summer weather, the implementation of the June 2007 Missouri electric rate order and higher electric margin in Non-rate-regulated Generation due to the replacement of below-market power sales contracts that expired in 2006.
In late August 2007, the Illinois governor signed into law the enabling legislation for the Illinois electric settlement agreement that was reached among key stakeholders in Illinois deigned to address the increase in electric rates that occurred after the state’s electric rate freeze ended on January 1, 2007, and to address the future power procurement process in Illinois. As part of the Illinois settlement agreement, the electric customers of the Ameren Illinois Utilities will receive $488 million in bill credits and refunds and other relief through 2010 as part of an approximately $1 billion state-wide relief package. The Ameren Illinois Utilities, Genco and AERG will be funding $150 million, in the aggregate, of this program over a four-year period. The total impact to Ameren’s earnings per share is expected to be about 45 cents per share spread across four years, including 26 cents per share in 2007. The Ameren Illinois Utilities began sending checks and providing bill credits to customers in September 2007. Ameren recorded 18 cents per share of these costs in the third quarter of 2007. Other key aspects of the settlement agreement are currently being implemented including those related to power procurement in the future.
Ameren’s Illinois Regulated business segment experienced a significant earnings decline during the third quarter and first nine months of 2007 compared with 2006 due to, among other things, its current levels of electric and gas delivery service rates being insufficient to recover its current costs of providing service to its customers. In early November 2007, the Ameren Illinois Utilities filed requests with the ICC for a combined $247 million increase in electric and gas rates. As the Illinois Regulated business segment’s recent earnings results indicate, these rate increase requests are clearly needed by the Ameren Illinois Utilities and are consistent with the Ameren Illinois Utilities’ need to recover their costs of providing safe and reliable service to their customers and earning a reasonable return on their investments. Earlier this year, the Ameren Illinois Utilities pledged to keep the overall annual residential electric bill increases in Illinois to less than 10 percent per year for each utility in their next rate filings. These Illinois rate filings are consistent with that pledge. This self-imposed rate increase limit could result in approximately $30 million of the increase request not being phased-in until the second year of implementation if the full request is granted by the ICC. The Ameren Illinois Utilities’ also requested rate mechanisms for bad debt expenses, electric infrastructure investments and the decoupling of natural gas revenues from volumes. The ICC has eleven months to make a decision on these filings. With rising costs, including fuel and related transportation, purchased power, labor and material costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until requests to increase rates to recover such costs are granted by state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary.
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.
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 cost 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 and recently-decided rate cases and the electric settlement agreement in Illinois. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Ameren’s net income decreased to $244 million, or $1.18 per share, in the third quarter of 2007 from $293 million, or $1.42 per share, in the third quarter of 2006. Net income in the Missouri Regulated and Non-rate-regulated Generation segments in the three months ended September 30, 2007, increased by $37 million and $11 million, respectively, from the prior-year period, while net earnings in the Illinois Regulated segment declined by $92 million.
Ameren’s net income increased to $510 million, or $2.46 per share, in the first nine months of 2007 from $486 million, or $2.37 per share, in the first nine months of 2006. Net income increased in the Missouri Regulated and Non-rate-regulated Generation segments by $9 million and $95 million, respectively, in the first nine months of 2007 compared to the prior-year period, while net income in the Illinois Regulated segment decreased by $80 million.
Earnings were favorably impacted in the third quarter and first nine months of 2007 as compared with the same periods in 2006 by:
Earnings were negatively impacted in the third quarter and first nine months of 2007 as compared with the same periods in 2006 by:
In addition to the above items affecting both periods, earnings were impacted in the first nine months of 2007 as compared with the first nine months of 2006 by the following items:
An increase in the number of common shares outstanding reduced Ameren’s earnings per share in the 2007 periods compared with the 2006 periods. Per share information presented above is based on average shares outstanding in 2006.
Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the three and nine months ended September 30, 2007 and 2006:
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three and nine months ended September 30, 2007, compared with the same periods in 2006. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
Ameren
Ameren’s electric margin decreased by $29 million for the three months and increased by $190 million for the nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | Non-rate-regulated Generation selling more power at market-based prices in the third quarter and first nine months of 2007 compared with sales at below-market prices pursuant to cost-based power supply agreements, which expired on December 31, 2006; |
| · | favorable weather conditions increased native load electric margin by an estimated $33 million and $54 million for the three and nine months ended September 30, 2007, respectively; |
| · | UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated, $15 million and $20 million for the three and nine months ended September 30, 2007, respectively; |
| · | an increase in margin on interchange sales primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher purchased power prices. This increase was partially offset by higher purchased power costs of $8 million and $12 million for the three and nine months ended September 30, 2007, respectively, associated with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc. In addition, increased native load demand, because of warmer weather, reduced excess power available for sale; |
| · | increased revenues as a result of lower than expected line losses at UE; |
| · | increased hydroelectric generation, which favorably impacted purchased power cost; |
| · | severe storm-related outages that occurred in 2006, which negatively impacted electric sales and resulted in an estimated net reduction in overall electric margin of $5 million and $8 million for the three and nine months ended September 30, 2006, respectively; |
| · | unrealized mark-to-market net gains on fuel and energy contracts not yet settled increased electric margin by $4 million and $11 million for the three and nine months ended September 30, 2007, respectively; and |
| · | decreased fuel costs due to the lack of $4 million in fees levied by the FERC in the nine months ended September 30, 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years. |
The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | the combined effect of the elimination of the Ameren Illinois Utilities’ bundled tariffs, implementation of new delivery service tariffs including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts; |
| · | a 15% and 12% increase in coal and related transportation prices for the three and nine months ended September 30, 2007, respectively; |
| · | rate relief and customer assistance programs under the Illinois electric settlement agreement reduced electric margin by $53 million. Illinois customer refund payments and credits, including the forgiveness of late payment charges, provided to certain Ameren Illinois Utilities’ electric customers of $159 million for the three and nine months ended September 30, 2007, decreased electric revenue. As part of the settlement agreement, Ameren expects to receive reimbursements from non-affiliated generators in Illinois totaling $106 million for the three and nine months ended September 30, 2007; |
| · | MISO purchased power costs were $18 million and $29 million higher for the three and nine months ended September 30, 2007, respectively. Costs related to participation in the MISO Day Two Energy Market were higher for the year because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005; and |
| · | decreased emission allowance sales of $20 million and $22 million offset by lower emission allowance costs of $4 million and $12 million for the three and nine months ended September 30, 2007, respectively. |
Ameren’s gas margin was comparable in the three months ended September 30, 2007, with the same period in 2006. Ameren’s gas margin increased by $10 million, or 4%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 14% increase in heating degree-days for the nine months ended September 30, 2007.
Missouri Regulated
UE
UE’s electric margin increased $55 million and $89 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had a favorable impact on electric margin
for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | an increase in margin on interchange sales primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher market prices. This increase was partially offset by increased purchased power costs of $8 million and $12 million for the three and nine months ended September 30, 2007, respectively, associated with an agreement with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc. In addition, increased native load demand, because of warmer weather, reduced excess power available for sale; |
| · | favorable weather conditions increased native load electric margin by an estimated $31 million and $44 million for the three and nine months ended September 30, 2007, respectively; |
| · | the electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $15 million and $20 million for the three and nine months ended September 30, 2007, respectively; |
| · | increased revenues as a result of lower than expected line losses; |
| · | increased hydroelectric generation, which favorably impacted purchased power costs; |
| · | severe storm-related outages in 2006, which reduced electric margin by $3 million and $6 million for the three and nine months ended September 30, 2006, respectively; and |
| · | decreased fuel costs due to the lack of $4 million in fees levied by the FERC in the nine months ended September 30, 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years. |
Factors that had an unfavorable impact on electric margin for the three and nine months ended September 30, 2007, as compared to the same periods in the prior year, were as follows:
| · | a 24% and 17% increase in coal and related transportation prices for the three- and nine-month periods ended September 30, 2007, respectively; |
| · | MISO costs were $12 million higher for the nine months ended September 30, 2007, compared to the same period in 2006, due to the March 2007 FERC order; |
| · | other MISO purchased power costs, excluding the effect of the March 2007 FERC order, were $18 million higher for the third quarter of 2007 and $9 million higher for the nine months ended September 30, 2007, compared to the same periods in 2006; and |
| · | reduced power plant availability because of planned maintenance activities. |
UE’s gas margin was comparable in the three months ended September 30, 2007, with the same period in 2006. UE’s gas margin increased by $5 million, or 11%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 15% increase in heating degree-days for the nine months ended September 30, 2007.
Illinois Regulated
Illinois Regulated’s electric margin declined by $134 million, or 42%, and $95 million, or 14%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. Illinois Regulated’s gas margin decreased by $4 million in the third quarter of 2007 and increased by $5 million, or 2%, for the nine months ended September 30, 2007, compared with the same periods in 2006.
