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. Dividends on Ameren’s common stock depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.
Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI through UE and Development Company, which each own 40% of EEI. Ameren consolidates EEI for financial reporting purposes, while UE reports EEI under the equity method. The following table presents summarized financial information of EEI for the three months ended March 31, 2007 and 2006.
The financial statements of the Ameren Companies (except CIPS) are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries as applicable. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006.
There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months ended March 31, 2007 and 2006, due to an immaterial number of stock options, restricted stock units and performance share units outstanding.
A summary of nonvested shares as of March 31, 2007, and changes during the quarter ended March 31, 2007, under the Long-term Incentive Plan of 1998, as amended, and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:
The fair value of each share unit awarded in February 2007 under the 2006 Plan was determined to be $59.60 based on Ameren’s closing common share price of $53.99 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 4.735%, dividend yields of 2.3% to 5.2% for the peer group, volatility of 12.91% to 18.33% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.
Ameren recorded compensation expense of $5 million and $2 million for the three-month period ended March 31, 2007 and 2006, respectively, and a related tax benefit of $2 million and $1 million for the three-month period ended March 31, 2007 and 2006, respectively. As of March 31, 2007, total compensation cost of $33 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 3 years.
FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, Ameren may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition of income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties on income taxes, accounting for income taxes in interim periods and requires expanded disclosures.
The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The amount of unrecognized tax benefits as of January 1, 2007, was $155 million, $58 million,
$15 million, $36 million, $18 million, $18 million and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. Of these unrecognized tax benefits on January 1, 2007, $20 million, $6 million, less than $1 million, less than $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, and CILCORP, respectively, would impact the respective company’s effective tax rate, if recognized.
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest and penalties accrued on tax liabilities on a gross basis as interest expense or penalty expense in the statements of income. Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis. As of January 1, 2007, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had recorded a liability of approximately $12 million, $5 million, less than $1 million, $4 million, $1 million, less than $1 million, and less than $1 million, respectively, for the payment of interest with respect to unrecognized tax benefits and no amount for penalties with respect to unrecognized tax benefits.
All of the Ameren Companies’ federal income tax returns are closed through 2001. The Ameren Companies are currently under federal income tax return examination for years 2002 through 2004. State income tax returns are generally subject to examination for a period of three years after filing of the respective return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to
the states. The Ameren Companies do not have state income tax returns in the process of examination. The Ameren Companies also do not have material state income tax issues in the process of administrative appeals or litigation.
The Ameren Companies are not aware of an event that is reasonably possible of occurring that would cause the total amount of unrecognized tax benefits to significantly increase or decrease within twelve months after the date of the Ameren Companies’ adoption of FIN 48.
In February 2007, the FASB issued SFAS No. 159, which permits companies to choose to measure many financial instruments and certain assets and liabilities at fair value that are not currently required to be measured at fair value on an instrument-by-instrument basis. Entities electing the fair value option will be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. SFAS No. 159 is effective as of the beginning of our 2008 fiscal year. We are currently evaluating whether we will elect the fair value option for any of our eligible financial instruments and other items.
The following table presents the net carrying value of emission allowances consumed or (sold) for Ameren, UE, Genco, CILCORP and CILCO during the three months ended March 31, 2007 and 2006.
Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the three months ended March 31, 2007 and 2006:
AROs at Ameren and UE increased compared to December 31, 2006, to reflect the accretion of obligations to their fair values.
Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.
With the expiration of an electric rate moratorium that provided for no changes in UE’s electric rates before July 1, 2006, UE filed in July 2006 a request with the MoPSC for an increase in base rates for electric service. UE’s original filing included a proposed average increase in electric rates of 17.7%, or $361 million based on a requested return on equity of 12.0%. This rate increase filing was based on a test year ended June 30, 2006, and was updated for known and measurable items through January 1, 2007. In December 2006, the MoPSC staff and other stakeholders filed their direct testimony in response to UE’s electric rate increase filing. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million based on a return on equity of 9.75% to 9.0%. The Missouri attorney general recommended a $53 million rate reduction based on a 9.0% return on equity. The Missouri Office of Public Counsel recommended a return on equity of 9.65%.
Subsequently, parties in this rate case have settled certain issues. As a result, UE and the MoPSC staff revised their positions in testimony filed with the MoPSC in April 2007. UE’s revised position is an electric rate increase request of $245 million based on a return on equity of 12.0%, and the MoPSC staff’s revised recommendation is an electric rate reduction of $39 million to $75 million based on a return on equity of 9.75% to 9.0%. The major factors contributing to the difference between the revised UE rate increase request and the MoPSC staff revised rate reduction recommendation include return on equity, depreciation levels, the treatment of a cost-based contract between UE and EEI, which expired in December 2005, margins for interchange sales, and the treatment of emission allowance sales, among other matters. In addition, the MoPSC staff and intervenors have recommended that UE not be granted the right to use a fuel and purchased power cost recovery mechanism.
Evidentiary hearings in this rate case were completed in March 2007. A decision from the MoPSC is expected no later than June 2007.
In March 2007, a stipulation and agreement was approved by the MoPSC, which resolved a July 2006 request by UE to the MoPSC to increase annual natural gas delivery revenues by $11 million. The stipulation and agreement authorized an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. Other principal provisions of the stipulation and agreement include:
Under the Illinois Customer Choice Law, as amended with the consent of the Illinois utilities, CIPS’, CILCO’s and IP’s rates were frozen through January 1, 2007. New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power procurement costs. As a result of these new electric rates going into effect, the estimated average annual residential rate overall increase is expected to be 40% to 55%. The estimated average annual residential rate overall increase for electric heat customers is
expected to be 60% to 80%. The following is a discussion of the current status of significant regulatory and legislative matters affecting our Illinois electric operations.
In February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for power procurement through an ICC-monitored auction, including, among other things, a rate mechanism to pass power supply costs directly through to customers, to take effect after the Illinois electric freeze expired on January 1, 2007 and supply contracts expired on December 31, 2006. The form of power supply would meet the full requirements of each utility, and the risk of fluctuations in power supply requirements would be borne by the supplier. In January 2006, the ICC issued an order that unanimously approved the Ameren Illinois Utilities’ proposed power procurement auction and the related tariffs for use commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to customers.
In accordance with the January 2006 ICC order, the power procurement auction was held at the beginning of September 2006. On September 14, 2006, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. On September 15, 2006, the independent auction manager, NERA Economic Consulting, declared a successful result in the auction for fixed-price customers. The auction clearing price was about $65 per megawatthour for the fixed-price residential and small commercial customers and about $85 per megawatthour for large commercial and industrial customers. Marketing Company was awarded sales in the auction. See Note 7 - Related Party Transactions for a discussion of affiliate power supply agreements. As a result of the high auction clearing price for large commercial and industrial customers, almost all of these customers chose a different supplier.
Certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. Opponents of the power procurement auction and related tariffs claim that the ICC did not have authority to approve market-based rates for electric service that have not been declared “competitive” pursuant to Section 16-113 of the Illinois Customer Choice Law. They further claim that the energy component of CIPS’, CILCO’s and IP’s retail rates for electricity should not be based on the costs to procure energy and capacity in the wholesale market. CIPS, CILCO and IP have received favorable rulings from the ICC and the circuit court of Cook County, Illinois, on opposition claims filed by the Illinois attorney general, CUB and ELPC.
Various parties, including CIPS, CILCO, IP, the Illinois attorney general, CUB, and ELPC, appealed to Illinois district appellate courts the ICC’s denial of rehearing requests with respect to its January 2006 order. Although CIPS, CILCO and IP are generally supportive of the ICC order, they filed a request for rehearing with regard to the provision of the January 2006 order requiring an annual postauction prudence review to be performed by the ICC. In June 2006, the Illinois attorney general filed a petition with the Supreme Court of Illinois seeking a direct and expedited review of appeals filed with Illinois district courts by various parties of the ICC’s January 2006 order approving the Illinois power procurement auction and a stay on implementation of the order. In this petition, the Illinois attorney general raised similar arguments to those discussed above. In August 2006, the Supreme Court of Illinois denied the Illinois attorney general’s petition and ordered that the appeals be consolidated in the appellate court for the Second District in Illinois. The Second District appellate court granted a motion of the Illinois attorney general to dismiss CIPS’, CILCO’s and IP’s appeal regarding the need for an annual postauction prudence review claiming that it was filed prematurely. CIPS, CILCO and IP appealed that decision to the Illinois Supreme Court, where it is now pending. In addition, in December 2006, the Illinois attorney general filed a motion to stay the effectiveness of the retail rates approved by the ICC in its January 2006 order. The motion was denied by the Second District appellate court in December 2006, and upon appeal, denied by the Illinois Supreme Court in January 2007. The Illinois attorney general’s, CUB’s and ELPC’s appeals at the Second District appellate court are still pending.
In March 2007, the Illinois attorney general filed a complaint with FERC against 16 electricity suppliers, including Marketing Company, which are selling power to CIPS, CILCO, IP and Commonwealth Edison Company pursuant to contracts entered into as a result of the September 2006 power procurement auction discussed above. The complaint requests that FERC, among other things, suspend the rates that the power suppliers are charging the Ameren Illinois Utilities and Commonwealth Edison Company and commence a proceeding to determine whether such rates are just and reasonable, and investigate evidence of price manipulation in the power procurement auction; revise the contracts and require refunds of sales at rates that are not just and reasonable; assess civil penalties against power suppliers that violated prohibitions against market manipulation and require any violators to disgorge excess profits and direct certain currently unidentified power suppliers to show cause why their market-based rate authority should not be revoked.
Additionally, Ameren, CIPS, CILCO, IP, Commonwealth Edison Company and its parent company, Exelon
Corporation, and 15 electricity suppliers, including Marketing Company, which are selling power to the Illinois utilities pursuant to contracts entered into as a result of the September 2006 power procurement auction, were named as defendants in two similar class action lawsuits filed in the Circuit Court of Cook County, Illinois in March 2007. The class asserted to be represented by the Commonwealth Edison Company electric customers who filed the complaints are all customers who purchased electric service from Commonwealth Edison Company or the Ameren Illinois Utilities. Both lawsuits allege, among other things, that the Illinois utilities and the power suppliers illegally manipulated prices in the September 2006 power procurement auction. The relief sought in both lawsuits is actual damages to be determined at trial and legal costs, including attorneys’ fees. One of the lawsuits also seeks punitive damages and recovery of illegal profits and excludes the Ameren Illinois Utilities from the requests for relief. In April 2007, the defendants in these lawsuits filed notices removing these cases to the U.S. District Court for the Northern District of Illinois.
CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). In November 2006, the ICC issued an order approving an annual revenue increase for electric delivery service of $97 million in the aggregate (CIPS - $8 million decrease, CILCO - $21 million increase and IP - $84 million increase). The ICC’s order was based on a return on equity of 10.08%, 10.08% and 10.12% for CIPS, CILCO and IP, respectively. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling $50 million, that were disallowed. The administrative law judges rehearing the November 2006 order issued a proposed order in April 2007 recommending no recovery of these expenses by CIPS, CILCO and IP. The ICC’s decision on the recovery of these expenses is due in May 2007. The ICC denied requests for rehearings filed by other parties to this case. Prior to January 2, 2007, most customers of the Ameren Illinois Utilities were taking service under a frozen bundled electric rate, 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.
Electric Rate Increase Phase-in Plan
As a result of the downgrade by Moody's of CIPS', CILCO's and IP's issuer credit ratings to below investment grade (junk) status on March 12, 2007, CIPS, CILCO and IP informed the ICC on March 14, 2007, that the Ameren Illinois Utilities would be unable to offer the $20 million one-time customer bill credit intended to assist high-use residential customers that was initially proposed on March 7, 2007. They also indicated that the Ameren Illinois Utilities would be unable to offer the Customer Elect phase-in plan, including the March 2007 amendment, which would have provided for 0% interest on a deferred portion of customers' bills in excess of a 14% annual increase in electric rates in 2007 through 2009. The Ameren Illinois Utilities also notified the ICC that the $15 million contribution that the utilities announced in 2006 and intended to make to fund energy assistance and energy efficiency initiatives would not be made. As a result, the Ameren Illinois Utilities reversed a $15 million charge in the first quarter of 2007 that was originally recorded in 2006. The Ameren Illinois Utilities took such steps because of the need to fund ongoing utility operations.
Potential Electric Rate Freeze and Recovery of Post-2006 Power Supply Costs
On April 20, 2007, the Illinois Senate approved legislation, known as Senate Bill 1592, that, if enacted into law, would reduce electric rates of CIPS, CILCO and IP to the rates which were in effect prior to January 2, 2007. As passed by the Illinois Senate, Senate Bill 1592 would not impact other Illinois utilities. Senate Bill 1592 provides that the cost of electric energy reflected in the Ameren Illinois Utilities’ electric rates in effect prior to January 2, 2007, cannot be changed for a period of one year after enactment into law. This would prevent 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 power procurement auction discussed above for at least one year after enactment into law, and would cause the Ameren Illinois Utilities to under recover their delivery service costs until the ICC could approve higher delivery service rates. Senate Bill 1592 also includes a requirement for refunds, with interest, of charges collected from customers since January 2, 2007 in excess of the pre-January 2, 2007 rates. If this refund requirement was enacted into law, CIPS, CILCO and IP may have been required to refund approximately $37 million, $21 million, and $49 million, respectively, of such charges collected from customers during the three months ended March 31, 2007. On March 6, 2007, the Illinois House of Representatives approved legislation that would apply to the Ameren Illinois Utilities and Commonwealth Edison Company and which provides for a three-year rate freeze and included a similar refund requirement. To become law in Illinois, legislation must be passed by the House of Representatives and Senate and signed by the Governor. The Governor has previously expressed support for rate rollback and freeze legislation. Despite passage by the Illinois House of Representatives and the Illinois Senate of similar rate rollback
and freeze legislation and statements by the Illinois Governor in support of rate rollback and freeze legislation, it is uncertain whether Senate Bill 1592, the House legislation, or any rate freeze legislation will ultimately be enacted into law.
Ameren, CIPS, CILCORP, CILCO and IP believe that any legislation reducing electric rates to pre-January 2, 2007, levels is unlawful and unconstitutional. In the event that such legislation is enacted into law, the Ameren Illinois Utilities intend to vigorously pursue all available legal actions and strategies to protect their legal and financial interests, including seeking immediate injunctive relief to prevent the implementation of such legislation. The Ameren Illinois Utilities believe that such actions will be successful in both enjoining the implementation of, and ultimately invalidating, such legislation.
Even if efforts to promptly enjoin the implementation of legislation to reduce electric rates to pre-January 2, 2007 levels were successful, Ameren, CIPS, CILCORP, CILCO and IP believe that the mere enactment into law of such legislation would nonetheless result in material adverse consequences to CIPS, CILCORP, CILCO and IP until final resolution of any litigation challenging such legislation. These material adverse consequences would include a significant drop in credit ratings to deep junk (or speculative) status, requirements to post collateral or other assurances for certain obligations, a reduction in access to the capital markets on reasonable terms and higher borrowing costs. These material adverse consequences could also include higher power supply costs, an inability to make timely energy infrastructure investments, disruption in electric and gas service and significant job losses. Consequently, the Ameren Illinois Utilities and CILCORP anticipate that their results of operations, financial position and liquidity would be materially adversely affected. Ameren’s results of operations, financial position and liquidity could also be materially adversely affected.
If legislation to reduce electric rates to pre-January 2, 2007 levels is enacted into law and the implementation of such legislation is not promptly enjoined, Ameren, CIPS, CILCORP, CILCO and IP believe that their results of operations, financial position, and liquidity would be materially adversely affected. Any action, including any legislation to reduce electric rates to pre-January 2, 2007, levels, that impairs the ability of the Ameren Illinois Utilities to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to CIPS, CILCORP, CILCO and IP and, potentially, Ameren. These material adverse consequences would include a significant drop in credit ratings to deep junk (or speculative) status, a severe limitation on their ability to procure reasonable financing from third party lending sources, 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, the likely disruption in electric and gas service, significant job losses, and ultimately the financial insolvency and bankruptcy of CIPS, CILCORP, CILCO and IP.
