total Ameren long-term debt redemptions, repurchases and maturities | | $ | 443 | | | $ | 86 | |
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of June 30, 2007:
| | | | | | | | | | |
| | Effective Date | Authorized Amount | | | Issued | | | Available | |
| Ameren | June 2004 | $ | 2,000 | | | $ | 459 | | | $ | 1,541 | |
| UE | October 2005 | | 1,000 | | | | 685 | | | | 315 | |
| CIPS | May 2001 | | 250 | | | | 211 | | | | 39 | |
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 a total of 0.9 million new shares of common stock valued at $48 million in the six months ended June 30, 2007.
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 bemade 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 3 – Credit Facilities and Liquidity to our financial statements under Part I, Item 1, 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 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At June 30, 2007, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the
capital markets or make our access to the capital markets uncertain or limited. Such events would increase our cost of capital and adversely affect our ability to access the capital markets.
Dividends
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues, including Ameren’s historical earnings and cash flow, projected earnings, projected cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics, impacts of regulatory orders or legislation and overall business considerations.
See Note 3 – Credit Facilities and Liquidity and Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At June 30, 2007, except as discussed below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.
The 2007 $500 million credit facility and 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to common and preferred stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured credit rating to below investment-grade, causing it to be subject to this dividend payment limitation. As of June 30, 2007, AERG did not meet the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities. The other borrowers thereunder are not currently limited in their dividend payments by this provision of the 2007 or 2006 $500 million credit facilities.
The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the six months ended June 30, 2007 and 2006.
| | | |
| | Six Months | |
| | 2007 | | | 2006 | |
| UE | $ | 127 | | | $ | 84 | |
| CIPS | | - | | | | 25 | |
| Genco | | 113 | | | | 71 | |
CILCORP(a) | | - | | | | 50 | |
| Nonregistrants | | 23 | | | | 30 | |
| Dividends paid by Ameren | $ | 263 | | | $ | 260 | |
| (a) | CILCO paid to CILCORP dividends of $50 million for the six months ended June 30, 2006. |
Contractual Obligations
For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K, and Other Obligations in Note 8 – Commitments and Contingencies under Part I, Item 1, of this report. See Note 11 – Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan. See also Note 1 – Summary of Significant Accounting Policies to our financial statements under Part I, Item 1, of this report for the unrecognized tax benefits under the provisions of FIN 48.
Subsequent to December 31, 2006, obligations related to the procurement of natural gas and nuclear fuel materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $4,031 million, $731 million, $415 million, $71 million, $1,241 million, $1,241 million and $1,554 million, respectively, as of June 30, 2007. Total other obligations at June 30, 2007, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,020 million, $2,017 million, $440 million, $315 million, $1,395 million, $1,395 million and $1,686 million, respectively.
As a result of the Illinois electric agreement reached in July 2007 and subject to enactment of legislation contemplated by the agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million;
IP - $28 million), $62 million from Genco and $28 million from AERG. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the Illinois electric agreement.
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:
| | Moody’s | S&P | Fitch |
Ameren: | | | |
| Issuer/corporate credit rating | Baa2 | BBB- | BBB+ |
| Unsecured debt | Baa2 | BB+ | BBB+ |
| Commercial paper | P-2 | A-3 | F2 |
UE: | | | |
| Issuer/corporate credit rating | Baa1 | BBB- | A- |
| Secured debt | A3 | BBB- | A+ |
| Commercial paper | P-2 | A-3 | F2 |
CIPS: | | | |
| Issuer/corporate credit rating | Ba1 | BB | BB+ |
| Secured debt | Baa3 | BBB- | BBB |
Genco: | | | |
| Issuer/corporate credit rating | - | BBB- | BBB+ |
| Unsecured debt | Baa2 | BBB- | BBB+ |
CILCORP: | | | |
| Issuer/corporate credit rating | - | BB | BB+ |
| Unsecured debt | Ba2 | B+ | BB+ |
CILCO: | | | |
| Issuer/corporate credit rating | Ba1 | BB | BB+ |
| Secured debt | Baa2 | BBB- | BBB |
IP: | | | |
| Issuer/corporate credit rating | Ba1 | BB | BB+ |
| Secured debt | Baa3 | BBB- | BBB |
On March 12, 2007, Moody’s downgraded the credit ratings of Ameren, UE, CIPS, CILCORP, CILCO, and IP. In addition, Moody’s assigned to CILCORP a corporate family credit rating of “Ba1” and a probability of default rating of “Ba1.” Moody’s indicated that the ratings of Ameren, CIPS, CILCORP, CILCO and IP remain on review for possible further downgrade. Moody’s also placed Ameren’s “Prime-2” short-term credit rating for commercial paper on review for possible downgrade. The ratings of UE are no longer on review although the rating outlook is negative.
Moody’s indicated that the downgrade of the ratings of Ameren, CIPS, CILCORP, CILCO and IP was prompted by the passage of rate freeze legislation by both the Illinois House of Representatives on March 6, 2007, and the Environment and Energy Committee of the Illinois Senate on March 7, 2007, and the growing support at the time for a rate freeze in both chambers of the Illinois General Assembly. In the event of the passage and enactment of rate freeze legislation, Moody’s indicated that the Ameren Illinois Utilities could be downgraded further into speculative (junk) grade.