CIPS
CIPS’ electric margin decreased by $44 million, or 43%, and $25 million, or 12%, for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts; |
| · | the Illinois settlement agreement reduced electric margin by $8 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $54 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $36 million due from non-affiliated generators and $10 million due from affiliated generators in Illinois; and |
| · | MISO costs increased $8 million for the nine months ended September 30, 2007, compared to the same period in 2006, because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005. |
The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | MISO purchased power costs, excluding the effect of the March 2007 FERC order discussed above, were $4 million and $16 million lower for the three and ninemonths ended September 2007, respectively, compared to the same periods in 2006; |
| · | severe storm-related outages in 2006, which reduced electric margin by $2 million for the three and nine months ended September 30, 2006; and |
| · | favorable weather conditions, which increased electric margin by an estimated $5 million for the nine months ended September 30, 2007. |
CIPS’ gas margin decreased by $2 million for the three months ended September 30, 2007, compared with the same period in 2006 primarily because of reduced transportation service revenues. CIPS’ gas margin increased by $1 million, or 2%, for the nine months ended September 30, 2007, primarily because of favorable weather conditions as evidenced by a 15% inrease in heating degree-days for the nine months ended September 30, 2007.
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 and nine months ended September 30, 2007, as compared with the same periods in 2006:
| | | Three Months | | | Nine Months | |
| CILCO (Illinois Regulated) | | $ | (24 | ) | | $ | (29 | ) |
| CILCO (AERG) | | | 22 | | | | 64 | |
| Total change in electric margin | | $ | (2 | ) | | $ | 35 | |
CILCO’s (Illinois Regulated) electric margin decreased by $24 million, or 45%, and $29 million, or 23%, for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts; |
| · | the Illinois settlement agreement reduced electric margin by $5 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $32 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $21 million from non-affiliated generators and by $6 million from affiliated generators in Illinois; and |
| · | MISO costs increased $4 million for the nine months ended September 30, 2007, because of the March 2007 FERC order noted above. |
The decrease in electric margin was reduced by favorable weather conditions, which increased electric margin by an estimated $2 million for the nine months ended September 30, 2007.
See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) change in electric margin for the three and nine months ended September 30, 2007, as compared with the same periods in 2006.
CILCO’s (Illinois Regulated) gas margin was comparable for the three months ended September 30, 2007, with the same period in 2006. CILCO’s (Illinois Regulated) gas margin increased by $4 million, or 7%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 12% increase in heating degree-days in the first nine months of 2007 and growth in the industrial sector.
IP
IP’s electric margin decreased by $66 million, or 41%, and $41 million, or 13%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts; |
| · | the Illinois settlement agreement reduced electric margin by $11 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $73 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $49 million from non-affiliated generators and by $13 million from affiliated generators in Illinois; and |
| · | the March 2007 FERC order, referenced above, reduced IP’s electric margin by $14 million for the nine months ended September 30, 2007, compared to the same period a year ago. |
The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | favorable weather conditions, which increased electric margin by an estimated $2 million and $4 million for the three and nine months ended September 30, 2007, respectively; and |
| · | severe storm-related outages in 2006, which reduced electric margin by $1 million for the three and nine months ended September 30, 2006. |
IP’s gas margin was comparable for the three and nine months ended September 30, 2007, compared with the same periods in 2006, primarily because of reduced transportation service revenues, partially offset by favorable weather conditions as evidenced by a 13% increase in heating degree-days for the nine months ended September 30, 2007.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $46 million, or 21%, and $196 million, or 34%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
Genco
Genco’s electric margin increased by $29 million, or 33%, and $110 million, or 42%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | selling power at market-based prices for the three and nine months ended September 30, 2007, compared with selling power at below-market prices pursuant to a cost-based power supply agreement, which expired on December 31, 2006. This was offset, in part, by the loss of margin on sales supplied with power acquired through the JDA; |
| · | reduced purchased power costs due to the expiration of the JDA; |
| · | increased power plant availability due to fewer planned outages this year reduced purchased power costs; |
| · | a reduction of mark-to-market losses on fuel contracts in 2007, which amounted to $5 million for the nine months ended September 30, 2006; and |
| · | MISO costs were $12 million lower for the nine months ended September 30, 2007, compared with the same period in 2006, as a result of the March 2007 FERC order. |
The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | costs of $20 million for the three and nine months ended September 30, 2007, pursuant to the Illinois electric settlement agreement discussed above; and |
| · | a 3% increase in coal and related transportation prices for the three and nine months ended September 30, 2007, respectively. |