The Ameren Illinois Utilities, Commonwealth Edison Company and others have been in discussions with members of the Illinois General Assembly and other stakeholders to develop a constructive solution to provide rate relief to Illinois customers in lieu of reducing electric rates to pre-January 2, 2007, levels or applying a tax on electric generation in Illinois. Through discussions with Senate leaders prior to the Senate’s passage of Senate Bill 1592 on April 20, 2007, the Ameren Illinois Utilities, Commonwealth Edison Company and others had agreed to offer more than $150 million in relief to the Illinois electric customers affected most by the rate increases. Over $85 million of electric customer bill credits and other assistance were specifically targeted for the Ameren Illinois Utilities’ customers. The customer assistance proposal was primarily aimed at residential, small business and not-for-profit users, particularly those Ameren Illinois Utilities’ customers who depend on electricity for heating their homes. Those customers, who since January 1, 2007, have absorbed the largest rate increases, had been in line to receive the most benefit from the rate proposal. The Ameren Illinois Utilities were prepared to reinstate their Customer-Elect rate increase phase-in plan capping annual rate increases at 14 percent with no carrying costs on deferred balances. This proposal was not instituted and the Customer-Elect rate increase phase-in plan has not been reinstated because the Illinois General Assembly continued to support rolling back and freezing electric rates at pre-January 2, 2007 levels. The Ameren Illinois Utilities believe that a constructive solution to the current rate situation remains in the best interests of all customers of the Ameren Illinois Utilities, and the Ameren Illinois Utilities remain committed to working with stakeholders to reach such a solution.
Summary
We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, the results of the two class action lawsuits and the Illinois attorney general’s complaint filed with FERC alleging price manipulation in the September 2006 auction, or the actions the Illinois General Assembly and Governor may take that might affect electric rates or the power procurement process for CIPS, CILCO and IP. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences would 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 rate freeze legislation.
Ameren, CIPS, CILCORP, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois Utilities will prevail over the stated opposition by various Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois Utilities are considering will be successful.
Federal
Hydroelectric License Renewal
On March 30, 2007, FERC granted a new 40-year license, subject to rehearing, for UE’s Osage hydroelectric plant and approved a settlement agreement among UE, the U.S. Department of the Interior and various state agencies that was submitted in May 2005 in support of the license renewal.
NOTE 3 - CREDIT FACILITIES AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, commercial paper issuances and drawings under committed bank credit facilities.
The following table summarizes the borrowing activity and relevant interest rates as of March 31, 2007, under the $1.15 billion credit facility and 2007 and 2006 $500 million credit facilities:
$1.15 Billion Credit Facility | Ameren (Parent) | | UE | | Ameren Total | |
March 31, 2007: | | | | | | | | | |
| Average daily borrowings outstanding during 2007 | $ | 96 | | $ | 361 | | $ | 457 | |
| Borrowings outstanding at period end | | - | | | 448 | | | 448 | |
| Weighted-average interest rate during 2007 | | 5.77 | % | | 5.58 | % | | 5.62 | % |
| Peak short-term borrowings during 2007 | $ | 275 | | $ | 448 | | $ | 667 | |
| Peak interest rate during 2007 | | 8.25 | % | | 8.25 | % | | 8.25 | % |
2007 $500 Million Credit Facility | | CIPS | | | CILCORP | | | CILCO (Parent) | | IP | | | AERG | | | Total | |
March 31, 2007: | | | | | | | | | | | | | | | | | | |
| Average daily borrowings outstanding during 2007 | $ | - | | $ | 43 | | $ | - | | $ | 8 | | $ | 29 | | $ | 80 | |
| Borrowings outstanding at period end | | - | | | 104 | | | - | | | 115 | | | 95 | | | 314 | |
| Weighted-average interest rate during 2007 | | - | % | | 6.38 | % | | - | % | | 4.69 | % | | 6.23 | % | | 6.16 | % |
| Peak short-term borrowings during 2007 | $ | - | | $ | 104 | | $ | - | | $ | 115 | | $ | 95 | | $ | 314 | |
| Peak interest rate during 2007 | | - | % | | 8.63 | % | | - | % | | 6.57 | % | | 6.95 | % | | 8.63 | % |
2006 $500 Million Credit Facility | | | | | | | | | | | | | | | | | | |
March 31, 2007: | | | | | | | | | | | | | | | | | | |
| Average daily borrowings outstanding during 2007 | $ | 62 | | $ | 50 | | $ | 66 | | $ | 87 | | $ | 92 | | $ | 357 | |
| Borrowings outstanding at period end | | 100 | | | 50 | | | - | | | 75 | | | 40 | | | 265 | |
| Weighted-average interest rate during 2007 | | 6.44 | % | | 6.75 | % | | 6.25 | % | | 6.36 | % | | 6.93 | % | | 6.56 | % |
| Peak short-term borrowings during 2007 | $ | 115 | | $ | 50 | | $ | 100 | | $ | 110 | | $ | 125 | | $ | 435 | |
| Peak interest rate during 2007 | | 8.25 | % | | 6.75 | % | | 6.40 | % | | 6.57 | % | | 6.98 | % | | 8.25 | % |
At March 31, 2007, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of the three facilities shown above, in the amounts of
$1.15 billion, $500 million and $500 million maturing in July 2010, January 2010 and January 2010, respectively.
The 2007 $500 million credit facility was entered into on February 9, 2007, by CIPS, CILCORP, CILCO, IP and AERG. Borrowing authority under this facility was effective immediately for CILCORP and AERG, and effective for CIPS, CILCO and IP on March 9, 2007, upon the receipt of regulatory approvals.
The obligations of IP under the 2007 $500 million credit facility were secured by the issuance on March 9, 2007, of mortgage bonds in the amount of $200 million. CIPS and CILCO cannot utilize any amount of their borrowing authority under the 2007 $500 million credit facility until they reduce their borrowing authority by an equal amount under the 2006
$500 million credit facility. If CIPS or CILCO elect to transfer borrowing authority from the 2006 $500 million credit facility to the 2007 $500 million credit facility, that company must retire an appropriate amount of first mortgage bonds issued with respect to the 2006 $500 million credit facility and issue new bonds in an equal amount to secure its obligations under the 2007 $500 million credit facility.
The $1.15 billion credit facility was used to support the commercial paper programs that included all outstanding external short-term debt of Ameren and UE as of March 31, 2007. Access to the $1.15 billion credit facility, the 2007 $500 million credit facility and the 2006 $500 million credit facility for the Ameren Companies is subject to reduction as borrowings are made by affiliates. Ameren and UE are currently limited in their access to the commercial paper market as a result of downgrades in their short-term credit ratings.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for operation and administration of the money pool agreements.
Utility
CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. AERG may make loans to, but may not borrow from, the utility money pool. Although UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2007, was 6.1% (2006 - 4.5%).
Non-state-regulated subsidiaries
Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, Ameren Energy and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement subject to applicable regulatory short-term borrowing authorizations. At March 31, 2007, $697 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2007, was 4.7% (2006 - 4.4%).
See Note 7 - Related Party Transactions for the amount of interest income (expense) from the money pool arrangements recorded by the Ameren Companies for the three months ended March 31, 2007 and 2006.
Indebtedness Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 5 - Credit Facilities and Liquidity in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, for a detailed description of those provisions.
The Ameren Companies’ bank credit facilities contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion credit facility contains provisions that limit total indebtedness of each of Ameren, UE and Genco to 65% of consolidated total capitalization pursuant to a calculation defined in the facility. Exceeding these debt levels would result in a default under the $1.15 billion credit facility.
The $1.15 billion credit facility also contains default provisions, including cross defaults, with respect to a borrower under the facility that can result from the occurrence of an event of default under any other facility covering indebtedness of that borrower or certain of its subsidiaries in excess of $50 million in the aggregate. The obligations of Ameren, UE and Genco under the facility are several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS, CILCORP, CILCO, AERG and IP are not considered subsidiaries for purposes of the cross-default or other provisions.
Under the $1.15 billion credit facility, restrictions apply limiting investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries by Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries are excluded for purposes of determining compliance with the 65% total consolidated indebtedness to total consolidated capitalization financial covenant in the facility.
Both the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG, discussed above, limit the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. Events of default under these facilities apply separately to each borrower (and, except in the case of CILCORP, to their subsidiaries), and an event of default under these facilities does not constitute an event of default under the $1.15 billion credit facility and vice versa. In addition, if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below-investment-grade credit rating by either Moody’s or S&P, then such borrower will be limited to capital stock dividend payments of $10 million per year each, while such below-investment-grade credit rating is in effect. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured long-term debt credit rating to below investment-grade, causing it to be subject to this dividend payment limitation. A similar restriction applies to AERG if its debt-to-operating cash flow ratio, as set forth in these facilities, is above a 3.0 to 1.0 ratio. As of March 31, 2007, AERG was in compliance with this test in the 2007 $500 million credit facility and the 2006 $500 million credit facility. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 $500 million or 2006 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG is limited by dividend restrictions at CILCORP.
The 2007 $500 million credit facility and the 2006 $500 million credit facility also limit the amount of other secured indebtedness issuable by each borrower. For CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other secured debt is limited to $425 million under the 2007 $500 million credit facility and $550 million under the 2006 $500 million credit facility, secured by the pledge of CILCO stock. For AERG, other secured debt is limited to $100 million under the 2007
$500 million credit facility and $200 million under the 2006 $500 million credit facility secured on an equal basis with its obligations under the facilities. In addition, the 2007 $500 million credit facility and the 2006 $500 million credit facility prohibit CILCO from issuing any preferred stock if, after giving effect to such issuance, the aggregate liquidation value of all CILCO preferred stock issued after February 9, 2007 and July 14, 2006, respectively, would exceed $50 million.
The 2007 $500 million credit facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures (that is, agree to forego the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture) in the following amounts: CIPS, prior to December 31, 2007 -
$50 million, on and after December 31, 2007, but prior to December 31, 2008 - $100 million, on and after December 31, 2008, but prior to December 31, 2009 - $150 million, on and after December 31, 2009 - $200 million; CILCO, prior to December 31, 2007 - $25 million, on and after December 31, 2007, but prior to December 31, 2008 - $50 million, on and after
December 31, 2008, but prior to December 31, 2009 - $75 million, on and after December 31, 2009 - $150 million; and IP, prior to December 31, 2008 - $100 million, on and after
December 31, 2008, but prior to December 31, 2009 - $200 million, on and after December 31, 2009 - $350 million.
The 2006 $500 million credit facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures in the following amounts: CIPS, prior to December 31, 2007 - $50 million, on and after December 31, 2007, but prior to December 31, 2008 - $100 million, on and after December 31, 2008 - $150 million; CILCO - $25 million; and IP - $100 million.
As of March 31, 2007, the ratio of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility for Ameren, UE and Genco was 50%, 52% and 46%, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2007 $500 million credit facility and 2006 $500 million credit facility, were 52%, 53%, 36%, 44% and 32%, respectively.
None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At March 31, 2007, the Ameren Companies were in compliance with their credit facility provisions and covenants.
NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS
Ameren
Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plans, pursuant to effective SEC Form S-8 registration statements, Ameren issued a total of 0.4 million new shares of common stock valued at $21 million in the three months ended March 31, 2007.
In February 2007, $100 million of Ameren’s 2002 5.70% notes matured and were retired.
CIPS
See Note 3 - Credit Facilities and Liquidity in this report and Note 5 - Credit Facilities and Liquidity in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, regarding mortgage bonds authorized by CIPS as security for its obligations under the 2007 $500 million credit facility and issued under the 2006
$500 million credit facility.
CILCORP
In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $1 million for the three months ended March 31, 2007, (2006 - $1 million) and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and CILCORP. See Note 3 - Credit Facilities and Liquidity in this report and Note 5 - Credit Facilities and Liquidity in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, regarding CILCORP’s pledge of the common stock of CILCO as security for CILCORP’s obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.
CILCO
In January 2007, $50 million of CILCO’s 7.50% first mortgage bonds matured and were retired.
See Note 3 - Credit Facilities and Liquidity in this report and Note 5 - Credit Facilities and Liquidity in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, regarding mortgage bonds authorized by CILCO as security for its obligations under the 2007 $500 million credit facility and issued under the 2006
$500 million credit facility.
IP
In conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $3 million for the three months ended March 31, 2007, (2006 - $3 million) and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and IP.
See Note 3 - Credit Facilities and Liquidity in this report and Note 5 - Credit Facilities and Liquidity in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, regarding mortgage bonds issued by IP as security for its obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.
Indenture Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 6 - Long-term Debt and Equity Financings in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, for a detailed description of those provisions.
UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable based on the 12 months ended March 31, 2007, at an assumed interest and dividend rate of 7%.
| | Required Interest Coverage Ratio(a)(b) | Actual Interest Coverage Ratio | Bonds Issuable(c)(d) | Required Dividend Coverage Ratio(e) | Actual Dividend Coverage Ratio | Preferred Stock Issuable |
| UE | ≥2.0 | 4.7 | $ 2,462 | ≥2.5 | 45.6 | $ 1,466 |
| CIPS | ≥2.0 | 4.2 | 169 | ≥1.5 | 2.4 | 215 |
| CILCO | ≥2.0(f) | 10.5 | 58 | ≥2.5 | 28.8 | 288(g) |
| IP | ≥2.0 | 3.6 | 240 | ≥1.5 | 2.1 | 333 |
(a) Coverage required on the annual interest charges on mortgage bonds outstanding and to be issued.
(b) Coverage is not required in certain cases when additional mortgage bonds are issued on the basis of retired bonds.
| (c) | Amount of bonds issuable based on either meeting required coverage ratios or unfunded property additions, whichever is more restrictive. In addition to these tests, UE, CIPS, CILCO and IP have the ability to issue bonds based upon retired bond capacity of $18 million, $3 million, $175 million, and $914 million, respectively, for which no earnings coverage test is required. |
| (d) | Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by these companies. See Note 3 - Credit Facilities and Liquidity for further discussion. |
| (e) | Coverage required on the annual interest charges on all long-term debt (CIPS-only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance. |
| (f) | In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all mortgage bonds outstanding and to be issued. For the three months ended March 31, 2007, CILCO had earnings equivalent to at least 40% of the principal amount of all mortgage bonds outstanding. |
| (g) | See Note 3 - Credit Facilities and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the 2007 $500 million credit facility and the 2006 $500 million credit facility. |
UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.7 billion of free and unrestricted retained earnings at March 31, 2007.
Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended March 31, 2007:
| | Required Interest Coverage Ratio | Actual Interest Coverage Ratio | Required Debt-to- Capital Ratio | Actual Debt-to- Capital Ratio |
Genco (a) | ≥1.75(b) | 5.3 | ≤60% | 45% |
CILCORP(c) | ≥2.2 | 2.9 | ≤67% | 32% |
| (a) | Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt-to-capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters. |
| (b) | Ratio excludes amounts payable under Genco’s intercompany note to CIPS and must be met for both the prior four fiscal quarters and for the four succeeding six-month periods. |
| (c) | CILCORP must maintain the required interest coverage ratio and debt-to-capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than to its direct or indirect subsidiaries. |
Genco’s ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. In the event CILCORP is not in compliance with these restrictions, CILCORP may make payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At March 31, 2007, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were B+, Ba2, and BB+, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and credit facility obligations.