Moody’s indicated that the downgrade of UE was prompted by higher costs, lower financial metrics and a continued challenging regulatory environment in Missouri. The downgrade also reflects Moody’s expectation that Ameren may have to rely more heavily on UE for upstreamed dividends if rate freeze legislation is passed and enacted in Illinois.
On April 24, 2007, Moody’s stated that the passage of rate freeze legislation by the Illinois Senate on April 20, 2007, was a negative development although it will not have an immediate impact on the credit ratings of Ameren or the Ameren Illinois Utilities. The legislation would have rolled back electric rates to 2006 levels, frozen rates at those levels for at least one year, and provided for refunds to customers. Moody’s also stated that any progress toward passage of the legislation by the Illinois House of Representatives could result in a ratings downgrade of the Ameren Illinois Utilities. Further, Moody’s said that enactment into law of such legislation could result in multi-notch downgrades of the ratings of the Ameren Illinois Utilities well into speculative grade due to concerns about the impact on the financial performance of the Ameren Illinois Utilities.
On March 9, 2007, S&P issued a report in response to the passage by the Environment and Energy Committee of the Illinois Senate of legislation which would have rolled back rates to 2006 levels and frozen rates for at least six months. S&P indicated in its report that if such bill was passed by the full Senate, the issuer credit ratings on the Ameren Illinois Utilities would be immediately lowered to “BB+.” According to S&P, such a downgrade would reflect growing sentiment in both chambers of the Illinois General Assembly of the need for rate relief for certain affected customers of the Ameren Illinois Utilities. S&P indicated that it would further lower the ratings on the Ameren Illinois Utilities if rate freeze legislation “of any meaningful length” is approved by both chambers of the Illinois General Assembly, and such ratings may be lowered precipitously in such circumstance.
On April 23, 2007, S&P lowered its long-term corporate credit ratings of Ameren, UE, and Genco from “BBB” to “BBB-”. Issuer credit ratings at CIPS, CILCORP, CILCO, and IP were lowered from “BBB-” to “BB” and secured debt ratings were lowered at CIPS and CILCO from “BBB” to “BBB-”. The downgrades followed the passage of rate rollback and freeze legislation on April 20, 2007, by the Illinois Senate as discussed above.
On April 2, 2007, Fitch downgraded the issuer default ratings of Ameren from “A-” to “BBB+” and the issuer default ratings of each of CIPS, CILCORP and CILCO from “BBB+” to “BB+”. Additionally, Ameren’s and CILCORP’s senior unsecured debt ratings were lowered from “A-” to “BBB+” and from “BBB+” to “BB+”, respectively. CIPS’ and CILCO’s secured debt ratings were each lowered from “A” to “BBB”. Fitch stated that the downgrade of CIPS, CILCORP and CILCO “follows the inability of the Illinois utilities to reach an agreement concerning the recovery of purchased power costs with the Illinois Senate before it adjourned before the mid-term break” on March 30, 2007, and that the downgrade of Ameren was “based upon an increased overall corporate risk profile due to the regulatory environment in Illinois.”
In July 2007, an electric settlement agreement was reached among key stakeholders in Illinois which, subject to enactment of enabling legislation, resolves the Illinois regulatory and legislative uncertainties that were the basis of most of the adverse ratings actions noted above. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for a discussion of the Illinois agreement.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. They may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made as of the end of the second quarter of 2007 were $87 million, $3 million, $10 million, $2 million, $24 million, $24 million, and $43 million at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively, resulting from our reduced corporate and issuer credit ratings. Sub-investment-grade issuer ratings for securities (less than “BBB-” or “Baa3”) at June 30, 2007, could have resulted in Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to
$149 million, $39 million, $19 million, $25 million, $21 million, $21 million, or $27 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
OUTLOOK
Below are some key events and trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2007 and beyond.
Revenues
| · | 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. |
| · | Average residential electric rates for CIPS, CILCO and IP increased significantly following the expiration of a rate freeze at the end of 2006. Electric rates rose because of the increased cost of power purchased on behalf of the Ameren Illinois Utilities’ customers and an increase in electric delivery service rates. Illinois average residential rates were expected to increase in 2007 by approximately 40% to 55% over 2006 rates with the overall increase for electric heat customers expected to be even higher. Due to the magnitude of these increases, a comprehensive customer rate relief and customer assistance program and agreement was reached with key stakeholders in Illinois that would provide approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. This agreement was reached in order to avoid rate rollback and freeze legislation, or a tax on power generation enabling legislation necessary for the agreement to become effective was passed by the Illinois General Assembly in late July 2007 but must be signed by the governor of Illinois to become law. |
| · | Pursuant to the rate relief program, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. To fund these contributions, the Ameren Illinois Utilities, Genco and AERG would need to increase their respective short-term or long-term borrowings. |
| · | Under the rate relief program, the Ameren Illinois Utilities would continue to have the right to file new electric delivery service rate cases with the ICC at the utilities’ discretion. As a result of low returns on equity expected in 2007, the Ameren Illinois Utilities plan to file additional delivery service rate cases by the end of 2007. |
| · | The redesign of all-electric customers’ rates is the subject of an ongoing case with the ICC designed to reduce seasonal fluctuations for residential customers who use large amounts of electricity while allowing utilities to fully recover costs. However, the redesign is expected to result in revenue changes between quarterly reporting periods. |
| · | The agreement provides that if legislation is enacted in Illinois before August 1, 2011, freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on the generation of electricity, then the remaining commitments would expire and any funds set aside in support of the funding commitments would be refunded to the contributing utilities and electric generators. |