CILCO (AERG)
For the three and nine months ended September 30, 2007, AERG’s electric margin increased by $22 million, or 82%, and $64 million, or 72%, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | increased revenues due to selling power at market-based prices in the third quarter of 2007 compared with sales at below-market prices in 2006 pursuant to a cost-based power supply agreement, which expired on December 31, 2006; and |
| · | reduced emission costs of $3 million and $8 million for the three and nine months ended September 30, 2007, respectively, compared with the same prior-year periods. |
The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared with the year-ago periods:
| · | costs of $9 million for the three and nine months ended September 30, 2007, pursuant to the Illinois electric settlement agreement discussed above; |
| · | revenues and fuel costs decreased due to reduced plant availability because of an extended plant outage; and |
| · | a 12% increase in coal and related transportation prices for the nine months ended September 30, 2007. |
EEI
EEI’s electric margin decreased by $36 million, or 35%, and $28 million, or 12%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
| · | the lack of emissions allowance sales in 2007, which increased the electric margin by $30 million for the three and nine months ended September 30, 2006; |
| · | a 5% increase in coal and related transportation prices for the three and nine months ended September 30, 2007; and |
| · | revenues and fuel costs decreased due to reduced plant availability due to increased unit outages in the three and nine months ended September 30, 2007. |
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Ameren
Three months – Other operations and maintenance expenses increased $32 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher plant maintenance expenditures of $12 million due to outages at coal-fired plants, increased distribution system reliability and maintenance expenditures, higher labor and employee benefits costs, and increased injuries and damages expenses. Additionally, as part of the Illinois electric settlement agreement, we paid $4 million to the IPA in the third quarter of 2007. The amount of the increase in expenses in the third quarter of 2007 over 2006 was lower than it otherwise would have been because in the third quarter of 2006, we experienced severe storms in our service territory resulting in expenses of $23 million, while there were no major storms in our service territory during the third quarter ended September 30, 2007. Additionally, in the third quarter of 2006, Ameren recorded $7 million of costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant with no similar costs recorded in the third quarter of 2007.
Nine months - Other operations and maintenance expenses increased $108 million in the first nine months of 2007 compared with the first nine months of 2006. Maintenance and labor costs associated with the Callaway refueling and maintenance outage in the second quarter of 2007 added $35 million to other operations and maintenance expenses in the period. Higher non-Callaway labor costs, bad debt reserves, maintenance at coal-fired plants, the IPA payment described above, and distribution system reliability expenditures also increased other operations and maintenance expenses in the first nine months of 2007 compared to the year-ago period. 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. Additionally, in the prior-year period, we recognized costs related to the Taum Sauk reservoir breach of $17 million and noncore property sale losses of $7 million at a subsidiary of AERG, items which did not recur in 2007. Increased other operations and maintenance expenses resulting from a severe ice storm in January 2007 in UE’s and CIPS’ service territories were offset by the absence in 2007 of severe summer storms such as those that occurred in the summer of the prior year.
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 and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three months – Other operations and maintenance expenses were comparable in the third quarter of 2007 with the third quarter of 2006. Increased plant maintenance at coal-fired plants from scheduled outages, increased distribution system reliability and maintenance expenditures, and insurance premiums paid to an affiliate for replacement power coverage in the current year third quarter were offset by the absence of costs related to the Taum Sauk reservoir breach. In addition, there were no severe summer storms in 2007, which resulted in expenses of $16 million in the third quarter of 2006.
Nine months - Other operations and maintenance expenses increased $86 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of ice storm repair expenditures of approximately $25 million and costs associated with the Callaway refueling and maintenance outage of $35 million. Increased plant maintenance at coal-fired plants, increased distribution system reliability and maintenance expenditures, higher labor costs, and insurance premiums for replacement power coverage of $14 million paid to an affiliate also increased other operations and maintenance expenses in the first nine months of 2007 compared with the prior year period. Reducing the effect of these items was the absence in the current year period of costs related to the Taum Sauk reservoir breach and the absence of severe summer storms in 2007 such as those that occurred in the prior year period.
Illinois Regulated
Other operations and maintenance expenses increased $9 million and $17 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
CIPS
Three months – Other operations and maintenance expenses were comparable between periods as the absence of severe summer storms in 2007, such as those that occurred in the summer of the prior year, was offset by increased distribution system reliability and maintenance expenditures and by higher injuries and damages expenses.