In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At March 31, 2007, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
NOTE 5 - OTHER INCOME AND EXPENSES
The following table presents Other Income and Expenses for each of the Ameren Companies for the three months ended March 31, 2007 and 2006:
| | Three Months | |
| | 2007 | | 2006 | |
Ameren:(a) | | | | | | |
| Miscellaneous income: | | | | | | |
Interest and dividend income | $ | 14 | | $ | 1 | |
Allowance for equity funds used during construction | | - | | | 1 | |
Other | | 2 | | | 2 | |
Total miscellaneous income | $ | 16 | | $ | 4 | |
UE: | | | | | | |
| Miscellaneous income: | | | | | | |
Interest and dividend income | $ | 10 | | $ | 1 | |
Allowance for equity funds used during construction | | - | | | 1 | |
Other | | - | | | 1 | |
Total miscellaneous income | $ | 10 | | $ | 3 | |
| Miscellaneous expense: | | | | | | |
Other | $ | (2 | ) | $ | (2 | ) |
Total miscellaneous expense | $ | (2 | ) | $ | (2 | ) |
CIPS: | | | | | | |
| Miscellaneous income: | | | | | | |
Interest and dividend income | $ | 3 | | $ | 4 | |
Other | | - | | | 1 | |
| Total miscellaneous income | $ | 3 | | $ | 5 | |
| Three Months |
| | | 2007 | | | 2006 | |
| Miscellaneous expense: | | | | | | |
Other | $ | - | | $ | (1 | ) |
| Total miscellaneous expense | $ | - | | $ | (1 | ) |
CILCORP: | | | | | | |
| Miscellaneous income: | | | | | | |
Interest and dividend income | $ | 2 | | $ | - | |
| Total miscellaneous income | $ | 2 | | $ | - | |
| Miscellaneous expense: | | | | | | |
Other | $ | (1 | ) | $ | (1 | ) |
| Total miscellaneous expense | $ | (1 | ) | $ | (1 | ) |
CILCO: | | | | | | |
| Miscellaneous income: | | | | | | |
Interest and dividend income | $ | 1 | | $ | - | |
| Total miscellaneous income | $ | 1 | | $ | - | |
| Miscellaneous expense: | | | | | | |
Other | $ | (1 | ) | $ | (1 | ) |
| Total miscellaneous expense | $ | (1 | ) | $ | (1 | ) |
IP: | | | | | | |
| Miscellaneous income: | | | | | | |
Interest and dividend income | $ | 1 | | $ | - | |
Other | | 1 | | | 1 | |
| Total miscellaneous income | $ | 2 | | $ | 1 | |
| Miscellaneous expense: | | | | | | |
Other | $ | (1 | ) | $ | (1 | ) |
| Total miscellaneous expense | $ | (1 | ) | $ | (1 | ) |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS
The pretax net gain or loss on power hedges is included in Operating Revenues - Electric, and the pretax net gain or loss on hedges related to SO2 emission allowances, fuel or power supply, and natural gas is included in Operating Expenses - Fuel and Purchased Power. This pretax net gain or loss represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions being delivered or settled, resulting in a $7 million gain for Ameren, a $5 million gain for UE, and a $2 million loss for CILCO for the quarter ended March 31, 2007 (2006 - $3 million loss for Ameren, $1 million loss for Genco and a $2 million loss for IP).
The following table presents the carrying value of all derivative instruments and the amount of pretax net gains (losses) on derivative instruments in Accumulated OCI for cash flow hedges as of March 31, 2007:
| | Ameren(a) | | UE | | CIPS | | Genco | | CILCORP/ CILCO | | IP | |
| Derivative instruments carrying value: | | | | | | | | | | | | | | | | | | |
Other assets | $ | 51 | | $ | 4 | | $ | 5 | | $ | - | | $ | 11 | | $ | - | |
Other deferred credits and liabilities | | 20 | | | 4 | | | 2 | | | 1 | | | 5 | | | - | |
| Gains (losses) deferred in Accumulated OCI: | | | | | | | | | | | | | | | | | | |
Power forwards(b) | | 17 | | | (4 | ) | | - | | | - | | | - | | | - | |
Interest rate swaps(c) | | 3 | | | - | | | - | | | 3 | | | - | | | - | |
Gas swaps and futures contracts(d) | | 11 | | | 2 | | | 3 | | | - | | | 7 | | | - | |
SO2 futures contracts | | (1 | ) | | - | | | - | | | (1 | ) | | - | | | - | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including $15 million over the next year. |
| (c) | Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002. |
| (d) | Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2008. |
Other Derivatives
The following table presents the net change in market value for the three months ended March 31, 2007 and 2006, of option and swap transactions used to manage our positions in SO2 allowances, coal and heating oil. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The net change in the market value of SO2, coal and heating oil options and swaps is recorded as Operating Expenses - Fuel and Purchased Power.
| | Three Months | |
Gains (Losses) | 2007 | | 2006 | |
SO2 options and swaps: | | | | | | |
Ameren | $ | 4 | | $ | (1 | ) |
UE | | 4 | | | 3 | |
Genco | | - | | | (3 | ) |
CILCORP/CILCO | | - | | | (1 | ) |
Coal options: | | | | | | |
Ameren | | 1 | | | - | |
UE | | 1 | | | - | |
Heating oil: | | | | | | |
Ameren | | 3 | | | - | |
NOTE 7 - RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 13 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Below are updates to several of these related party agreements.
Electric Power Supply Agreements
The following table presents the amount of gigawatthour sales under related party electric power supply agreements for the three months ended March 31, 2007 and 2006:
| | Three Months | |
| | 2007 | | 2006 | |
Genco sales to Marketing Company(a) | | - | | | 5,591 | |
Marketing Company sales to CIPS(a) | | - | | | 3,079 | |
Genco sales to Marketing Company(b) | | 4,119 | | | - | |
AERG sales to Marketing Company(c) | | 1,488 | | | - | |
Marketing Company sales to CIPS(d) | | 619 | | | - | |
Marketing Company sales to CILCO(d) | | 288 | | | - | |
Marketing Company sales to IP(d) | | 826 | | | - | |
| (a) | These agreements expired or terminated on December 31, 2006. |
| (b) | In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco sells and Marketing Company purchases all the capacity available from Genco’s generation fleet and such amount of associated energy commencing on January 1, 2007. |
| (c) | In December 2006, AERG and Marketing Company entered into a power supply agreement (AERG PSA) whereby AERG sells and Marketing Company purchases all the capacity available from AERG’s generation fleet and such amount of associated energy commencing on January 1, 2007. |
| (d) | In accordance with the January 2006 ICC order, discussed in Note 2 - Rate and Regulatory Matters, an auction was held in September 2006 to procure power for CIPS, CILCO and IP after their previous power supply contracts expired on December 31, 2006. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for their customers. See also Note 3 - Rate and Regulatory Matters under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006 for further details of the power procurement auction in Illinois. |
Joint Dispatch Agreement
UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement of the JDA and agreed to terminate it on December 31, 2006. This action with respect to the JDA was accepted by FERC in September 2006.
For the three months ended March 31, 2006, UE sales to Genco under the JDA were 2,795 gigawatthours, and Genco sales to UE under the JDA were 606 gigawatthours. Also for the three months ended March 31, 2006, the short-term power sales margins under the JDA for UE and Genco were $33 million and $12 million, respectively.
Money Pools
See Note 3 - Credit Facilities and Liquidity for discussion of affiliate borrowing arrangements.
Intercompany Promissory Notes
Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $3 million for the three months ended March 31, 2007 (2006 - $4 million).
CILCORP has been granted authority by FERC in a 2006 order to borrow up to $250 million directly from Ameren. The outstanding borrowings were zero and $191 million at March 31, 2007 and 2006, respectively. The average interest rate on these borrowings was 6.1% for the three months ended March 31, 2007 (2006 - 4.4%). CILCORP recorded interest expense of less than $1 million for these borrowings for the three months ended March 31, 2007 (2006 - $2 million).
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three months ended March 31, 2007 and 2006. It is based primarily on the agreements discussed above and in Note 13 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, and the money pool arrangements discussed above in Note 3 - Credit Facilities and Liquidity of this report.
Agreement | Financial Statement Line Item | | | | UE | | | CIPS | | | Genco | | CILCORP(a) | | IP | |
| | | | | | | | | | | | | | | | | | | | |
Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Genco and AERG power supply | Operating Revenues | | 2007 | | $ | (b | ) | $ | (b | ) | $ | 211 | | $ | 72 | | $ | (b | ) |
| agreements with Marketing Company | | | | | | |
| Ancillary service agreement with CIPS, | Operating Revenues | | 2007 | | | 4 | | | (b | ) | | (b | ) | | (b | ) | | (b | ) |
| CILCO and IP | | | | | |
| Power supply agreement with Marketing | Operating Revenues | | 2006 | | | (b | ) | | 2 | | | 195 | | | 4 | | | (b | ) |
| Company - expired December 31, 2006 |
| UE and Genco gas Transportation | Operating Revenues | | 2007 | | | (c | ) | | (b | ) | | (b | ) | | (b | ) | | (b | ) |
| agreement | | 2006 | | | (c | ) | | (b | ) | | (b | ) | | (b | ) | | (b | ) |
| JDA - terminated December 31, 2006 | Operating Revenues | | 2006 | | | 72 | | | (b | ) | | 19 | | | (b | ) | | (b | ) |
Total Operating Revenues | | | | 2007 | | $ | 4 | | $ | (b | ) | $ | 211 | | $ | 72 | | $ | (b | ) |
| | | | | 2006 | | | 72 | | | 2 | | | 214 | | | 4 | | | | |
Fuel and Purchased Power: | | | | | | | | | | | | | | | | | | | | |
| CIPS, CILCO and IP agreements with | Fuel and Purchased Power | | 2007 | | $ | (b | ) | $ | 42 | | $ | (b | ) | $ | 19 | | $ | 55 | |
| Marketing Company (auction) | | | | | | | | | | | | | | | | | | | | | |
| Ancillary service agreement with UE | Fuel and Purchased Power | | 2007 | | | (b | ) | | 1 | | | (b | ) | | 1 | | | 2 | |
| Ancillary service agreement with Marketing | Fuel and Purchased Power | | 2007 | | | (b | ) | | 1 | | | (b | ) | | (c | ) | | 1 | |
| Company |
| JDA - terminated December 31, 2006 | Fuel and Purchased Power | | 2006 | | | 19 | | | (b | ) | | 72 | | | (b | ) | | (b | ) |
| Power supply agreement with Marketing | Fuel and Purchased Power | | 2006 | | | (b | ) | | 108 | | | (b | ) | | (d | ) | | (b | ) |
| Company - expired December 31, 2006 | |
| Executory tolling agreement with Medina | Fuel and Purchased Power | | 2007 | | | (b | ) | | (b | ) | | (b | ) | | 12 | | | (b | ) |
| Valley | | | | | | 2006 | | | (b | ) | | (b | ) | | (b | ) | | 13 | | | (b | ) |
| UE and Genco gas transportation | Fuel and Purchased Power | | 2007 | | | (b | ) | | (b | ) | | (c | ) | | (b | ) | | (b | ) |
| agreement | | | �� | | | 2006 | | | (b | ) | | (b | ) | | (c | ) | | (b | ) | | (b | ) |
Total Fuel and Purchased Power | | | | | | 2007 | | $ | (b | ) | $ | 44 | | $ | (c | ) | $ | 32 | | $ | 58 | |
| | | | | 2006 | | | 19 | | | 108 | | | 72 | | | 13 | | | (b | ) |
Other Operating Expense: | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Services support services agreement | Other Operating Expenses | | 2007 | | $ | 36 | | $ | 12 | | $ | 6 | | $ | 13 | | $ | 19 | |
| | | | | | | 2006 | | | 33 | | | 11 | | | 5 | | | 12 | | | 17 | |
| Ameren Energy support services agreement | Other Operating Expenses | | 2007 | | | 3 | | | (b | ) | | (c | ) | | (b | ) | | (b | ) |
| | | | | | | 2006 | | | 2 | | | (b | ) | | 1 | | | (b | ) | | (b | ) |
| AFS support services agreement | Other Operating Expenses | | 2007 | | | 2 | | | (c | ) | | 1 | | | 1 | | | (c | ) |
| | | | | | | 2006 | | | 1 | | | (c | ) | | 1 | | | (c | ) | | 1 | |
| Insurance premiums | Other Operating Expenses | | 2007 | | | 4 | | | (b | ) | | 1 | | | (c | ) | | (b | ) |
Total Other Operating Expenses | | | | | | 2007 | | $ | 45 | | $ | 12 | | $ | 8 | | $ | 14 | | $ | 19 | |
| | | | | | | 2006 | | | 36 | | | 11 | | | 7 | | | 12 | | | 18 | |
Agreement | Financial Statement Line Item | | | UE | | CIPS | | Genco | | CILCORP(a) | | IP | |
| | | | | | | | | | | | | | | | | | | | |
| Money pool borrowings (advances) | Interest (Expense) | | 2007 | | $ | - | | $ | (c | ) | $ | 2 | | $ | (c | ) | $ | (c | ) |
| | Income | | 2006 | | | - | | | (c | ) | | 2 | | | 2 | | | 1 | |
| (a) | Amounts represent CILCORP and CILCO activity. |
| (c) | Amount less than $1 million. |
NOTE 8 - COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the course of daily business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have 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 Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters and Note 7 - Related Party Transactions in this report.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at March 31, 2007. The property coverage was renewed on October 1, 2006. The nuclear liability coverage anniversary was January 1, 2007.
Type and Source of Coverage | Maximum Coverages | Maximum Assessments for Single Incidents |
| Public liability: | | | | | | |
American Nuclear Insurers | $ | 300 | | $ | - | |
Pool participation | | 10,461 | | | 101 | (a) |
| $ | 10,761 | (b) | $ | 101 | |
| Nuclear worker liability: | | | | | | |
American Nuclear Insurers | $ | 300 | (c) | $ | 4 | |
| Property damage: | | | | | | |
| Nuclear Electric Insurance Ltd. | $ | 2,750 | (d) | $ | 24 | |
| Replacement power: | | | | | | |
Nuclear Electric Insurance Ltd. | $ | 490 | (e) | $ | 9 | |
(a) | Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $15 million per year. |
| (b) | Limit of liability for each incident under Price-Anderson. |
| (c) | Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation. |
| (d) | Includes premature decommissioning costs. |
| (e) | Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter. |
Price-Anderson limits the liability for claims from an incident involving any licensed United States 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.
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.
Other Obligations
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. 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 Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006.
As of March 31, 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 March 31, 2007:
| | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | Thereafter(a) | |
Ameren(b) | $ | 558 | | $ | 483 | | $ | 326 | | $ | 219 | | $ | 197 | | $ | 1,960 | |
| UE | | 72 | | | 65 | | | 46 | | | 29 | | | 25 | | | 56 | |
| CIPS | | 104 | | | 111 | | | 73 | | | 53 | | | 38 | | | 69 | |
| Genco | | 24 | | | 20 | | | 8 | | | 8 | | | 8 | | | 13 | |
| CILCORP/CILCO | | 134 | | | 131 | | | 80 | | | 46 | | | 55 | (c) | | 839 | (c) |
| IP | | 213 | | | 152 | | | 118 | | | 82 | | | 69 | (c) | | 983 | |
| (a) | Commitments for natural gas are until 2017. |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (c) | Commitments for natural gas purchases for CILCO and IP include projected synthetic natural gas purchases pursuant to a 20-year supply contract beginning in April 2011. |
As of March 31, 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 March 31, 2007:
| | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | Thereafter(a) |
| Ameren | $ | 49 | | $ | 51 | | $ | 37 | | $ | 113 | | $ | 33 | | $ | 139 | |
| UE | | 49 | | | 51 | | | 37 | | | 113 | | | 33 | | | 139 | |
| (a) | Commitments for nuclear fuel are until 2020. |
Environmental Matters
We are subject to various environmental laws and regulations by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, 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.
Clean Air Act
In May 2005, the EPA issued final regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule) from coal-fired power plants. The new rules require significant reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. States are required to finalize rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule. Although the federal rules mandate a specific cap for SO2, NOx and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and it may implement a more stringent program than the federal program. Illinois has enacted rules to implement the federal Clean Air Interstate Rule program that will reduce the number of NOx allowances automatically allocated to Genco’s, AERG’s and EEI’s plants; however it is anticipated that the rules will not be finalized until the third quarter of 2007. As a result of the Illinois rules, Genco, AERG and EEI would need to procure allowances and install pollution control equipment in order to continue to operate.
The Missouri Department of Natural Resources formally proposed rules to implement the federal Clean Air Mercury and Clean Air Interstate Rules in November 2006. These rules substantially follow the federal rules. The Missouri Air Conservation Commission approved the rules at their February 2007 meeting. The rules became effective after publication in the Missouri Register in April 2007 by the EPA. When fully implemented, it is estimated that these rules will reduce mercury emissions 81% by 2018 and reduce NOx emissions 30% and SO2 emissions 75% by 2015.