| · | As part of the agreement, the current reverse auction used for power procurement in Illinois would be discontinued immediately and replaced with a new power procurement process. In 2008, utilities would contract for necessary baseload, intermediate and peaking power requirements through a request-for-proposal process, subject to ICC review and approval. Existing supply contracts from the September 2006 reverse auction would remain in place. |
| · | As part of the rate relief program, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock-in prices for 400 to 1,000 megawatts annually of their baseload power requirements from 2008 through 2012 at |
| relevant market prices. These contracts are not effectiveuntil enactment of enabling legislation by the Illinois governor. If the legislation is enacted into law after August 10, 2007, then new market prices will be set when the legislation is enacted. These financial swap contracts expose Genco and AERG to changes in market prices, which could materially impact Genco’s, CILCORP’s, and CILCO’s results of operations, financial position, or liquidity if the market prices of power exceed the locked-in prices. |
| · | See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of Illinois rate matters. |
| · | The MoPSC issued an order granting UE a $43 million increase in base rates for electric service with new electric rates effective June 4, 2007. The MoPSC also approved a stipulation and agreement authorizing an increase in UE’s annual natural gas delivery revenues of $6 million, effective April 1, 2007. UE agreed not to file a natural gas delivery rate case before March 15, 2010. With increasing fuel and purchased power costs, and lacking a fuel and purchased power cost recovery mechanism, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability, UE expects to be entering a period where more frequent rate cases will be necessary. |
| · | 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 spot markets and influence the cost of power purchased in the spot markets. |
| · | 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 (through Marketing Company) 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. In 2007, an additional 1 million megawatthours of these contracts will expire and another 2 million contracted megawatthours will expire in 2008. These agreements had an average embedded selling price of $36 per megawatthour, which is below current market prices. In 2006, Genco also sold 2.1 million net megawatthours of power in the spot 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 spot 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). |
| · | The marketing strategy for Non-rate-regulated Generation is to optimize generation output in a low risk manner to minimize earnings and cash flow volatility, while capitalizing on its low-cost generation fleet to provide for solid, sustainable returns. Through a mix of physical and financial sales contracts and the Illinois 2006 power procurement auction and including expected contracts associated with the Illinois settlement agreement referenced above, the Non-rate-regulated Generation segment has sold approximately 90% of its expected 2007 generation output for the remainder of 2007 (fiscal year 2008 - 70%, or 23 million megawatthours; fiscal year 2009 - 50%, or 17 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). |
| · | 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 customers, 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. |
Fuel and Purchased Power
| · | 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 the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather and derailments. As of June 30, 2007, coal inventories for UE, Genco, AERG and EEI were adequate, and consistent with historical levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources. |
| · | Ameren’s coal and related transportation costs are expected to increase 15% to 20% in 2007 over 2006 and 5% to 10% in 2008. Ameren’s nuclear fuel costs are also expected to rise over the next few years. In addition, power generation from higher-cost, gas-fired plants is expected to increase in the next few years. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk in Part I of this report for information about the percentage of fuel and transportation requirements that are price-hedged for 2007 through 2011. |
| · | In Illinois, Ameren and IP will also experience higher year-over-year purchased power expenses as the amortization of certain favorable purchase accounting adjustments associated with the IP acquisition was completed in 2006. |
| · | In July 2005, a new law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. In UE’s electric rate order issued by the MoPSC in May 2007, the MoPSC denied UE’s request to implement a fuel and purchased power cost recovery mechanism and an environmental cost recovery mechanism. UE may request the use of these mechanisms in future rate cases. |
| · | In 2007, Ameren expects to reduce levels of emission allowance sales in order to retain remaining allowances for future environmental compliance needs. |
Other Costs
| · | In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. In 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 of the damage and liabilities (but not penalties or lost electric margins) caused by the breach, including rebuilding the plant, will be covered by insurance. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties and by state authorities. The Taum Sauk incident is also under investigation at the MoPSC. 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. See Note 2 – Rate and Regulatory Matters and Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of Taum Sauk matters. |
| · | UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the fall of 2008. During an outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years. |
| · | Over the next few years, we expect rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may need to take, at UE’s Callaway nuclear plant and at our other facilities. Insurance premiums may also increase as a result of the Taum Sauk incident, among other things. |
| · | Bad debts may increase due to rising electric rates. |
| · | We are currently undertaking cost reduction and control initiatives associated with the strategic sourcing of purchases and streamlining of all aspects of our business. |
Capital Expenditures
| · | The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2007 and 2016, Ameren expects that certain Ameren Companies will be required to invest between $3.5 billion and $4.5 billion to retrofit their power plants with pollution control equipment. These investments will also result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment will be in Ameren’s regulated UE operations, and it is therefore expected to be recoverable from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of this increased investment. |