Illinois has adopted rules for mercury that are significantly stricter than the federal rules. In 2006, Genco,
CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls Genco, AERG and EEI will begin installing equipment designed to reduce mercury emissions in 2009. When fully implemented, it is estimated that these rules will reduce mercury emissions 90%, NOx emissions 50% and SO2 emissions 70% by 2015 in Illinois.
The table below presents estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air Mercury Rule through 2016 and related state implementation plans. The estimates described below could change depending upon additional federal or state requirements, new technology, variations in costs of material or labor or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with the proposed rules, thereby deferring capital investment.
| | 2007 | 2008 - 2011 | 2012 - 2016 | Total |
UE(a) | $ 110 | $ 630- 830 | $ 910-1,180 | $ 1,650-2,120 |
| Genco | 110 | 820-1,060 | 180- 260 | 1,110-1,430 |
| CILCO (AERG) | 100 | 185- 240 | 95- 140 | 380- 480 |
| EEI | 10 | 185- 240 | 165- 220 | 360- 470 |
| Ameren | $ 330 | $ 1,820-2,370 | $ 1,350-1,800 | $ 3,500-4,500 |
| (a) | UE’s expenditures are expected to be recoverable in rates over time. |
Illinois and Missouri must also develop attainment plans to meet the federal eight-hour ozone ambient standard by June 2007 and the federal fine particulate ambient standard by April 2008. The costs in the table assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet this new standard in the St. Louis region. Should Missouri develop an alternative plan to comply with this standard, the cost impact could be material to UE. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for ozone and fine particulate. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.
Emission Allowances
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program created marketable commodities called allowances. Currently each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program has applied to all electric generating units in Illinois since the beginning of 2004; it was applied to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low-NOx burners, over-fire air systems, combustion optimization, rich-reagent injection, selective noncatalytic reduction, and selective catalytic reduction systems.
The following table presents the SO2 and NOx emission allowances held and the related SO2 and NOx book values that are carried as intangible assets as of March 31, 2007.
| | SO2 (a) | NOx (b) | | Book Value | |
| UE | | 1.666 | | 15,667 | | $ | 57 | |
| Genco | | 0.647 | | 16,233 | | | 66 | |
| CILCO (AERG) | | 0.307 | | 4,198 | | | 1 | |
| EEI | | 0.306 | | 5,594 | | | 9 | |
| Ameren | | 2.926 | | 41,692 | | | 210 | (c) |
| (a) | Vintages are from 2007 to 2016. Each company possesses additional allowances for use in periods beyond 2016. Units are in millions of SO2 allowances (currently one allowance equals one ton emitted). |
| (b) | Vintages are from 2007 to 2008. Units are in NOx allowances (one allowance equals one ton emitted). |
| (c) | Includes value assigned to AERG and EEI allowances as a result of purchase accounting of $77 million. |
The following table presents the distribution by company and year of the NOx emission allowances that were allocated by the Illinois EPA in September 2006, for 2007 and 2008.
| | 2007(a) | | 2008(a) | |
| UE | | 156 | | | 130 | |
| Genco | | 4,656 | | | 4,679 | |
| CILCO (AERG) | | 2,052 | | | 2,053 | |
| EEI | | 2,746 | | | 2,713 | |
| Ameren | | 9,610 | | | 9,575 | |
| (a) | These NOx allowances are included in the total allowances table above. Units are in NOx allowances (one allowance equals one ton emitted). |
Allocations of NOx allowances for UE’s Missouri generating facilities will be 10,166 allowances per emissions season in 2007 and 2008. In addition, UE expects to receive 4,081 allowances from the compliance supplement pool for early NOx emission reductions.
UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment and the level of operations will have a significant impact on the amount of allowances actually
required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. The Clean Air Interstate Rule program will require that SO2 allowances be surrendered at a ratio of two allowances for every ton of emission in 2010 through 2014. Beginning in 2015, the Clean Air Interstate Rule program will require SO2 allowances to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG and EEI expect to install control technology designed to further reduce SO2 emissions.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming are the subjects of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Coal-fired power plants are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity from the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including enhanced generation at our nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.
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 cars 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 greenhouse gas 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.
New Source Review
The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review (NSR) requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were performed.
In April 2007, the U.S. Supreme Court in Environmental Defense v. Duke Energy Corp., issued a decision which effectively reduced the statutory defenses available to NSR and Prevention of Significant Deterioration (PSD) claims. The key issue before the Supreme Court was whether EPA requirements to obtain permits under the NSR and PSD programs are triggered when a “modification” at an industrial facility results in an increase in an hourly emissions rate, as upheld by the U.S. Court of Appeals for the Fourth Circuit, or in total annual emissions, as asserted by environmental groups. The U.S. Supreme Court found that the NSR and PSD regulations can be triggered by either an hourly or annual increase in the emissions. The Supreme Court decision did not address other potential defenses or potential exceptions under the NSR and PSD programs.
In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. We are currently in discussions with the EPA and interested stakeholders regarding resolution of these matters, but we are unable to predict the outcome of these discussions.
Remediation
We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of degree of fault, legality of original disposal, or ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.
As of March 31, 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 March 31, 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 March 31, 2007, UE had recorded $7 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 March 31, 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 March 31, 2007, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.
In addition, our operations, or those of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our results of operations, financial position, or liquidity.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. At the FERC’s direction, outside experts were hired by UE to review the cause of the incident. Their reports and reports by FERC staff indicated design, construction, and human error as causes of the breach. In their report, UE’s outside experts concluded that restoration of the upper reservoir, if undertaken, will require a complete rebuild of the entire dam with a completely different design concept, not simply a repair of the breached area. FERC agreed with this conclusion and rejected repair as an option.
The FERC investigation of the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation that the FERC’s Office of Enforcement conducted into alleged violations of license conditions and FERC regulations by UE as the licensee of the Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply with a new dam safety program developed in connection with the settlement.
In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk Plant, assuming successful resolution of
outstanding issues with authorities of the state of Missouri. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer.
UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all damages and liabilities (but not penalties) caused by the breach, plus the cost of rebuilding the plant, will be covered by insurance. UE expects the total cost for clean up, damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $137 million to $157 million. As of March 31, 2007, UE had paid $76 million and accrued a $61 million liability, including costs resulting from the FERC-approved stipulation and consent agreement discussed above, while expensing $30 million and recording a $107 million receivable due from insurance companies. As of March 31, 2007, UE has received $30 million from insurance companies, which reduced the insurance receivable balance to $77 million. As of March 31, 2007, UE had a $10 million receivable due from insurance companies related to rebuilding the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.
In December 2006, the state of Missouri through its attorney general and 10 business owners filed separate lawsuits regarding the Taum Sauk breach. The attorney general’s suit, which was originally filed in the Missouri circuit court in St. Louis, and subsequently transferred to the Missouri circuit court in Reynolds County, alleges negligence, violations of the Missouri Clean Water Act and various other statutory and common law claims. The business owners’ suit, which was filed in the Missouri circuit court in Reynolds County, contains similar allegations and seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages. In January 2007, the Missouri Department of Natural Resources filed a petition to intervene as a plaintiff in the attorney general’s lawsuit.
Until the reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, a final decision about whether the plant will be rebuilt is made, and future regulatory treatment for the facility is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the circuit court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 188 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of March 31, 2007, the average number of parties was 70.
The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS or CILCO has contractually agreed to indemnify Genco or AERG for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if awarded, typically would be shared among the named defendants.
From January 1, 2007, through March 31, 2007, seven additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the circuit court of Madison County, Illinois. Four lawsuits were dismissed and two were settled. The following table presents the status as of March 31, 2007, of the asbestos-related lawsuits that have been filed against the Ameren Companies:
| | | | Specifically Named as Defendant | |
| | Total(a) | | | Ameren | | | UE | | | CIPS | | | Genco | | | CILCO | | | IP | |
| Filed | | 327 | | | 31 | | | 181 | | | 138 | | | 2 | | | 45 | | | 158 | |
| Settled | | 107 | | | - | | | 53 | | | 44 | | | - | | | 14 | | | 53 | |
| Dismissed | | 151 | | | 26 | | | 98 | | | 51 | | | 2 | | | 9 | | | 69 | |
| Pending | | 69 | | | 5 | | | 30 | | | 43 | | | - | | | 22 | | | 36 | |
| (a) | Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants. |
As of March 31, 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.
The ICC order approving Ameren’s acquisition of IP effective September 30, 2004, also approved a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP 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.
NOTE 9 - CALLAWAY NUCLEAR PLANT
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2017. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.
Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. It is assumed that the Callaway nuclear plant site will be decommissioned based on immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2006, 2005 and 2004. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 2005. Minor tritium contamination was discovered on the Callaway nuclear plant site in the summer of 2006. Existing facts and regulatory requirements indicate that this discovery will not cause any significant increase in a decommissioning cost estimate when the next study is conducted. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset.
NOTE 10 - OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders’ equity, except those resulting from transactions with common shareholders. A reconciliation of net income to comprehensive income for the three months ended March 31, 2007 and 2006, is shown below for the Ameren Companies:
| | Three Months | |
| | 2007 | | 2006 | |
Ameren:(a) | | | | | | |
| Net income | $ | 123 | | $ | 70 | |
| Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $(15) and $(11), respectively | | (28 | ) | | (17 | ) |
| Reclassification adjustments for (gain) included in net income, net of taxes of $7 and $2, respectively | | (13 | ) | | (3 | ) |
Adjustment to pension and benefit obligation, net of taxes of $1 and $-, respectively | | 2 | | | - | |
Total comprehensive income, net of taxes | $ | 84 | | $ | 50 | |
UE: | | | | | | |
Net income | $ | 38 | | $ | 51 | |
| Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $(3) and $(2), respectively | | (5 | ) | | (3 | ) |
Reclassification adjustments for (gain) included in net income, net of taxes of $2 and $-, respectively | | (3 | ) | | - | |
Total comprehensive income, net of taxes | $ | 30 | | $ | 48 | |
| | Three Months |
| | | 2007 | | | 2006 | |
CIPS: | | | | | | |
Net income (loss) | $ | 11 | | $ | (1 | ) |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $- and $(2), respectively | | 1 | | | (3 | ) |
Reclassification adjustments for (gain) included in net income, net of taxes of $- and $1, respectively | | - | | | (1 | ) |
Total comprehensive income (loss), net of taxes | $ | 12 | | $ | (5 | ) |
Genco: | | | | | | |
Net income | $ | 43 | | $ | 6 | |
| Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $(1) and $-, respectively | | (2 | ) | | - | |
Reclassification adjustments for loss included in net income, net of taxes of $- and $-, respectively | | - | | | 1 | |
Adjustment to pension and benefit obligation, net of taxes of $- and $-, respectively | | 1 | | | - | |
Total comprehensive income, net of taxes | $ | 42 | | $ | 7 | |
CILCORP: | | | | | | |
Net income | $ | 20 | | $ | 8 | |
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $2 and $(8), respectively | | 3 | | | (11 | ) |
| Reclassification adjustments for (gain) included in net income, net of taxes of $2 and $-, respectively | | (3 | ) | | - | |
Adjustment to pension and benefit obligation, net of taxes of $- and $-, respectively | | 1 | | | - | |
Total comprehensive income (loss), net of taxes | $ | 21 | | $ | (3 | ) |
CILCO: | | | | | | |
Net income | $ | 26 | | $ | 17 | |
| Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $2 and $(8), respectively | | 3 | | | (11 | ) |
Reclassification adjustments for (gain) included in net income, net of taxes of $2 and $-, respectively | | (3 | ) | | - | |
Total comprehensive income, net of taxes | $ | 26 | | $ | 6 | |
IP: | | | | | | |
Net income | $ | 13 | | $ | 4 | |
Unrealized (loss) on derivative hedging instruments, net of taxes of $- and $2, respectively | | - | | | 3 | |
| Reclassification adjustments for loss included in net income, net of taxes of $- and $2, respectively | | - | | | (3 | ) |
Total comprehensive income, net of taxes | $ | 13 | | $ | 4 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
NOTE 11 - RETIREMENT BENEFITS
Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. Based on our assumptions at December 31, 2006, and the new contribution requirements in the Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009, at which time we would expect a required contribution of $100 million to $150 million. Required contributions of $150 million to $200 million each year are also expected for 2010 and 2011. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months ended March 31, 2007 and 2006:
| | Pension Benefits(a) | | Postretirement Benefits(a) | |
| | 2007 | | 2006 | | 2007 | | 2006 | |
| Service cost | $ | 16 | | $ | 16 | | $ | 6 | | $ | 6 | |
| Interest cost | | 45 | | | 43 | | | 19 | | | 18 | |
| Expected return on plan assets | | (52 | ) | | (49 | ) | | (13 | ) | | (12 | ) |
| Amortization of: | | | | | | | | | | | | |
Prior service cost | | 3 | | | 2 | | | (2 | ) | | (1 | ) |
Actuarial loss | | 6 | | | 11 | | | 7 | | | 10 | |
| Net periodic benefit cost | $ | 18 | | $ | 23 | | $ | 17 | | $ | 21 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
UE, CIPS, Genco, CILCORP, CILCO and IP 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 ended March 31, 2007 and 2006:
| | Pension Costs | | Postretirement Costs | |
| | 2007 | | 2006 | | 2007 | | 2006 | |
| Ameren | $ | 18 | | $ | 23 | | $ | 17 | | $ | 21 | |
| UE | | 10 | | | 13 | | | 9 | | | 11 | |
| CIPS | | 2 | | | 3 | | | 2 | | | 2 | |
| Genco | | 1 | | | 2 | | | 1 | | | 1 | |
CILCORP(a) | | 3 | | | 3 | | | 2 | | | 3 | |
| IP | | 2 | | | 2 | | | 3 | | | 4 | |
| (a) | CILCORP includes CILCO. |
NOTE 12 - SEGMENT INFORMATION
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI 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.
CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO comprises the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. Other for CILCORP and CILCO comprises leveraged lease investments, parent company activity, and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.
The following table presents information about the reported revenues and net income of Ameren for the three months ended March 31, 2007 and 2006, and total assets as of March 31, 2007 and December 31, 2006.
| | Missouri Regulated | | Illinois Regulated | | Non-rate-regulated Generation | | Other | | Intersegment Eliminations | | Consolidated | |
2007: | | | | | | | | | | | | | | | | | | |
| External revenues | $ | 638 | | $ | 1,054 | | $ | 318 | | $ | 9 | | $ | - | | $ | 2,019 | |
| Intersegment revenues | | 12 | | | 7 | | | 133 | | | 10 | | | (162 | ) | | - | |
Net income(a) | | 23 | | | 29 | | | 70 | | | 1 | | | - | | | 123 | |
2006: | | | | | | | | | | | | | | | | | | |
| External revenues | $ | 558 | | $ | 984 | | $ | 239 | | $ | 19 | | $ | - | | $ | 1,800 | |
| Intersegment revenues | | 78 | | | 2 | | | 191 | | | 12 | | | (283 | ) | | - | |
Net income (loss)(a) | | 35 | | | 9 | | | 27 | | | (1 | ) | | - | | | 70 | |
As of March 31, 2007: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 10,269 | | $ | 6,234 | | $ | 3,796 | | $ | 1,024 | | $ | (1,697 | ) | $ | 19,626 | |
As of December 31, 2006: | | | | | | | | | | | | | | | | | | |
| Total assets | | 10,251 | | | 6,226 | | | 3,612 | | | 1,161 | | | (1,672 | ) | | 19,578 | |
| (a) | Represents net income available to common shareholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment. |
The following table presents information about the reported revenues and net income of UE for the three months ended March 31, 2007 and 2006, and total assets as of March 31, 2007 and December 31, 2006.
| | Missouri Regulated | | Other (a) | | Consolidated UE | |
2007: | | | | | | | | | |
| Revenues | $ | 650 | | $ | - | | $ | 650 | |
Net income(b) | | 23 | | | 13 | | | 37 | |
2006: | | | | | | | | | |
| Revenues | $ | 636 | | $ | - | | $ | 636 | |
Net income(b) | | 35 | | | 15 | | | 50 | |
As of March 31, 2007: | | | | | | | | | |
| Total assets | $ | 10,286 | | $ | 34 | | $ | 10,320 | |
As of December 31, 2006: | | | | | | | | | |
| Total assets | | 10,251 | | | 36 | | | 10,287 | |
| (a) | Includes 40% interest in EEI and other non-rate-regulated activities. |
| (b) | Represents net income available to the common shareholder (Ameren). |
The following table presents information about the reported revenues and net income of CILCORP for the three months ended March 31, 2007 and 2006, and total assets as of March 31, 2007 and December 31, 2006.
| | Illinois Regulated | | Non-rate-regulated Generation | | CILCORP Other | | Intersegment Eliminations | | Consolidated CILCORP | |
2007: | | | | | | | | | | | | | | | |
| External revenues | $ | 234 | | $ | 76 | | $ | - | | $ | - | | $ | 310 | |
| Intersegment revenues | | - | | | 1 | | | - | | | (1 | ) | | - | |
Net income(a) | | 7 | | | 13 | | | - | | | - | | | 20 | |
2006: | | | | | | | | | | | | | | | |
| External revenues | $ | 233 | | $ | 9 | | $ | - | | $ | - | | $ | 242 | |
| Intersegment revenues | | - | | | 41 | | | - | | | (41 | ) | | - | |
Net income(a) | | 8 | | | - | | | - | | | - | | | 8 | |
As of March 31, 2007: | | | | | | | | | | | | | | | |
Total assets(b) | $ | 1,150 | | $ | 1,241 | | $ | 4 | | $ | (180 | ) | $ | 2,215 | |
As of December 31, 2006: | | | | | | | | | | | | | | | |
Total assets(b) | | 1,208 | | | 1,246 | | | 4 | | | (217 | ) | | 2,241 | |
| (a) | Represents net income available to the common shareholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment. |
| (b) | Total assets for Illinois Regulated include an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company). |
The following table presents information about the reported revenues and net income of CILCO for the three months ended March 31, 2007 and 2006, and total assets as of March 31, 2007 and December 31, 2006.
| | Illinois Regulated | | Non-rate-regulated Generation | | CILCO Other | | Intersegment Eliminations | | Consolidated CILCO | |
2007: | | | | | | | | | | | | | | | |
| External revenues | $ | 234 | | $ | 76 | | $ | - | | $ | - | | $ | 310 | |
| Intersegment revenues | | - | | | 1 | | | - | | | (1 | ) | | - | |
Net income(a) | | 7 | | | 19 | | | - | | | - | | | 26 | |
2006: | | | | | | | | | | | | | | | |
| External revenues | $ | 233 | | $ | 9 | | $ | - | | $ | - | | $ | 242 | |
| Intersegment revenues | | - | | | 41 | | | - | | | (41 | ) | | - | |
Net income(a) | | 8 | | | 10 | | | - | | | - | | | 18 | |
As of March 31, 2007: | | | | | | | | | | | | | | | |
| Total assets | $ | 967 | | $ | 656 | | $ | 1 | | $ | (3 | ) | $ | 1,621 | |
As of December 31, 2006: | | | | | | | | | | | | | | | |
| Total assets | | 1,020 | | | 642 | | | 1 | | | (22 | ) | | 1,641 | |
| (a) | Represents net income available to the common shareholder (CILCORP); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment. |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Ameren’s earnings in the first quarter 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 contracts in 2007. Electric and gas margins in Ameren’s Missouri and Illinois rate-regulated business segments benefited from greater heating demand caused by colder winter weather. In fact, heating degree days were up 13 percent in the first quarter of 2007 over the same period in 2006. Ameren’s first quarter 2007 earnings also benefited from new ICC-approved rate tariffs for the delivery of electricity. However, these positive results were reduced by increases in fuel and related transportation costs, labor and benefit costs, bad debt expenses, higher depreciation expenses, greater dilution and rising financing costs. In addition, costs related to participation in the MISO market were higher in the first quarter of 2007 over the same period in 2006 because of a March 2007 FERC order that reallocated costs among market participants retroactive to 2005.
Ameren’s earnings in the first quarter 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 ice storms. Storm-related costs in the first quarter of 2006 reduced net income by an estimated $6 million (after taxes), or 3 cents per share. 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. These commitments were terminated in the first quarter of 2007 as a result of credit rating downgrades resulting from Illinois legislative actions in the first quarter of 2007.
More noteworthy is the Ameren Illinois Utilities’ continued focus on developing a constructive solution for their customers to help them adjust to higher electric rates resulting from the end of a decade-long rate freeze and expiration of power supply contracts. If enacted, legislation proposed in the Illinois General Assembly during the first quarter to roll back rates to 2006 levels, freeze rates and provide refunds would render the Ameren Illinois utilities financially insolvent and bankrupt unless the courts quickly intervene. A rate rollback would mean that reliability would suffer and our customers would face even higher electric bills, as was the case in California a few years ago. Notably, if rate rollback legislation had been in place on January 1, 2007, the Ameren Illinois utilities would have collected approximately $100 million less in revenues in the first quarter of 2007. Just the threat of rate rollback and freeze legislation in Illinois has already resulted in credit rating downgrades, increased collateral and prepayment requirements, higher borrowing costs and increased use of liquidity for the Ameren Illinois utilities.
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 pending rate cases and the Illinois power procurement auction process and related tariffs. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity 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 $123 million, or 59 cents per share, in the first quarter of 2007 from $70 million, or 34 cents per share, in the first quarter of 2006. Net income in the Illinois Regulated and Non-rate-regulated segments increased by $20 million and $43 million, respectively, while net earnings in the Missouri Regulated segment declined by
$12 million.
Earnings were favorably impacted in the first quarter of 2007 as compared with the first quarter of 2006 by:
| · | increased margins on interchange sales from the Missouri Regulated segment; |
| · | higher delivery service rates on Illinois Regulated sales; |
| · | 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; |
| · | 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); |
| · | favorable weather conditions (estimated at 5 cents per share); and |
| · | other factors, including organic growth. |
Earnings were negatively impacted in the first quarter of 2007 as compared with the first quarter of 2006 by:
| · | costs associated with electric outages caused by a severe ice storm in January 2007 (9 cents per share); |
| · | higher labor and employee benefit costs (6 cents per share); |
| · | increased depreciation expense (5 cents per share); |
| · | higher financing costs (4 cents per share); and |
| · | other factors, including higher fuel and transportation prices. |
An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2007 compared with 2006. 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 ended March 31, 2007 and 2006:
| | | 2007 | | | 2006 | |
| Net income (loss): | | | | | | |
UE(a) | $ | 37 | | $ | 50 | |
| CIPS | | 10 | | | (2 | ) |
| Genco | | 43 | | | 6 | |
| CILCORP | | 20 | | | 8 | |
| IP | | 12 | | | 3 | |
Other(b) | | 1 | | | 5 | |
| Ameren net income | $ | 123 | | $ | 70 | |
| (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 ended March 31, 2007 and 2006:
2007 | Missouri Regulated | | Illinois Regulated | | Non-rate-regulated Generation | | Other / Intersegment Eliminations | | Total | |
| Electric margin | $ | 415 | | $ | 172 | | $ | 250 | | $ | (15 | ) | $ | 822 | |
| Gas margin | | 27 | | | 115 | | | - | | | (2 | ) | | 140 | |
| Other revenues | | 1 | | | 2 | | | - | | | (3 | ) | | - | |
| Other operations and maintenance | | (223 | ) | | (126 | ) | | (68 | ) | | 21 | | | (396 | ) |
| Depreciation and amortization | | (87 | ) | | (55 | ) | | (27 | ) | | (7 | ) | | (176 | ) |
| Taxes other than income taxes | | (57 | ) | | (36 | ) | | (8 | ) | | (1 | ) | | (102 | ) |
| Other income and (expenses) | | 9 | | | 4 | | | 1 | | | 2 | | | 16 | |
| Interest expense | | (48 | ) | | (29 | ) | | (25 | ) | | 2 | | | (100 | ) |
Income taxes | | (13 | ) | | (16 | ) | | (46 | ) | | 4 | | | (71 | ) |
Minority interest and preferred dividends | | (1 | ) | | (2 | ) | | (7 | ) | | - | | | (10 | ) |
Net income | $ | 23 | | $ | 29 | | $ | 70 | | $ | 1 | | $ | 123 | |
2006 | | | | | | | | | | | | | | | |
| Electric margin | $ | 374 | | $ | 140 | | $ | 184 | | $ | (12 | ) | $ | 686 | |
| Gas margin | | 25 | | | 110 | | | - | | | 1 | | | 136 | |
| Other revenues | | 1 | | | - | | | - | | | (1 | ) | | - | |
| Other operations and maintenance | | (171 | ) | | (124 | ) | | (69 | ) | | 12 | | | (352 | ) |
| Depreciation and amortization | | (80 | ) | | (47 | ) | | (26 | ) | | (8 | ) | | (161 | ) |
| Taxes other than income taxes | | (59 | ) | | (43 | ) | | (8 | ) | | (3 | ) | | (113 | ) |
| Other income and (expenses) | | 1 | | | 2 | | | - | | | 1 | | | 4 | |
| Interest expense | | (35 | ) | | (23 | ) | | (25 | ) | | 7 | | | (76 | ) |
Income taxes | | (20 | ) | | (4 | ) | | (22 | ) | | 2 | | | (44 | ) |
Minority interest and preferred dividends | | (1 | ) | | (2 | ) | | (7 | ) | | - | | | (10 | ) |
Net income | $ | 35 | | $ | 9 | | $ | 27 | | $ | (1 | ) | $ | 70 | |
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three months ended March 31, 2007, as compared with the year-ago period. 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) | $ | 18 | | $ | 7 | | $ | 5 | | $ | - | | $ | 4 | | $ | 4 | | $ | 2 | |
| Interchange revenues | | 61 | | | 61 | | | - | | | - | | | - | | | - | | | - | |
| Other (estimate) | | 168 | | | (62 | ) | | 46 | | | (4 | ) | | 79 | | | 79 | | | 28 | |
| Total | $ | 247 | | $ | 6 | | $ | 51 | | $ | (4 | ) | $ | 83 | | $ | 83 | | $ | 30 | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | | | | | | |
| Fuel: | | | | | | | | | | | | | | | | | | | | | |
Generation and other | $ | (9 | ) | $ | 5 | | $ | - | | $ | (15 | ) | $ | 2 | | $ | 2 | | $ | - | |
Emissions allowance costs | | 13 | | | 3 | | | - | | | 5 | | | 4 | | | 4 | | | - | |
Price | | (18 | ) | | (11 | ) | | - | | | (2 | ) | | (5 | ) | | (5 | ) | | - | |
Purchased power | | (100 | ) | | 34 | | | (33 | ) | | 75 | | | (70 | ) | | (70 | ) | | (12 | ) |
| Storm-related energy costs | | 3 | | | 3 | | | - | | | - | | | - | | | - | | | - | |
| Total fuel and purchased power changeTotal | $ | (111 | ) | $ | 34 | | $ | (33 | ) | $ | 63 | | $ | (69 | ) | $ | (69 | ) | $ | (12 | ) |
Net change in electric margins | $ | 136 | | $ | 40 | | $ | 18 | | $ | 59 | | $ | 14 | | $ | 14 | | $ | 18 | |
Net change in gas margins | $ | 4 | | $ | 2 | | $ | 2 | | $ | - | | $ | 1 | | $ | 1 | | $ | 2 | |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Ameren
Ameren’s electric margin increased by $136 million, or 20%, for the three months ended March 31, 2007, compared with the same period in 2006. The following items had a favorable impact on electric margins for the first quarter of 2007 as compared to the year-ago period:
| · | an increase in electric margins as a result of Non-rate-regulated Generation selling more power at market-based prices in the first quarter of 2007 compared with sales under cost-based power supply agreements which expired on December 31, 2006; |
| · | Illinois electric delivery service rate increases which commenced January 1, 2007; |
| · | lower emissions allowance costs totaling $13 million for the quarter ended March 31, 2007; |
| · | favorable weather conditions increased electric margin by $9 million; |
| · | 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 |
| · | storm-related outages in the first quarter of 2006 decreased interchange margin by $3 million at Ameren and UE. |
The following items had an unfavorable impact on electric margins for the first quarter of 2007 as compared to the year-ago period:
| · | a 10% increase in coal and related transportation prices; |
| · | elimination of bundled tariffs in Illinois Regulated operations; |
| · | reduced power plant availability, primarily at the UE and AERG plants; and |
| · | MISO costs, which were $19 million higher for the three months ended March 31, 2007, compared with the same period in 2006. Costs related to participation in the MISO Day Two Energy Market were higher in the first quarter of 2007 over the same period in 2006 because of a March 2007 FERC order that reallocated costs among market participants retroactive to 2005. |
Ameren’s gas margin increased by $4 million, or 3%, for the three months ended March 31, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as was evidenced by a 13% increase in heating degree-days.
Missouri Regulated
UE
UE’s electric margin increased by $40 million, or 11%, for the three months ended March 31, 2007, compared to the same period in 2006. The increase was primarily due to:
| · | a $36 million 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; |
| · | favorable weather conditions which increased electric margin by $3 million; and |
| · | spring storm-related outages in the first quarter of 2006, which reduced 2006 electric margins by $3 million. |
Factors that reduced the increase in electric margin for the three months ended March 31, 2007, as compared to the same period in the prior year were as follows:
| · | reduced power plant availability because of planned maintenance activities; |
| · | an increase in coal and related transportation prices; and |
| · | increased MISO costs totaling $13 million, primarily related to the March 2007 FERC order referenced above. |
UE’s gas margin increased by $2 million, or 8%, for the three months ended March 31, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by an 11% increase in heating degree-days.
Illinois Regulated
Illinois Regulated’s electric margin increased by $32 million, or 23%, for the three months ended March 31, 2007, compared with the same period in 2006. Illinois Regulated’s gas margin increased by $5 million, or 5%, for the three months ended March 31, 2007, compared with the same period in 2006.
CIPS
CIPS’ electric margin increased by $18 million, or 42%, for the three months ended March 31, 2007, compared to the same period in 2006. The increase in electric margin 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 which increased electric margin by $4 million. |
CIPS’ gas margin increased by $2 million, or 8%, for the three months ended March 31, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 5% increase in heating degree-days.
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 ended March 31, 2007, as compared with the same period in 2006:
| | | Three Months | |
| CILCO (Illinois Regulated) | $ | (4 | ) |
| CILCO (AERG) | | 18 | |
| Total change in electric margin | $ | 14 | |
CILCO’s Illinois Regulated electric margin decreased by $4 million, or 13%, for the three months ended March 31, 2007, compared to the same period 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. In addition, MISO costs increased $2 million. The decrease in electric margin was reduced by favorable weather conditions which increased electric margin by $3 million.
See Non-rate-regulated Generation under Results of Operations for a detailed explanation of CILCO’s (AERG) change in electric margin for the three months ended March 31, 2007, as compared with the same period in 2006.
CILCO’s (Illinois Regulated) gas margin increased by $1 million, or 3%, for the three months ended March 31, 2007, compared to the same period in 2006. Favorable weather conditions resulted in a $2 million increase in gas margins, as evidenced by a 15% increase in heating degree-days, but was offset by unfavorable customer sales mix.
IP
IP’s electric margin increased by $18 million, or 28%, for the three months ended March 31, 2007, compared with the same period in 2006 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. In addition, MISO costs increased $13 million, primarily as a result of the March 2007 FERC order referenced above.
IP’s gas margin increased by $2 million, or 4%, for the three months ended March 31, 2007, compared to the same period in 2006, primarily because of favorable weather conditions evidenced by a 12% increase in heating degree-days.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $66 million, or 36%, for the three months ended March 31, 2007, compared with the same period in 2006.