| · | Ameren will provide a report on how it is responding to rising regulatory, competitive, and public pressure to significantly reduce carbon dioxide and other emissions from current and proposed power plant operations. The report will include Ameren’s climate change strategy and activities, current greenhouse gas emissions, and analysis with respect to plausible future greenhouse gas scenarios. Ameren will publish this report on its Web site by December 15, 2007. Investments to control carbon emissions at Ameren’s coal-fired plants would significantly increase future capital expenditures. |
| · | UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until at least 2018. However, due to the significant time required to plan, acquire permits for and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In 2007, UE signed an agreement with UniStar Nuclear to assist UE in the preparation of a combined construction and operating license application (COLA) for filing with the NRC. A COLA describes how a nuclear plant would be designed, constructed and operated. In addition, UE has also signed contracts for certain long lead-time equipment. Preparing a COLA and entering into these contracts does not mean a decision has been made to build a nuclear plant. They are only the first steps in the regulatory licensing and procurement process. UE and UniStar Nuclear must submit the COLA |
| to the NRC in 2008 to be eligible for incentives available under provisions of the 2005 Energy Policy Act. |
| · | Over the next few years, we expect to make significant investments in our electric and gas infrastructure to improve overall system reliability in addition to addressing environmental compliance requirements. We are projecting higher labor and material costs for these capital expenditures. |
Other
| · | Severe storms in 2006 and early 2007 resulted in electric outages for more than 1.5 million customers and an increased focus on alternatives for improving reliability during severe storms. UE, CIPS, CILCO and IP are studying alternatives to improve system reliability, which could result in increased investment in system infrastructure or higher maintenance expenses. UE announced in July 2007 plans to spend $300 million over three years for underground cabling and reliability improvement, $135 million ($45 million per year) for tree-trimming, and $84 million over three years (approximately $28 million per year) for circuit and device inspection and repair. We would expect any additional costs or investments to be recovered in rates. |
| · | The MoPSC has initiated a rulemaking process to develop reliability rules applicable to Missouri investor-owned utilities that address three focus areas: vegetation management, infrastructure inspection, and reliability. The MoPSC’s proposed vegetation management and infrastructure inspection rules were published in the Missouri Register in July 2007, and a public hearing on these rules is scheduled for August 15, 2007. The MoPSC’s proposed reliability rules have not yet been published in the Missouri Register. The ultimate cost of the rules is subject to their final terms, but could be material. UE anticipates that most of such costs would ultimately be recoverable in rates. |
| · | In 2006, Ameren realized gains on sales of noncore properties, including leveraged leases. The net benefit of these sales to Ameren in 2006 was 16 cents per share. Ameren continues to pursue the sale of its interests in its remaining three leveraged lease assets. Ameren does not expect to achieve similar sales levels of noncore properties in 2007. |
Affiliate Transactions
| · | 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. UE is able to sell any excess power it has at market prices, which we believe will most likely be higher than the prices paid to it by Genco. Genco will no longer receive the margins on sales that it made, which were fulfilled with power from UE. The electric rate order issued in May 2007 by the MoPSC incorporated the net decrease in UE’s revenue requirement from increased margins expected to result from the termination of the JDA. See Note 7 – Related Party Transactions to our financial statements under Part I, Item 1, of this report for a discussion of the effects of terminating the JDA. |
The above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, or liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.
ITEM 3. 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.
Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risks.
Interest Rate Risk
We are exposed to market risk through 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 June 30, 2007:
| | | | | | |
| | Interest Expense | | | Net Income(a) | |
| Ameren | $ | 24 | | | $ | (15) | |
| UE | | 9 | | | | (6) | |
| CIPS | | 2 | | | | (1) | |
| Genco | | 2 | | | | (1) | |
| CILCORP | | 5 | | | | (3) | |
| CILCO | | 3 | | | | (2) | |
| IP | | 7 | | | | (4) | |
| (a) | Calculations are based on an effective tax rate of 38%. |
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 receivable 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 June 30, 2007, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with power purchase and sale activity with nonaffiliated companies. These companies also have credit exposure to affiliates. At June 30, 2007, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade purchases and sales was each less than $1 million, net of collateral (2006 - less than $1 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $33 million at June 30, 2007 (2006 - $27 million).
The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs, which would provide $488 million in rate relief over a four-year period to certain electric customers of the Ameren Illinois Utilities, if enabling legislation is enacted into law. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities would bill the participating generators for their proportionate share of that month’s rate relief and assistance, which would be due in 30 days, or drawn from the escrow agreement. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.
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. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI, and in the amount of cash required to be contributed to the plans.
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.
The following table shows how our earnings might decrease if power prices were to increase by 1% on unhedged economic generation for the remainder of 2007 through 2010:
| | | |
| | Net Income | |
| Ameren | $ | (25) | |
| UE | | (10) | |
| Genco | | (10) | |
| CILCO (AERG) | | (3) | |
| EEI | | (2) | |
| a) | Calculations are based on an effective tax rate of 38% |
Similar techniques are used to manage risks associated with fuel exposures for generation. Most UE, Genco, AERG and EEI fuel supply contracts are physical forward contracts. UE, Genco, AERG and EEI do not have a provision similar to the PGA clause for electric operations, so UE, Genco, AERG and EEI 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 electric rate case filed in July 2006, UE had requested approval by the MoPSC for a fuel and purchased power cost recovery mechanism; however, such request was rejected by the MoPSC in its May 2007 order.