Genco
Genco’s electric margin increased by $59 million, or 72%, for the three months ended March 31, 2007, compared with the same period in 2006, primarily because of:
| · | an increase in electric margins as a result of selling power at market-based prices in the first quarter of 2007 compared with cost-based power supply agreements which expired on December 31, 2006; |
| · | increased plant availability; and |
| · | lower MISO costs totaling $8 million, primarily as a result of the March 2007 FERC order referenced above. |
Genco’s increase in electric margin was reduced by:
| · | the loss of margins on sales supplied with power acquired through the JDA; and |
| · | an increase in coal and related transportation prices. |
CILCO (AERG)
For the three-month period ended March 31, 2007, AERG’s electric margin increased by $18 million, or 51%, compared with the same period in 2006 primarily because of:
| · | an increase in electric margins of AERG selling its power at market-based prices in the first quarter of 2007 compared with sales under cost-based power supply agreements which expired on December 31, 2006; and |
| · | lower MISO costs totaling $4 million, primarily as a result of the march 2007 FERC order referenced above. |
The increase in electric margin was reduced by:
| · | an increase in coal and related transportation prices; and |
| · | reduced plant availability because of planned maintenance activities. |
EEI
EEI’s electric margins decreased by $3 million for the three months ended March 31, 2007, compared with the same period in 2006 primarily because of an increase in coal and related transportation prices.
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Ameren
Ameren’s other operations and maintenance expenses increased $44 million in the first quarter of 2007 compared with the first quarter 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, higher labor costs and increased bad debt reserves. Reducing the effect of these items was 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. The commitment to make these contributions was terminated in the first quarter of 2007 as a result of credit rating agency downgrades resulting from recent Illinois legislative actions.
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 ended March 31, 2007, compared with the same period in 2006 were as follows:
Missouri Regulated
UE
Other operations and maintenance expenses increased $53 million primarily because of storm repair expenditures of $26 million, increased labor costs of $13 million, higher maintenance expenses of $4 million, and insurance premiums paid to an affiliate for replacement power coverage of $4 million.
Illinois Regulated
Other operations and maintenance expenses increased $2 million in the Illinois Regulated segment in the first quarter of 2007 compared with the first quarter of 2006.
CIPS
Other operations and maintenance expenses increased $5 million primarily because of storm repair expenditures of $3 million, higher labor costs and increased bad debt reserves. The reversal of an accrual for customer assistance programs of $4 million established in 2006, as noted above, reduced the impact of these increases.
CILCO (Illinois Regulated)
Other operations and maintenance expenses decreased $3 million primarily because of the reversal of the customer assistance program accrual of $3 million established in 2006, as noted above.
IP
Other operations and maintenance expenses were comparable with the prior-year period as the reversal of the customer assistance program accrual of $8 million established in 2006 noted above was offset by higher employee benefit costs.
Non-rate-regulated Generation
Other operations and maintenance expenses decreased $1 million in the Non-rate-regulated Generation segment in the first quarter of 2007 compared with the first quarter of 2006.
Genco, CILCO (AERG) and EEI
Other operations and maintenance expenses were comparable at Genco, CILCO (AERG) and EEI for the first quarter of 2007 compared with the first quarter of 2006.
CILCORP (Parent Company Only)
Other operations and maintenance expenses decreased $3 million primarily because of the write-off in the prior-year period of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.
Depreciation and Amortization
Ameren
Ameren’s depreciation and amortization expenses increased $15 million in the first quarter of 2007, compared with the first quarter of 2006, primarily because of capital additions in 2006 and the start of amortization of a regulatory asset associated with acquisition integration costs at IP in 2007 as required by an ICC order.
Variations in depreciation and amortization expenses in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2007, compared with the same period in 2006 were as follows:
Missouri Regulated
UE
Depreciation and amortization expenses increased $7 million primarily because of capital additions in 2006, including CTs purchased in the first quarter of 2006 and storm-related expenditures.
Illinois Regulated
Depreciation and amortization expenses increased $8 million in the Illinois Regulated segment for the three months ended March 31, 2007, compared with the same period in 2006.
CIPS & CILCO (Illinois Regulated)
Depreciation and amortization expenses were comparable between periods.
IP
Depreciation and amortization expenses increased $6 million, primarily because of amortization in the first quarter of 2007 of a regulatory asset associated with acquisition integration costs as required by an ICC order.
Non-rate-regulated Generation
Depreciation and amortization expenses were comparable in the Non-rate-regulated Generation segment, and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI for the first quarter of 2007 compared with the first quarter of 2006.
Taxes Other Than Income Taxes
Ameren
Ameren’s taxes other than income taxes decreased $11 million in the first quarter of 2007 from the first quarter of 2006, primarily because of lower gross receipts and property taxes.
Variations in taxes other than income taxes in Ameren’s business segments and for the Ameren Companies for the three months ended March 31, 2007, compared with the same period in 2006 were as follows:
Missouri Regulated
UE
Taxes other than income taxes decreased $2 million, primarily because of lower gross receipts taxes.
Illinois Regulated
Taxes other than income taxes decreased $7 million in the Illinois Regulated segment in the first quarter of this year compared to the first quarter of the prior year.
CIPS
Taxes other than income taxes decreased $3 million, primarily because of lower property taxes.
CILCO (Illinois Regulated)
Taxes other than income taxes decreased $2 million, primarily because of lower gross receipts taxes.
IP
Taxes other than income taxes decreased $1 million, primarily because of lower gross receipts taxes.
Non-rate-regulated Generation
Taxes other than income taxes were comparable in the Non-rate-regulated Generation segment, and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI for the first quarter of 2007 compared with the first quarter of 2006.
Other Income and Expenses
Ameren
Miscellaneous income increased $12 million in the first quarter of 2007 compared with the first quarter of 2006, primarily as a result of interest income on an industrial development revenue bond acquired by UE in conjunction with its purchase of a CT in the first quarter of 2006. This amount is offset by an equivalent amount of interest expense associated with a capital lease for the CT recorded in interest charges on Ameren’s and UE’s statements of income. Miscellaneous expense was comparable between periods.
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 ended March 31, 2007, compared with the same period in 2006 were as follows:
Missouri Regulated
UE
Miscellaneous income increased $8 million, primarily as a result of increased interest income related to an industrial
development revenue bond as noted above. Miscellaneous expense was comparable between periods.
Illinois Regulated
Other income and expenses were comparable in the Illinois Regulated segment, and at CIPS, CILCO (Illinois Regulated), and IP in the first quarter of 2007 compared with the first quarter of the prior year.
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 for the first quarter of 2007 compared with the first quarter of 2006.
Interest
Ameren
Interest expense increased $24 million in the first quarter of 2007, compared with the first quarter of 2006, primarily because of increased short-term borrowings and other items noted below.
Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2007, compared with the same period in 2006, were as follows:
Missouri Regulated
UE
Interest expense increased $13 million, primarily because of interest expense recognized on UE’s capital lease associated with the purchase of a CT in the first quarter of 2006. This amount was offset by an equivalent amount of interest income recorded in other income and expenses on Ameren’s and UE’s statements of income. Additionally, increased short-term borrowings resulted in higher interest expense in the first quarter of 2007.
Illinois Regulated
Interest expense increased $6 million in the Illinois Regulated segment in the first quarter of this year compared to the first quarter of the prior year.
CIPS & CILCO (Illinois Regulated)
Interest expense was comparable between periods.
IP
Interest expense increased $4 million, primarily because of the issuance of $75 million senior secured notes in 2006 and increased short-term borrowings.
Non-rate-regulated Generation
Interest expense was comparable at Non-rate-regulated Generation, Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI for the first quarter of 2007 compared with the first quarter of 2006.
Income Taxes
Ameren
Ameren’s effective tax rate was comparable between 2007 and 2006.
Variations in effective tax rates in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months ended March 31, 2007, compared with the same period in 2006 were as follows:
Missouri Regulated
UE
Effective tax rate decreased in 2007 from 2006, primarily because of an increase in expenses deductible for tax purposes which were not expensed for book purposes.
Illinois Regulated
Effective tax rate increased in the first quarter of 2007 compared with the first quarter of 2006 at Illinois Regulated due to items detailed below:
CIPS
Effective tax rate increased primarily because of an increase in reserves for uncertain tax positions in 2006 for tax returns filed in the prior year.
CILCO (Illinois Regulated) and IP
Effective tax rate increased primarily because of an increase in non-deductible expenses.
Non-rate-regulated Generation
Effective tax rate decreased in the first quarter of 2007 compared with the first quarter of 2006 in the Non-rate-regulated Generation segment due to items detailed below:
Effective tax rate decreased primarily because of an increase in reserves for uncertain tax positions in 2006 for tax returns filed in the prior year, along with an increase in expenses in 2007 that were deductible for tax purposes, but were not expensed for book purposes.
CILCO (AERG)
Effective tax rate decreased primarily because of an increase in expenses deductible for tax purposes which were not expensed for book purposes.
CILCORP (Parent Company Only)
Effective tax rate increased primarily because of an increase in non-deductible expenses.
EEI
Effective tax rate decreased 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 sells power through the Illinois power procurement auction and is selling power through other primarily market-based contracts with wholesale and retail customers. The amount of power that Genco, AERG, EEI, Marketing Company and their affiliates may supply to CIPS, CILCO and IP through the Illinois power procurement auction is limited to 35% of CIPS’, CILCO’s and IP’s aggregate annual load. In addition to cash flows from operating activities, each of the Ameren Companies uses 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 March 31, 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 an Illinois legislative proposal to rollback and freeze electric rates at 2006 levels for CIPS, CILCO and IP. If such legislation is enacted and the implementation of such legislation is not promptly enjoined, CIPS, CILCORP, CILCO and IP will not have enough operating cash flow to support normal operations, which would lead to financial insolvency and bankruptcy.
The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2007 and 2006:
| Net Cash Provided By (Used In) Operating Activities | Net Cash Provided By (Used In) Investing Activities | Net Cash Provided By (Used In) Financing Activities |
| | | 2007 | | | 2006 | | | Variance | | | 2007 | | | 2006 | | | Variance | | | 2007 | | | 2006 | | | Variance | |
Ameren(a) | $ | 358 | | $ | 373 | | $ | (15 | ) | $ | (386 | ) | $ | (573 | ) | $ | 187 | | $ | 52 | | $ | 133 | | $ | (81 | ) |
| UE | | (50 | ) | | 86 | | | (136 | ) | | (221 | ) | | (429 | ) | | 208 | | | 270 | | | 324 | | | (54 | ) |
| CIPS | | 10 | | | 67 | | | (57 | ) | | (34 | ) | | (64 | ) | | 30 | | | 64 | | | (3 | ) | | 67 | |
| Genco | | 69 | | | 72 | | | (3 | ) | | (37 | ) | | (42 | ) | | 5 | | | (32 | ) | | (30 | ) | | (2 | ) |
| CILCORP | | 42 | | | 78 | | | (36 | ) | | (1 | ) | | (36 | ) | | 35 | | | (18 | ) | | (42 | ) | | 24 | |
| CILCO | | 58 | | | 78 | | | (20 | ) | | (1 | ) | | (36 | ) | | 35 | | | (35 | ) | | (43 | ) | | 8 | |
| IP | | 58 | | | 65 | | | (7 | ) | | (62 | ) | | (38 | ) | | (24 | ) | | 47 | | | (26 | ) | | 73 | |
| (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 three months of 2007, as compared with the first three months of 2006. Working capital investment increased as a result of the collection of higher electric rates from customers lagging payments for power purchases. 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 $68 million.
At UE, cash from operating activities decreased in the first three months of 2007, as compared with the first three months of 2006. Increases in electric margins were reduced
by storm repair costs, as discussed in Results of Operations. Negatively impacting cash from operations was an increase in accounts receivable, primarily because of sales to MISO. Compared to the prior year period, cash paid for Taum Sauk costs (net of insurance recoveries) decreased $23 million benefiting cash flow from operations. Income tax payments (net of refunds) decreased by $33 million benefiting cash flows from operations.
At CIPS, cash from operating activities decreased in the first three months of 2007, as compared with the first three months of 2006. Electric 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 was the primary reason for the overall decrease in operating cash flows. Income tax payments (net of refunds) decreased $16 million, benefiting cash flows from operations.
Genco’s cash from operating activities decreased in the first three months of 2007 compared to the 2006 period primarily because of the timing of payments to affiliates for purchased power under the JDA, which expired at the end of 2006, compared with the timing of receipts from the wholesale sales associated with that purchased power. Income tax payments (net of refunds) also decreased in 2007 by $6 million compared to 2006 improving cash flows from operations.
Cash from operating activities decreased for CILCORP and CILCO in the three months ended March 31, 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. Income tax payments (net of refunds) were the same year over year for CILCORP and decreased $8 million for CILCO.
IP’s cash from operations decreased in the three months ended March 31, 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 was the primary reason for the overall decrease in operating cash flows. Income tax payments (net of refunds) decreased by $20 million reducing the impact on cash flows of higher receivables.
Cash Flows from Investing Activities
Ameren’s decrease in cash used in investing activities was primarily because of $292 million used for CT purchases in 2006 and a $33 million reduction in emission allowance purchases in the first three months of 2007 compared to the first three months of 2006. Excluding the effect of the prior year CT purchase, capital expenditures increased by $137 million in 2007, principally due to capital expenditures paid in 2007 related to the December 2006 and January 2007 severe storms, scrubber projects at UE, Genco, and AERG power plants, and expenditures made in preparation for UE’s April 2007 Callaway nuclear plant refueling and maintenance outage.
UE’s cash used in investing activities decreased in the first three 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 an $87 million increase in capital expenditures in the first three months of 2007 as compared with the first three months of 2006. The increased capital expenditures were related to storm costs paid in 2007, scrubber projects at a power plant, and expenditures incurred in preparation for the April 2007 Callaway nuclear plant refueling and maintenance outage.
CIPS’ cash used in investing activities decreased for the three months ended March 31, 2007, compared with the 2006 period, primarily due to a $33 million reduction of net advances to the money pool.
Genco’s cash used in investing activities decreased a net $5 million in the first three months of 2007 compared with the 2006 period. Capital expenditures increased $20 million, principally due to a scrubber project at one of its plants, while emission allowance purchases decreased by $26 million.
CILCORP’s and CILCO’s cash used in investing activities decreased in the three months ended March 31, 2007, compared with the same period in 2006 primarily as a result of
$42 million received from the money pool in 2007 in repayment of prior year advances. In addition, there was a $12 million decrease in emission allowance purchases for the first three months of 2007 compared to the first three months of 2006. For $18 million increase in capital expenditures primarily due to a scrubber project and plant upgrades at CILCO subsidiary AERG reduced the benefit of these increases in cash flows.
IP’s cash used in investing activities increased in the first three months of 2007 compared to the same period in 2006, primarily because of net money pool advances of $16 million, and an $8 million increase in capital expenditures for the first three months of 2007 compared to the same period in 2006.
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 from financing activities decreased for Ameren in the first three months of 2007 from the year-ago period. Negative effects on cash included a $143 million increase in long-term debt redemptions, repurchases and maturities, including the maturity of $100 million in 5.70% notes during the quarter. As a result of these maturities, there was an increase in short-term debt. Positive effects on cash included a net increase of $67 million in net short-term debt proceeds in the 2007 period, compared to the 2006 period.
UE’s cash from financing activities decreased for the first three months of 2007, compared to the same period last year. UE had $151 million less in short-term borrowings in the first quarter of 2007 than the 2006 period. Short-term borrowings were used in 2006 principally to fund the acquisition of CTs. In addition, dividend payments increased $38 million in the 2007 period compared to 2006. Cash was positively affected by $137 million in net proceeds from an intercompany borrowing arrangement with Ameren.
CIPS’ had a net source of cash from financing activities for the three months ended March 31, 2007, compared to a net use of cash in the 2006 period, primarily because of a net increase of $65 million in net short-term debt proceeds in 2007.
Genco had a $2 million increase in cash used in financing activities for the first three months of 2007, compared with 2006. This net increase resulted from a $17 million increase in dividend payments in the 2007 period compared with the 2006 period partially offset by Genco having $7 million in net borrowings from the money pool in the 2007 period, compared to net repayments of $8 million in the prior year period.
CILCORP’s and CILCO’s cash used in financing activities decreased for the first three months of 2007, compared to the same period last year. Cash used for redemptions, repurchases, and maturities increased by $120 million at CILCORP and $50 million at CILCO. The absence in 2007 of $50 million in dividends paid in the prior year benefited cash at both companies. In addition, a net increase of $74 million in short-term debt at CILCORP and a net increase in money pool borrowings of $25 million at CILCORP and $24 million at CILCO benefited cash.