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 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 remainder of 2007 through 2011:
| | | | | | | | | | |
| | 2007 | | | 2008 | | | | 2009 – 2011 | |
Ameren: | | | | | | | | | |
| Coal | | 100% | | | | 95% | | | | 40% | |
| Coal transportation | | 100 | | | | 95 | | | | 46 | |
| Nuclear fuel | | 100 | | | | 91 | | | | 52 | |
| Natural gas for generation | | 55 | | | | 12 | | | | - | |
Natural gas for distribution(a) | (a) | | | | 31 | | | | 9 | |
Purchased power for Illinois Regulated(b) | | 100 | | | | 81 | | | | 21 | |
UE: | | | | | | | | | | | |
| Coal | | 100% | | | | 94% | | | | 41% | |
| Coal transportation | | 100 | | | | 97 | | | | 61 | |
| Nuclear fuel | | 100 | | | | 91 | | | | 52 | |
| Natural gas for generation | | 36 | | | | 8 | | | | - | |
Natural gas for distribution(a) | (a) | | | | 32 | | | | 5 | |
CIPS: | | | | | | | | | | | |
Natural gas for distribution(a) | (a) | | | | 32% | | | | 13% | |
Purchased power(b) | | 100% | | | | 81 | | | | 21 | |
Genco: | | | | | | | | | | | |
| Coal | | 100% | | | | 95% | | | | 38% | |
| Coal transportation | | 100 | | | | 97 | | | | 45 | |
| Natural gas for generation | | 100 | | | | 15 | | | | - | |
CILCORP/CILCO: | | | | | | | | | | | |
| Coal (AERG) | | 99% | | | | 96% | | | | 41% | |
| Coal transportation (AERG) | | 100 | | | | 71 | | | | 23 | |
Natural gas for distribution(a) | (a) | | | | 24 | | | | 7 | |
Purchased power(b) | | 100 | | | | 81 | | | | 21 | |
IP: | | | | | | | | | | | |
Natural gas for distribution(a) | (a) | | | | 35% | | | | 9% | |
Purchased power(b) | | 100% | | | | 81 | | | | 21 | |
| | | | | | | | | | |
| | 2007 | | | 2008 | | | | 2009 – 2011 | |
EEI: | | | | | | | | | | | |
| Coal | | 100% | | | | 97% | | | | 42% | |
| Coal transportation | | 100 | | | | 100 | | | | - | |
| (a) | The year 2007 is non-applicable for this table. 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 early 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. Nearly all of these customers chose a third-party supplier. However, regardless of whether customers choose a third-party supplier, the purchased power needed to serve this load is 100% price-hedged through May 31, 2008, due to the Illinois auction. Also excluded from the percent hedged amount is purchased power to serve large service real-time pricing customers. See Note 2 – Rate and Regulatory Matters and Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a discussion of this matter. |
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:
| | | | | | |
| | Coal | | | Transportation | |
| | Fuel Expense | | | Net Income(a) | | | Fuel Expense | | | Net Income(a) | |
Ameren(b) | $ | 12 | | | $ | (8 | ) | | $ | 14 | | | $ | (9 | ) |
| UE | | 6 | | | | (4 | ) | | | 5 | | | | (3 | ) |
| Genco | | 4 | | | | (2 | ) | | | 4 | | | | (2 | ) |
| CILCORP | | 2 | | | | (1 | ) | | | 2 | | | | (1 | ) |
| CILCO (AERG) | | 2 | | | | (1 | ) | | | 2 | | | | (1 | ) |
| EEI | | 1 | | | | (1 | ) | | | 4 | | | | (2 | ) |
| (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 and coal transportation prices, UE, Genco, AERG and EEI 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.
See Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.
Fair Value of Contracts
Most of our commodity contracts qualify for treatment as normal purchases and sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months and six months ended June 30, 2007. 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 five years.
| | | | | | | | | | | | | | | | | | | |
| | | Ameren(a) | | | UE | | | CIPS | | | Genco(b) | | | CILCORP/ CILCO | | | IP | |
Three Months | | | | | | | | | | | | | | | | | | |
| Fair value of contracts at beginning of period, net | | $ | 31 | | | $ | - | | | $ | 3 | | | $ | (1 | ) | | $ | 6 | | | $ | - | |
| Contracts realized or otherwise settled during the period | | | (5 | ) | | | (2 | ) | | | (1 | ) | | | - | | | | (2 | ) | | | - | |
| Changes in fair values attributable to changes in valuation technique and assumptions | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Fair value of new contracts entered into during the period | | | 22 | | | | (2 | ) | | | - | | | | - | | | | - | | | | - | |
| Other changes in fair value | | | 21 | | | | 9 | | | | (1 | ) | | | (1 | ) | | | - | | | | - | |
| Fair value of contracts outstanding at end of period, net | | $ | 69 | | | $ | 5 | | | $ | 1 | | | $ | (2 | ) | | $ | 4 | | | $ | - | |
Six Months | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of contracts at beginning of period, net | | $ | 98 | | | $ | 12 | | | $ | 2 | | | $ | (1 | ) | | $ | 6 | | | $ | 2 | |
| Contracts realized or otherwise settled during the period | | | (22 | ) | | | (6 | ) | | | (1 | ) | | | - | | | | (4 | ) | | | - | |
| Changes in fair values attributable to changes in valuation technique and assumptions | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Fair value of new contracts entered into during the period | | | 20 | | | | (3 | ) | | | - | | | | - | | | | - | | | | - | |
| Other changes in fair value | | | (27 | ) | | | 2 | | | | - | | | | (1 | ) | | | 2 | | | | (2 | ) |
| Fair value of contracts outstanding at end of period, net | | $ | 69 | | | $ | 5 | | | $ | 1 | | | $ | (2 | ) | | $ | 4 | | | $ | - | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | In conjunction with the new power supply agreement between Marketing Company and Genco that went into effect January 1, 2007, the mark-to-market value of hedges entered into during 2006 for Genco was transferred from Genco to Marketing Company. |
The following table presents maturities of derivative contracts as of June 30, 2007:
| | | | | | | | | | | | | | | |
Sources of Fair Value | Maturity Less than 1 Year | | | Maturity 1-3 Years | | | Maturity 4-5 Years | | | Maturity in Excess of 5 Years | | | Total Fair Value | |
Ameren: | | | | | | | | | | | | | | |
| Prices actively quoted | $ | 8 | | | $ | - | | | $ | - | | | $ | - | | | $ | 8 | |
Prices provided by other external sources(a) | | 1 | | | | - | | | | - | | | | - | | | | 1 | |
Prices based on models and other valuation methods(b) | | 41 | | | | 19 | | | | - | | | | - | | | | 60 | |
| Total | $ | 50 | | | $ | 19 | | | $ | - | | | $ | - | | | $ | 69 | |
UE: | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Prices provided by other external sources(a) | | - | | | | - | | | | - | | | | - | | | | - | |
Prices based on models and other valuation methods(b) | | 2 | | | | 1 | | | | - | | | | - | | | | 3 | |
| Total | $ | 4 | | | $ | 1 | | | $ | - | | | $ | - | | | $ | 5 | |
CIPS: | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Prices provided by other external sources(a) | | 1 | | | | - | | | | - | | | | - | | | | 1 | |
Prices based on models and other valuation methods(b) | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | $ | 1 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1 | |
Genco: | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | $ | (1 | ) | | $ | (1 | ) | | $ | - | | | $ | - | | | $ | (2 | ) |
Prices provided by other external sources(a) | | - | | | | - | | | | - | | | | - | | | | - | |
Prices based on models and other valuation methods(b) | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | $ | (1 | ) | | $ | (1 | ) | | $ | - | | | $ | - | | | $ | (2 | ) |
CILCORP/CILCO: | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | $ | 1 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1 | |
Prices provided by other external sources(a) | | 3 | | | | - | | | | - | | | | - | | | | 3 | |
Prices based on models and other valuation methods(b) | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | $ | 4 | | | $ | - | | | $ | - | | | $ | - | | | $ | 4 | |
IP: | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted �� | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Prices provided by other external sources(a) | | - | | | | - | | | | - | | | | - | | | | - | |
Prices based on models and other valuation methods(b) | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| (a) | Principally fixed price for floating over-the-counter power swaps, power forwards and fixed price for floating over-the-counter natural gas swaps. |
| (b) | Principally coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates. |
ITEM 4. CONTROLS AND PROCEDURES.
| (a) | Evaluation of Disclosure Controls and Procedures |
As of June 30, 2007, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
| (b) | 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.
PART II. OTHER INFORMATION
ITEM 1. 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.
For additional information on legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 7 – Related Party Transactions and Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, and Item 1A, Risk Factors, below of this report.
ITEM 1A. RISK FACTORS.
The Form 10-K includes a detailed discussion of our risk factors. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in the Form 10-K.
The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions which are largely outside of our control. Where 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.
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, and liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on 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. Despite the provisions of the Illinois rate relief agreement reached in July 2007, described below, which remains subject to enactment of enabling legislation by the Illinois governor, and the rate increases granted by the MoPSC and the ICC in recent electric and gas rate proceedings, Ameren remains subject to competitive, economic, political, legislative and regulatory pressures that 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 May 2007, the ICC issued an order disallowing the recovery of certain administrative and general expenses totaling $50 million. 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 included the cost of power, so these delivery service revenue changes do 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. CIPS, CILCO and IP expect to file additional electric delivery service rate cases before December 31, 2007.
Electric Agreement
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. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006.
Various Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties challenged the results of the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. In the first six months of 2007, legislation was introduced in the Illinois General Assembly which would have rolled back and frozen the Ameren Illinois Utilities’ electric rates at pre-January 2, 2007 levels. This would have prevented the Ameren Illinois Utilities from recovering from retail customers substantial portions of the cost of electric energy the Ameren Illinois Utilities are purchasing under wholesale contracts entered into as a result of the September 2006 auction, and would have caused the Ameren Illinois Utilities to under-recover their delivery service costs until the ICC could approve higher delivery service rates.
As a result of these concerns, in July 2007, an agreement was reached among key stakeholders in Illinois that addresses the increase in electric rates and the future power procurement process. Ameren, on behalf of Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon, on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings, Inc., Midwest Generation, LLC, and MidAmerican Energy Company agreed to contribute approximately
$1 billion over four years to fund both rate relief programs and the IPA. The agreement provides that if legislation is enacted in Illinois before August 1, 2011 freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on generation of electricity, then the remaining funding commitments will expire and any funds set aside in support of those commitments will be refunded to the utilities and electric generators. The agreement also provides that all pending litigation and regulatory actions by the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the electric space heating marketing practices of the Ameren Illinois utilities would be withdrawn with prejudice.