IP had a net source of cash from financing activities in the first three months of 2007, compared to a net use of cash in the same period of the prior year. This increase was primarily because of $115 million in net short-term debt proceeds in the 2007 period, partially offset by $43 million in net repayments to the money pool in the 2007 period, compared to net borrowings of $3 million in the prior year period.
Short-term Borrowings and Liquidity
Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities of 1 to 45 days. 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 April 30, 2007:
Credit Facility | Expiration | | | Amount Committed | | | Amount Available | |
Ameren, UE and Genco: | | | | | | | | |
Multiyear revolving(a) | July 2010 | | $ | 1,150 | | $ | 697 | |
CIPS, CILCORP, CILCO, IP and AERG: | | | | | | | | |
2007 Multiyear revolving(b) | January 2010 | | | 500 | | | 186 | |
2006 Multiyear revolving(c) | January 2010 | | | 500 | | | 235 | |
| (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 $156 million, respectively. |
| (b) | The maximum amount available to each borrower, including for the issuance of letters of credit, is limited as follows: CILCORP - $125 million, IP - $200 million and AERG - $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. Borrowings by CIPS, CILCO and IP under this facility are on a 364-day basis. |
| (c) | The maximum amount available to each borrower, including for issuance of letters of credit, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. Borrowings by CIPS, CILCO and IP under this facility are on a 364-day basis. |
In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At March 31, 2007, Ameren had
$161 million of cash and cash equivalents.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2006, FERC issued an order authorizing these subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion; CIPS - $250 million; and CILCO - $250 million. The authorization was effective as of April 1, 2006, and terminates on March 31, 2008. IP has unlimited short-term debt authorization from FERC.
Genco is authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt authorization from FERC.
With the repeal of PUHCA 1935, the issuance of short-term unsecured debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer subject to approval by any regulatory body.
The Ameren Companies continually evaluate the adequacy and appropriateness of their credit arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.
Long-term Debt and Equity
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts and including any redemption premiums) for the three months ended March 31, 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.
| | | | Three Months | |
| | Month Issued, Redeemed, Repurchased or Matured | 2007 | | 2006 | |
Issuances | | | | | | |
Common stock | | | | | | | | | |
Ameren: | | | | | | | | | |
DRPlus and 401(k) | | Various | | $ | 21 | | $ | 27 | |
| Total common stock issuances | | | | $ | 21 | | $ | 27 | |
Redemptions, Repurchases and Maturities | | | | | | | | | |
Long-term debt | | | | | | | | | |
Ameren: | | | | | | | | | |
2002 5.70% notes due 2007 | | February | | | 100 | | | - | |
CILCORP: | | | | | | | | | |
9.375% Senior notes due 2029 | | March | | | - | | | 3 | |
CILCO: | | | | | | | | | |
7.50% First mortgage bonds due 2007 | | January | | | 50 | | | - | |
IP: | | | | | | | | | |
Note payable to IP SPT: | | | | | | | | | |
5.65% Series due 2008 | | Various | | | 24 | | | 28 | |
| Total Ameren long-term debt redemptions, repurchases and maturities | | | | $ | 174 | | $ | 31 | |
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of March 31, 2007:
| Effective Date | | | Authorized Amount | | | Issued | | | Available | |
| Ameren | June 2004 | | $ | 2,000 | | $ | 459 | | $ | 1,541 | |
| UE | October 2005 | | | 1,000 | | | 260 | | | 740 | |
| 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 0.4 million new shares of common stock valued at $21 million in the three months ended March 31, 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 be made only by means of a prospectus that meets the
requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
See Note 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 March 31, 2007, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control, such as the legislation proposed to rollback and freeze electric rates at 2006 levels in Illinois for CIPS, CILCO and IP, may create uncertainty in the capital markets. Such events would increase our cost of capital and adversely affect our ability to access the capital markets. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for further discussion.
Dividends
Dividends paid by Ameren to shareholders during the first three months of 2007 totaled $131 million, or 63.5 cents per share (2006 - $130 million or 63.5 cents per share). On
April 24, 2007, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on June 29, 2007, to shareholders of record on June 6, 2007.
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 March 31, 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 other 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
March 31, 2007, AERG was in compliance with the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities. The other borrowers 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 three months ended March 31, 2007 and 2006.
| | Three Months |
| | | 2007 | | | 2006 | |
| UE | $ | 80 | | $ | 42 | |
| Genco | | 39 | | | 22 | |
CILCORP(a) | | - | | | 50 | |
| Nonregistrants | | 12 | | | 16 | |
| Dividends paid by Ameren | $ | 131 | | $ | 130 | |
| (a) | CILCO paid to CILCORP dividends of $50 million for the three months ended March 31, 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 Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006,
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.
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 $4,165 million, $715 million, $448 million, $81 million, $1,285 million, $1,285 million and $1,617 million, respectively, as of March 31, 2007. Total other obligations at March 31, 2007, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,352 million, $2,057 million, $473 million, $393 million, $1,473 million, $1,473 million and $1,749 million, respectively.
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 as set forth in the above table. 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 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 roll back electric rates to 2006 levels, freeze rates at those levels for at least one year, and provide for refunds to customers. See Note 2 - Rates and Regulatory Matters to our financial statements under Part I, Item 1 of this report. 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 roll back rates to 2006 levels and freeze 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 follow 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+,” in addition to other rating downgrades with respect to Ameren, UE, CIPS, CILCORP and CILCO on that date. The ratings for Ameren, CIPS, CILCORP, CILCO and IP remain on “negative watch.” 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.”
The recent adverse ratings actions and any further 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 were made during the first quarter of 2007 of $33 million, $2 million, $4 million, $4 million, and $20 million at Ameren, CIPS, 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 March 31, 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 $196 million, $67 million, $20 million, $36 million, $28 million, $28 million, or $19 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 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. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In September 2006, the power procurement auction was held and declared successful with respect to power for fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. The auction clearing price was about $65 per megawatthour for the fixed-price residential and small commercial product and about $85 per megawatthour for large commercial and industrial customers. Marketing Company participated in the auction with power being acquired from Genco and AERG, subject to an auction rules limitation of providing no more than 35% of the Ameren Illinois Utilities’ expected annual load, and it was awarded sales in the auction. As a result of the high auction price for the large commercial and industrial customers, almost all of these customers chose a different supplier. |
| · | CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). In November 2006, the ICC issued an order approving an annual revenue increase for electric delivery service of $97 million in the aggregate (CIPS - $8 million decrease, CILCO - $21 million increase and IP - $84 million increase) based on an allowed return on equity of approximately 10%. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling approximately $50 million, which were disallowed. The administrative law judges issued a proposed order in April 2007 recommending no recovery of these expenses for CIPS, CILCO and IP. The ICC’s decision on the recovery of these expenses is due in May 2007. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity in 2007. Prior to January 2, 2007, most customers were taking service under a frozen bundled electric rate in 2006, which included the cost of power, so any delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates. The necessity and timing of new Illinois delivery service rate cases for the Ameren Illinois Utilities will be driven by several factors, including the results of the pending rehearing. |
| · | 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 based on the results of the Illinois power procurement auction held in early September 2006 and increases resulting from the delivery service rate cases. CIPS and IP average residential rates are expected to increase in 2007 by approximately 40% over 2006 rates, and CILCO average residential rates are expected to increase approximately 55% over 2006 rates. The estimated average annual residential overall increase for electric heat customers is expected to be 60% to 80% over 2006 rates. Due to the impact to electric heat customers of eliminating subsidizations from other customer classes, the ICC initiated, in March 2007, an investigation into all aspects of rate design for all customer classes of CIPS, CILCO and IP. Any rate design change is not expected to change total revenues. Due to the magnitude of these increases, various Illinois legislators, the Illinois attorney general, the Illinois governor and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. CIPS, CILCO and IP have received favorable rulings from the ICC and the circuit court of Cook County, Illinois on opposition claims filed by the Illinois attorney general, CUB and ELPC. These rulings are currently under court appeals. In addition, the Illinois attorney general filed a complaint with FERC in March 2007 asking for an investigation into alleged price manipulation by suppliers in the power procurement auction. Two similar class action lawsuits were filed in the circuit court of Cook County, Illinois also alleging price manipulation. |
| · | On April 20, 2007, the Illinois Senate approved legislation, known as Senate Bill 1592, that, if enacted into law, would reduce electric rates of CIPS, CILCO and IP to the rates which were in effect prior to January 2, 2007. As passed by the Illinois Senate, Senate Bill 1592 would not impact other Illinois utilities. Senate Bill 1592 provides that the cost of electric energy reflected in the Ameren Illinois Utilities’ electric rates in effect prior to January 2, 2007, cannot be changed for a period of one year after enactment into law. This would prevent 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 power procurement auction for at least one year after enactment into law, and would cause the Ameren Illinois Utilities to under recover their delivery service costs until the ICC could approve higher delivery service rates. Senate Bill 1592 also includes a requirement for refunds, with interest, of charges collected from customers since January 2, 2007, in excess of the pre-January 2, 2007 rates. If this requirement were enacted, CIPS, CILCO and IP would have to refund approximately $37 million, $21 million, and $49 million, respectively, of such charges collected from customers during the three months ended March 31, 2007. On March 6, 2007, the Illinois House of Representatives approved legislation that would apply to the Ameren Illinois Utilities and Commonwealth Edison Company and which provides for a three-year rate freeze and included a similar refund requirement. To become law in Illinois, legislation must be passed by the House of Representatives and Senate and signed by the Governor. The Governor has previously expressed support for rate rollback and freeze legislation. Despite passage by the Illinois House of Representatives and the Illinois Senate of similar rate freeze legislation and statements by the Illinois Governor in support of rate rollback and freeze legislation, it is uncertain whether Senate Bill 1592, the House legislation or any rate rollback and freeze legislation will ultimately be enacted into law. Ameren, CIPS, CILCORP, CILCO and IP believe that any legislation reducing electric rates to pre-January 2, 2007, levels is unlawful and unconstitutional. In the event that such legislation is enacted into law, the Ameren Illinois Utilities intend to vigorously pursue all available legal actions and strategies to protect their legal and financial interests, including seeking immediate injunctive relief to prevent the implementation of such legislation. They believe that such actions will be successful in both enjoining the implementation of, and ultimately invalidating, such legislation. |
| · | Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences would 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. |
| · | The Ameren Illinois Utilities, Commonwealth Edison Company and others have been in discussions with members of the Illinois General Assembly and other stakeholders to develop a constructive solution to provide rate relief to Illinois customers in lieu of reducing electric rates to pre-January 2, 2007 levels or applying a tax on electric generation in Illinois. Through discussions with Senate leaders prior to the Senate’s passage of Senate Bill 1592 on April 20, 2007, the Ameren Illinois Utilities, Commonwealth Edison Company and others had agreed to offer more than $150 million in relief to the Illinois electric customers affected most by the rate increases. Over $85 million of electric customer bill credits and other assistance were specifically targeted for the Ameren Illinois Utilities’ customers. The customer assistance proposal was primarily aimed at residential, small business and not-for-profit users, particularly those Ameren Illinois Utilities’ customers who depend on electricity for heating their homes. Those customers, who since January 1, 2007, have absorbed the largest rate increases, had been in line to receive the most benefit from the rate proposal. The Ameren Illinois Utilities were prepared to reinstate their Customer-Elect rate increase phase-in plan capping annual rate increases at 14 percent with no carrying costs on deferred balances. This proposal was not instituted and the Customer-Elect rate increase phase-in plan has not been reinstated because the Illinois General Assembly continued to support rolling back and freezing electric rates at pre-January 2, 2007 levels. The Ameren Illinois Utilities believe that a constructive solution to the current rate situation remains in the best interests of all customers of the Ameren Illinois Utilities and the Ameren Illinois Utilities remain committed to working with stakeholders to reach such a solution. Even a constructive solution could cause Ameren, CIPS, Genco, CILCO, CILCORP and IP to incur significant costs. |
| · | 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 Illinois General Assembly may consider changes to the Illinois power procurement process in the future. The ICC is currently reviewing the auction process to determine whether any changes should be implemented prior to the next auction. The next Illinois power procurement auction for the Ameren Illinois Utilities is scheduled to take place in January 2008. |
| · | In July 2006, UE filed requests with the MoPSC for an increase in electric rates of $361 million and in natural gas delivery rates of $11 million. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million. Other stakeholders also made recommendations. As the result of the settlement of some issues in the electric case in April 2007 UE’s request for an increase in annual electric revenues was changed to $245 million and the MoPSC staff recommended revenue reduction was changed to $39 million to $75 million. A decision from the MoPSC is expected no later than June 2007. 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. In addition, UE agreed to not 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 surcharge. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of Missouri rate matters. |
| · | 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. About 1 million megawatthours of these contracts expire by the end of 2007 and another 2 million contracted megawatthours expire by the end of 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). Genco, AERG and EEI have contracts to sell all of their power to Marketing Company. Marketing Company resells this power and provides the net proceeds to Genco, AERG and EEI. |
| · | 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, as of March 31, 2007, Non-rate-regulated Generation has sold approximately 90% of its expected 2007 generation output (29 million megawatthours) at an average price of $51 per megawatthour. Expected sales in 2007 include an estimated 7.6 million megawatthours of power sold |
| | through the Illinois power procurement auction at about $65 per megawatthour (2008 - 6.8 million, 2009 - 4.3 million). Including Illinois auction sales, approximately 55% to 60% of the expected generation output in 2008 was sold as of March 31, 2007. |
| · | We expect continued economic growth in our service territory to benefit energy demand in 2007 and beyond, but higher energy prices could result in reduced demand from consumers, especially in Illinois. |
| · | UE, Genco and CILCO are seeking to raise the equivalent availability and capacity factors of their power plants through greater investments and a process improvement program and investment. |
| · | Very volatile power prices in the Midwest affect the amount of revenues Ameren, UE, Genco and CILCO (through AERG) can generate by marketing power into the wholesale and spot markets and influence the cost of power purchased in the spot markets. These companies hedged approximately 86% of estimated available 2007 generation (2008 - 70%, 2009 - 60%). |
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 March 31, 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 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. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. UE requested a fuel and purchased power cost recovery mechanism in its electric rate case filed with the MoPSC in July 2006. The MoPSC staff and intervenors in the electric rate case have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost recovery mechanism as part of its pending Missouri electric case, but no rules have been established for such a mechanism. UE’s requests are subject to approval by the MoPSC. A decision from the MoPSC is expected no later than June 2007. |
| · | 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. Until reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, a final decision about whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, Taum Sauk will remain out of service. 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) caused by the breach, including rebuilding the plant, will be covered by insurance. UE expects the total cost for clean up, damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $137 million to $157 million. As of March 31, 2007, UE had paid $76 million and accrued a $61 million liability, including costs resulting from the FERC stipulation and consent agreement, while expensing $30 million, and recording a $107 million receivable due from insurance companies. As of March 31, 2007, UE had received $30 million from insurance companies |
| | reducing the insurance receivable to $77 million. As of March 31, 2007, UE had a $10 million receivable duefrom 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 a result of this breach, UE is engaged in litigation initiated by certain private parties and by state authorities. 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. |
| · | UE’s Callaway nuclear plant’s scheduled refueling and maintenance outage which commenced April 1, 2007 was completed on May 10, 2007. 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 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 September 1, 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 April 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. Preparing a COLA does not mean a decision has been made to build a nuclear plant. It is only the first step in the regulatory licensing 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’s, CIPS’, CILCO’s and IP’s performance during these storms is subject to regulatory and legislative review and media attention. Recommendations to improve service during severe storms resulting from regulatory and internal reviews could include more aggressive tree removal and trimming programs, comprehensive pole and line inspections and burial of more electric services, among other things. In 2007, UE will begin to spend an additional $100 million per year on converting overhead circuits to underground lines. We would expect any additional costs or investments to be recovered 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 it was paid by Genco. Genco will no longer receive the margins on sales that it made, which were fulfilled with power from UE. Ameren’s and UE’s earnings will be affected by the termination of the JDA when UE’s rates are adjusted by the MoPSC. UE’s requested electric rate increase filed in July 2006 is net of the decrease in its 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 Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006. See Item 7A under Part II of the 2006 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 March 31, 2007:
| | Interest Expense | | | Net Income(a) | |
| Ameren | $ | 18 | | $ | (11) | |
| UE | | 11 | | | (7) | |
| CIPS | | 1 | | | (1) | |
| Genco | | 1 | | | (1) | |
| CILCORP | | 3 | | | (2) | |
| CILCO | | 2 | | | (1) | |
| IP | | 5 | | | (3) | |
| (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 receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large
number of customers in a broad range of industry groups who make up our customer base. At March 31, 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 March 31, 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 - $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 $22 million at March 31, 2007 (2006 - $32 million).