Although we cannot fully predict the effect of the implementation of the comprehensive rate relief program and agreement on Ameren, the Ameren Illinois Utilities, Genco or AERG, we believe the settlement agreement reached with key stakeholders in Illinois significantly reduces the risk that legislation would be enacted into law that reduces and freezes electric rates of CIPS, CILCO and IP to rates that were in effect prior to January 2, 2007, or that imposes a tax on electric generation in Illinois. The following factors resulting from implementation of the program and agreement could have a material adverse effect on the results of operations, financial position or liquidity of Ameren, the Ameren Illinois Utilities, Genco or AERG:
| · | uncertainty as to the implementation of the new power procurement process in Illinois for 2008 and 2009, including ICC review and approval requirements, the role of the IPA, and the ability of the Ameren Illinois Utilities to lease, or invest in, generation facilities; |
| · | the increase in short-term or long-term borrowings by the Ameren Illinois Utilities, Genco and AERG to fund contributions under the program and agreement; |
| · | the failure by the electric generators that are party to the agreement to perform in a timely manner under their respective funding agreements, which permits the Ameren Illinois Utilities to seek reimbursement for a portion of the rate relief that will be provided to certain of their electric customers; |
| · | the exposure of Genco and AERG to changes in market prices as a result of the financial swap contracts that Marketing Company (on behalf of Genco and AERG) entered into with the Ameren Illinois Utilities; and |
| · | the extent to which Genco and AERG will be successful in making future sales to supply a portion of Illinois' total electric demand through the revised power procurement mechanism. |
The settlement agreement will not be effective until enabling legislation, which has been passed by the Illinois General Assembly, is enacted into law by the Illinois governor. We are unable to predict the actions the Illinois General Assembly, the Illinois attorney general or Illinois governor may take that might affect electric rates, the power procurement process for CIPS, CILCO and IP or pending litigation and regulatory actions if the settlement agreement is not enacted into law. If any decision is made or action occurs that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner, and such decision or action is not promptly enjoined, it could result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk (or speculative) status, the inability to access the capital markets on reasonable terms, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, requirements to post collateral or other assurances for certain obligations, significant risk of disruption in electric and gas service, significant job losses, and the financial insolvency and bankruptcy of CIPS, CILCORP, CILCO and IP. In addition, Ameren, CILCORP and IP would need to assess whether they are required to record a charge for
goodwill impairment for the goodwill that was recorded when Ameren acquired CILCORP and IP. Furthermore, if the Ameren Illinois Utilities are unable to recover their costs from customers, the utilities could be required to cease applying for the electric portions of their businesses SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which allows the Ameren Illinois Utilities to defer certain costs pursuant to actions of rate regulators and to recover such costs in rates charged to customers. This could result in the elimination of the Ameren Illinois Utilities’ regulatory assets and liabilities recorded on their, CILCORP’s and Ameren’s balance sheets and a one-time extraordinary charge on their, CILCORP’s and Ameren’s statements of income that could be material. Ameren’s, CILCORP’s and IP’s assessment of any goodwill impairment and Ameren’s, CIPS’, CILCORP’s, CILCO’s and IP’s continued application of SFAS No. 71, for the electric portions of the Ameren Illinois Utilities’ businesses, would include consideration of, among other things, their views on the ultimate success of their legal actions and strategies to enjoin the implementation of, and ultimately invalidate, any enacted legislation, decision, or other action that would impair the Ameren Illinois Utilities’ ability to recover their costs from customers through rates.
Missouri
With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In March 2007, a stipulation and agreement was approved by the MoPSC authorizing an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. As part of this stipulation and agreement, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement does not prevent UE from filing to recover infrastructure costs through a statutory infrastructure system replacement surcharge (ISRS) during this three-year rate moratorium. The return on equity to be used by UE for purposes of any future ISRS tariff filing is 10.0%.
In May 2007, the MoPSC issued an order authorizing a $43 million increase in UE’s base rates for electric service based on a return on equity of 10.2%. The MoPSC denied UE’s and other intervenors’ applications for rehearing with respect to certain aspects of the MoPSC rate order. In July 2007, UE appealed certain aspects of the MoPSC decision, principally the 10.2% return on equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both intervenors in the electric rate case, also appealed certain aspects of the MoPSC decision to the Circuit Court of Cole County. We cannot predict the outcome of these appeals of the MoPSC rate order. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.
In addition, the MoPSC has initiated a rulemaking process to develop reliability rules applicable to Missouri investor-owned utilities that address three focus areas: vegetation management, infrastructure inspection, and reliability. The MoPSC's proposed vegetation management and infrastructure inspection rules were published in the Missouri Register in July 2007, and a public hearing on these rules is scheduled for August 15, 2007. The MoPSC's proposed reliability rules have not yet been published in the Missouri Register. The ultimate cost of the rules is subject to their final terms, but could be material.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
| | | | | | | | | | | | | |
Period | | (a) Total Number of Shares (or Units) Purchased(a) | | | (b) Average Price Paid per Share (or Unit) | | | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | |
| April 1 – April 30, 2007 | | | 600 | | | $ | 50.88 | | | | - | | | | - | |
| May 1 – May 31, 2007 | | | - | | | | - | | | | - | | | | - | |
| June 1 – June 30, 2007 | | | - | | | | - | | | | - | | | | - | |
| Total | | | 600 | | | $ | 50.88 | | | | - | | | | - | |
| (a) | These shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligation upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998, as amended. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the April 1 to June 30, 2007 period.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Ameren
At Ameren’s annual meeting of shareholders held on April 24, 2007, the following matters were presented to the meeting for a vote and the results of such voting are as follows:
| Item (1) | Election of 12 directors (comprising Ameren’s full Board of Directors) to serve until the next annual meeting of shareholders in 2008. |
Name | For | Withheld | Broker Non-Votes(a) |
| Stephen F. Brauer | 172,744,706 | 3,380,682 | - |
| Susan S. Elliott | 172,623,835 | 3,501,553 | - |
| Gayle P. W. Jackson | 172,735,245 | 3,390,143 | - |
| James C. Johnson | 172,735,312 | 3,390,076 | - |
| Richard A. Liddy | 172,062,753 | 4,062,635 | - |
| Gordon R. Lohman | 172,404,949 | 3,720,439 | - |
| Charles W. Mueller | 172,537,140 | 3,588,248 | - |
| Douglas R. Oberhelman | 171,969,174 | 4,156,214 | - |
| Gary L. Rainwater | 172,095,957 | 4,029,431 | - |
| Harvey Saligman | 172,438,721 | 3,686,667 | - |
| Patrick T. Stokes | 172,621,903 | 3,503,485 | - |
| Jack D. Woodard | 172,727,233 | 3,398,155 | - |
| (a) | Broker shares included in the quorum but not voting on the item. |
| Item (2) | Ameren proposal regarding ratification of the appointment of PricewaterhouseCoopers LLP as Ameren’s independent registered public accountants for the fiscal year ending December 31, 2007. |
For | Against | Abstain | Broker Non-Votes(a) |
| 173,027,701 | 1,298,461 | 1,799,226 | - |
| (a) | Broker shares included in the quorum but not voting on the item. |
| Item (3) | Shareholder proposal requesting a report on releases from UE’s Callaway nuclear plant. |
For | Against | Abstain | Broker Non-Votes(a) |
| 10,401,287 | 106,900,549 | 12,280,634 | 46,542,918 |
| (a) | Broker shares included in the quorum but not voting on the item. |
UE
At UE’s annual meeting of shareholders held on April 24, 2007, the following individuals (comprising UE’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2008: Warner L. Baxter, Daniel F. Cole, Richard J. Mark, Steven R. Sullivan and Thomas R. Voss. Each individual received 102,123,834 votes for election and no withheld votes or broker non-votes.
CIPS
At CIPS’ annual meeting of shareholders held on April 24, 2007, the following individuals (comprising CIPS’ full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2008: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Steven R. Sullivan and Thomas R. Voss. Each individual received 25,452,373 votes for election and no withheld votes or broker non-votes.
CILCO
At CILCO’s annual meeting of shareholders held on April 24, 2007, the following individuals (comprising CILCO’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2008: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Steven R. Sullivan and Thomas R. Voss. Each individual received 13,563,871 votes for election and no withheld votes or broker non-votes.
At IP’s annual meeting of shareholders held on April 24, 2007, the following individuals (comprising IP’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Steven R. Sullivan and Thomas R. Voss. Each individual received 23,662,924 votes for election and no withheld votes or broker non-votes.
GENCO and CILCORP
The information called for by this item is omitted in reliance on General Instruction H(1)(a) and (b) of Form 10-Q.
ITEM 6. EXHIBITS.
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.
Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
Instruments Defining Rights of Securities Holders, Including Indentures |
| 4.1 | Ameren UE | UE Company Order dated June 15, 2007, establishing the 6.40% Senior Secured Notes due 2017 (including the global note) | June 15, 2007 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.2 | Ameren UE | Supplemental Indenture dated June 1, 2007 by and between UE and The Bank of New York, as Trustee under the Indenture of Mortgage and Deed of Trust dated June 15, 1937, as amended, relating to the First Mortgage Bonds, Senior Notes Series KK securing the 6.40% Senior Notes due 2017 | June 15, 2007 Form 8-K, Exhibit 4.5, File No. 1-2967 |
Statement re: Computation of Ratios |
| 12.1 | Ameren | Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges | |
| 12.2 | UE | UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
| 12.3 | CIPS | CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
| 12.4 | Genco | Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges | |
| 12.5 | CILCORP | CILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges | |
| 12.6 | CILCO | CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
| 12.7 | IP | IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
| Rule 13a-14(a) / 15d-14(a) Certifications |
31.1 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren | |
| 31.2 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren | |
| 31.3 | UE | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE | |
| 31.4 | UE | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE | |
| 31.5 | CIPS | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS | |
| 31.6 | CIPS | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS | |
| 31.7 | Genco | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco | |
| 31.8 | Genco | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco | |
| 31.9 | CILCORP | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP | |
| 31.10 | CILCORP | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP | |
| 31.11 | CILCO | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO | |
| 31.12 | CILCO | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO | |
| 31.13 | IP | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP | |
| 31.14 | IP | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP | |
Section 1350 Certifications |
| 32.1 | Ameren | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren | |
| 32.2 | UE | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE | |
| 32.3 | CIPS | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS | |
| 32.4 | Genco | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco | |
| 32.5 | CILCORP | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCORP | |
| 32.6 | CILCO | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO | |
| 32.7 | IP | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP | |
SIGNATURES
Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
AMEREN CORPORATION
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
UNION ELECTRIC COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and
Principal Accounting Officer
(Principal Accounting Officer)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
AMEREN ENERGY GENERATING COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
CILCORP INC.
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
CENTRAL ILLINOIS LIGHT COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
ILLINOIS POWER COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
Date: August 9, 2007
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