Equity Price Risk
Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. 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.
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 pending electric rate case filed in July 2006, UE has requested approval by the MoPSC for a fuel and purchased power cost recovery mechanism.
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 | % | | 41 | % |
| Coal transportation | 100 | | | 95 | | | 43 | |
| Nuclear fuel | 100 | | | 91 | | | 51 | |
| Natural gas for generation | 85 | | | 14 | | | - | |
Natural gas for distribution(a) | (a) | | | 23 | | | 8 | |
Purchased power for Illinois Regulated(b) | 100 | | | 81 | | | 21 | |
UE: | | | | | | | | |
| Coal | 100 | % | | 94 | % | | 41 | % |
| Coal transportation | 100 | | | 97 | | | 61 | |
| Nuclear fuel | 100 | | | 91 | | | 51 | |
| Natural gas for generation | 81 | | | 7 | | | - | |
Natural gas for distribution(a) | (a) | | | 21 | | | 5 | |
CIPS: | | | | | | | | |
Natural gas for distribution(a) | (a) | | | 34 | | | 13 | |
Purchased power(b) | 100 | | | 81 | | | 21 | |
Genco: | | | | | | | | |
| Coal | 100 | % | | 96 | % | | 38 | % |
| Coal transportation | 100 | | | 97 | | | 35 | |
| Natural gas for generation | 100 | | | 53 | | | - | |
CILCORP/CILCO: | | | | | | | | |
| Coal (AERG) | 100 | % | | 96 | % | | 42 | % |
| Coal transportation (AERG) | 100 | | | 71 | | | 23 | |
Natural gas for distribution(a) | (a) | | | 21 | | | 7 | |
Purchased power(b) | 100 | | | 81 | | | 21 | |
IP: | | | | | | | | |
Natural gas for distribution(a) | (a) | | | 21 | | | 7 | |
Purchased power(b) | 100 | | | 81 | | | 21 | |
EEI: | | | | | | | | |
| Coal | 100 | % | | 96 | % | | 43 | % |
| Coal transportation | 100 | | | 100 | | | - | |
| (a) | Represents the percentage of natural gas price-hedged for the peak winter season of November through March. The year 2007 represents the period January 2007 through March 2007 and is therefore non-applicable for this report. 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) | $ | 18 | | $ | (11) | | $ | 14 | | $ | (9) | |
| UE | | 8 | | | (5) | | | 5 | | | (3) | |
| Genco | | 6 | | | (4) | | | 4 | | | (3) | |
| CILCORP | | 3 | | | (2) | | | 2 | | | (1) | |
| CILCO (AERG) | | 3 | | | (2) | | | 2 | | | (1) | |
| EEI | | 2 | | | (1) | | | 3 | | | (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 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. As discussed in Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report. UE is seeking approval of the MoPSC of a fuel and purchased power cost recovery mechanism in its pending electric rate case filed in July 2006, which if approved could mitigate the impact of increased fuel cost at Ameren and UE.
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 quarter ended March 31, 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 | |
| Fair value of contracts at beginning of period, net | $ | 98 | | $ | 12 | | $ | 2 | | $ | (1 | ) | $ | 6 | | $ | 2 | |
| Contracts realized or otherwise settled during the period | | (17 | ) | | (4 | ) | | - | | | - | | | (2 | ) | | - | |
Changes in fair values attributable to changes in valuation technique and assumptions | | - | | | - | | | - | | | - | | | - | | | - | |
| Fair value of new contracts entered into during the period | | (2 | ) | | (1 | ) | | - | | | - | | | - | | | - | |
| Other changes in fair value | | (48 | ) | | (7 | ) | | 1 | | | - | | | 2 | | | (2 | ) |
| Fair value of contracts outstanding at end of period, net | $ | 31 | | $ | - | | $ | 3 | | $ | (1 | ) | $ | 6 | | $ | - | |
| (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 affect 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 March 31, 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 | | | 5 | | | - | | | - | | | - | | | 5 | |
Prices provided by other external sources(a) | | | 4 | | | 2 | | | - | | | - | | | 6 | |
Prices based on models and other valuation methods(b) | | | 18 | | | 2 | | | - | | | - | | | 20 | |
| Total | | | 27 | | | 4 | | | - | | | - | | | 31 | |
UE: | | | | | | | | | | | | | | | | |
| Prices actively quoted | | | - | | | - | | | - | | | - | | | - | |
Prices provided by other external sources(a) | | | 2 | | | - | | | - | | | - | | | 2 | |
Prices based on models and other valuation methods(b) | | | (2 | ) | | - | | | - | | | - | | | (2 | ) |
| Total | | | - | | | - | | | - | | | - | | | - | |
CIPS: | | | | | | | | | | | | | | | | |
| Prices actively quoted | | | - | | | - | | | - | | | - | | | - | |
Prices provided by other external sources(a) | | | 3 | | | - | | | - | | | - | | | 3 | |
Prices based on models and other valuation methods(b) | | | - | | | - | | | - | | | - | | | - | |
| Total | | | 3 | | | - | | | - | | | - | | | 3 | |
GENCO: | | | | | | | | | | | | | | | | |
| Prices actively quoted | | | (1 | ) | | - | | | - | | | - | | | (1 | ) |
Prices provided by other external sources(a) | | | - | | | - | | | - | | | - | | | - | |
Prices based on models and other valuation methods(b) | | | - | | | - | | | - | | | - | | | - | |
| Total | | | (1 | ) | | - | | | - | | | - | | | (1 | ) |
CILCORP/CILCO: | | | | | | | | | | | | | | | | |
| Prices actively quoted | | | - | | | - | | | - | | | - | | | - | |
Prices provided by other external sources(a) | | | 4 | | | 2 | | | - | | | - | | | 6 | |
Prices based on models and other valuation methods(b) | | | - | | | - | | | - | | | - | | | - | |
| Total | | | 4 | | | 2 | | | - | | | - | | | 6 | |
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 vs. floating over-the-counter power swaps, power forwards and fixed price vs. floating over-the-counter natural gas swaps. |
| (b) | Principally coal and SO2 option values based on a Black-Sholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates. |
ITEM 4. CONTROLS AND PROCEDURES.
| (a) | Evaluation of Disclosure Controls and Procedures |
As of March 31, 2007, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
| (b) | 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 sub-stantial 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 Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2006, 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 that Form 10-K.
The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are currently the subject of rate case proceedings and potential legislative action. The outcome of these proceedings and of other potential legislative action or future rate proceedings is largely outside of our control. Should these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position or liquidity. In particular, we believe rolling back and freezing electric rates at 2006 levels in Illinois would lead to the financial insolvency and bankruptcy of CIPS, CILCORP, CILCO and IP.
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, or liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on our results of operations, financial position, or liquidity.
Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. Ameren expects that many of its operating expenses will continue to rise. Ameren further expects to continue to make significant investment in its energy infrastructure. These are the two principal factors underlying the pending electric rate increase request with the MoPSC and the rate increase requests recently acted upon and pending rehearing with the ICC. We cannot predict the outcome of
these rate case proceedings or of potential Illinois legislative action to deny full recovery of costs. In addition, in response to competitive, economic, political, legislative and regulatory pressures, in connection with the resolution of our current rate case proceedings or otherwise, we may be subject to further rate moratoriums, rate refunds, limits on rate increases, or rate reductions, including phase-in plans. Any or all of these could have a material adverse effect on our results of operations, financial position, or liquidity.
Illinois
Electric Delivery Service Rate Cases
A provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS - an $8 million decrease, CILCO - a $21 million increase and IP - an $84 million increase) based on an allowed return on equity of 10%. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling $50 million, that were disallowed. The administrative law judges issued a proposed order in April 2007 recommending no recovery of these expenses for CIPS, CILCO and IP. The ICC’s decision on the recovery of these expenses is due in May 2007. The ICC denied requests for rehearings filed by other parties in this case. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which included the cost of power, so these delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.
Potential Electric Rate Rollback and Freeze, and Recovery of Post-2006 Power Supply Costs
Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expired on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006.
Subsequently, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, and the independent auction manager declared a successful result in the auction for these fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. Various Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers.
On April 20, 2007, the Illinois Senate approved legislation, known as Senate Bill 1592, that, if enacted into law, would reduce electric rates of CIPS, CILCO and IP to the rates which were in effect prior to January 2, 2007. As passed by the Illinois Senate, Senate Bill 1592 would not impact other Illinois utilities. Senate Bill 1592 provides that the cost of electric energy reflected in the Ameren Illinois Utilities’ electric rates in effect prior to January 2, 2007, cannot be changed for a period of at least one year after enactment into law. This would prevent 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 discussed above for at least one year after enactment into law, and would cause the Ameren Illinois Utilities to under recover their delivery service costs until the ICC could approve higher delivery service rates. Senate Bill 1592 also includes a requirement for refunds, with interest, of charges collected from customers since January 2, 2007, in excess of the pre-January 2, 2007 rates. If this requirement were enacted, CIPS, CILCO and IP would have to refund approximately $37 million, $21 million, and $49 million, respectively, of such charges collected from customers during the three months ended March 31, 2007. On March 6, 2007, the Illinois House of Representatives approved legislation that would apply to the Ameren Illinois Utilities and Commonwealth Edison Company and which provides for a three-year rate freeze and included a similar refund requirement. To become law in Illinois, legislation must be passed by the House of Representatives and Senate and signed by the Governor. The Governor has previously expressed support for rate rollback and freeze legislation. Despite passage by each of the Illinois House of Representatives and the Illinois Senate of similar rate
rollback and freeze legislation and statements by the Illinois Governor in support of rate rollback and freeze legislation, it is uncertain whether Senate Bill 1592, the House legislation or any rate rollback and freeze legislation will ultimately be enacted into law.
Ameren, CIPS, CILCORP, CILCO and IP believe that any legislation reducing electric rates to pre-January 2, 2007, levels is unlawful and unconstitutional. In the event that such legislation is enacted into law, the Ameren Illinois Utilities intend to vigorously pursue all available legal actions and strategies to protect their legal and financial interests, including seeking immediate injunctive relief to prevent the implementation of such legislation. They believe that such actions will be successful in both enjoining the implementation of, and ultimately invalidating, such legislation.
Even if efforts to promptly enjoin the implementation of legislation to reduce electric rates to pre-January 2, 2007 levels were successful, Ameren, CIPS, CILCORP, CILCO and IP believe that the mere enactment into law of such legislation would nonetheless result in material adverse consequences to CIPS, CILCORP, CILCO and IP until final resolution of any litigation challenging such legislation. These material adverse consequences would include a significant drop in credit ratings to deep junk (or speculative) status, requirements to post collateral or other assurances for certain obligations, a reduction in access to the capital markets on reasonable terms and higher borrowing costs. These material adverse consequences could also include higher power supply costs, an inability to make timely energy infrastructure investments, disruption in electric and gas service and significant job losses. Consequently, the Ameren Illinois Utilities anticipate that their results of operations, financial position and liquidity would be materially adversely affected. Ameren’s results of operations, financial position and liquidity could also be materially adversely affected.
If legislation to reduce electric rates to pre-January 2, 2007 levels is enacted into law and the implementation of such legislation is not promptly enjoined, Ameren, CIPS, CILCORP, CILCO and IP believe that their results of operations, financial position, and liquidity would be materially adversely affected. These material adverse consequences would include a significant drop in credit ratings to deep junk (or speculative) status, a severe limitation on their ability to procure reasonable financing from third party lending sources, 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, the likely disruption in electric and gas service, significant job losses, and ultimately the financial insolvency and bankruptcy of CIPS, CILCORP, CILCO and IP.
Ameren, CIPS, CILCORP, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois Utilities will prevail over the stated opposition by various Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois Utilities are considering will be successful.
We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, the results of the two class action lawsuits and the Illinois attorney general’s complaint filed with FERC alleging price manipulation in the September 2006 auction, nor the actions the Illinois General Assembly and Governor may take that might affect electric rates or the power procurement process for CIPS, CILCO and IP. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences would 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, the likely 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 rate freeze legislation.
Missouri
With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In December 2006, the MoPSC staff and other stakeholders filed direct testimony in response to UE’s electric rate case filing. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million. Subsequently, parties in this rate case have settled certain issues. As a result, UE and the MoPSC staff revised their positions in testimony filed with the MoPSC in April 2007. UE’s revised position is an electric rate increase request of $245 million and the MoPSC staff’s revised position is an electric rate reduction request of $39 million to $75 million. Other parties also filed testimony in the case. A decision from the MoPSC is expected no later than June 2007. 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 to not 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%. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.
UE does not currently have a rate-adjustment clause for its electric operations in Missouri that would allow it to recover from customers the costs for purchased power, fuel, or infrastructure investment. Therefore, insofar as UE has not hedged its fuel and power costs, UE is exposed to changes in fuel and power prices to the extent they exceed the costs embedded in current electric rates. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism that would be subject to MoPSC approval. The MoPSC staff and intervenors in the electric rate case have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost-recovery mechanism as part of its pending Missouri electric rate case, but no rules have been established for such a mechanism. Any new energy infrastructure investment could result in increased financing requirements for UE, which could increase further depending on rate case outcomes. The lack of timely recovery of these costs could have a material adverse effect on UE’s results of operations, financial position, or liquidity. We are unable to predict whether the MoPSC will approve our request for a fuel and purchased power cost recovery mechanism in our pending electric rate case. We also are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted.
Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.
We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including those related to future environmental compliance. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. See the Credit Ratings section in Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part I, Item 2, of this report for a discussion of credit rating changes in response to actions in Illinois with respect to legislation to rollback and freeze rates at 2006 levels.
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 | |
| January 1 - January 31, 2007 | 13,000 | | $ | 54.15 | | | - | | | - | |
| February 1 - February 28, 2007 | 3,000 | | | 54.15 | | | - | | | - | |
| March 1 - March 31, 2007 | 29,108 | | | 52.33 | | | - | | | - | |
| Total | 45,108 | | $ | 52.97 | | | - | | | - | |
| (a) | Included in January were 12,000 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for director compensation awards. Included in March were 29,108 shares of Ameren common stock purchased by Ameren from employee participants to satisfy participants’ tax obligations incurred by the release of restricted shares of Ameren common stock under Ameren’s Long-term Incentive Plan of 1998. The remaining 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. 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 January 1 to March 31, 2007 period.
ITEM 6. EXHIBITS.
(a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP as indicated.
Exhibit Designation | Registrant(s) | Nature of Exhibit |
Material Contracts |
| 10.1 | Ameren Companies | *Amended and Restated Ameren Corporation Change of Control Severance Plan (filed to correct and replace in its entirety due to an administrative error the Amended and Restated Ameren Corporation Change of Control Severance Plan previously filed as Exhibit 10.5 to the Ameren Companies’ Current Report on Form 8-K dated February 16, 2006 and to update Schedule I thereto). |
| 10.2 | Ameren Companies | *2007 Base Salary Table for Named Executive Officers |
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 |
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 |
Exhibit Designation | Registrant(s) | Nature of Exhibit |
| 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 |
Additional Exhibits | | |
| 99.1** | Ameren | Press release regarding earnings for the quarter ended March 31, 2007, issued on May 10, 2007 by Ameren Corporation |
| * | Management compensatory plan or arrangement. |
| ** | This exhibit has been furnished and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities under that Section and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Exchange Act. |
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 Controller
(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: May 10, 2007
84