Nine months - Other operations and maintenance expenses increased $7 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of increased bad debt reserves as a result of the transition to higher electric rates in Illinois, and increased distribution system reliability expenditures. The reversal in 2007 of the customer assistance program accrual of $4 million,
established in 2006 as noted above, reduced the effect of these increases. The impact of a severe ice storm in January 2007 was offset by the absence in 2007 of severe summer storms such as those that occurred in the summer of the prior year.
CILCO (Illinois Regulated)
Three months – Other operations and maintenance expenses were comparable between periods.
Nine months – Other operations and maintenance expenses were comparable between periods as an increase in bad debt reserves was offset by the reversal of the customer assistance program accrual of $3 million established in 2006 as noted above.
IP
Three months – Other operations and maintenance expenses increased $6 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher employee benefit costs and increased injuries and damages expenses. Reducing the unfavorable impact of these items was the absence of severe summer storms in 2007 such as those that occurred in the summer of 2006.
Nine months - Other operations and maintenance expenses increased $9 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher employee benefit costs and increased bad debt reserves. Reducing the effect of these items was the reversal of the customer assistance program accrual of $8 million, established in 2006 as noted above, and the absence of severe summer storms in 2007 such as those that occurred in the summer of the prior year.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $14 million and $23 million in the Non-rate-regulated Generation segment in the three and nine months ended
September 30, 2007, respectively, compared with the same periods in 2006.
Genco
Three months – Other operations and maintenance expenses increased $5 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher plant maintenance costs due to scheduled outages. Additionally, as part of the Illinois electric settlement agreement, Genco paid $3 million to the IPA in the third quarter of 2007.
Nine months - Other operations and maintenance expenses increased $9 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher labor costs, the IPA payment, and insurance premiums for replacement power coverage paid to an affiliate.
CILCORP (Parent Company Only)
Three months – Other operations and maintenance expenses were comparable between periods.
Nine months - Other operations and maintenance expenses were comparable between periods as increased employee benefit costs in the current year period were offset by the absence of a write-off in 2007, as occurred in the prior year period, of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.
CILCO (AERG)
Three months – Other operations and maintenance expenses were comparable between periods.
Nine months - Other operations and maintenance expenses increased $7 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher plant maintenance costs due to an extended plant outage.
EEI
Three and nine months - Other operations and maintenance expenses increased $2 million and $5 million in the three and nine months ended September 30, 2007, respectively, compared to the prior year periods primarily because of higher plant maintenance costs.
Depreciation and Amortization
Ameren
Three and nine months – Ameren’s depreciation and amortization expenses increased $7 million and $29 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The increases were primarily because of capital additions in 2006 and the start of amortization of a regulatory asset in 2007 associated with acquisition integration costs at IP, as required by an ICC order.
Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:
UE
Three months - Depreciation and amortization expenses were comparable between periods as increased depreciation expenses from capital additions were offset by decreased expenses resulting from the extension of UE’s plants’ useful lives in connection with a MoPSC electric rate order issued in May 2007. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information on UE’s electric rate order.
Nine months – Depreciation and amortization expenses increased $9 million in the nine months ended September 30, 2007, primarily because of capital additions in 2006 and early 2007, including CTs purchased in the second quarter of 2006, and storm-related expenditures in 2006.
Illinois Regulated
Depreciation and amortization expenses increased $5 million and $18 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
CIPS & CILCO (Illinois Regulated)
Three and nine months - Depreciation and amortization expenses were comparable between periods.
IP
Three and nine months – Depreciation and amortization expenses increased $4 million and $15 million in the three and nine months ended September 30, 2007, respectively, primarily because of amortization in 2007 of $4 million and $12 million for the three and nine months ended September 30, 2007, respectively, of a regulatory asset associated with acquisition integration costs, as required by an ICC order.
Non-rate-regulated Generation
Three and nine months - Depreciation and amortization expenses were comparable in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.
Taxes Other Than Income Taxes
Ameren
Three months – Ameren’s taxes other than income taxes were comparable between periods.
Nine months - Ameren’s taxes other than income taxes decreased $7 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of lower gross receipts and lower property tax expenses.
Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three and nine months – Taxes other than income taxes increased $4 million and $3 million in the third quarter and first nine months of 2007 compared with the same periods in the prior year primarily because of increased gross receipts taxes.
Illinois Regulated
Taxes other than income taxes in the Illinois Regulated segment decreased $6 million and $10 million for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
CIPS
Three and nine months – Taxes other than income taxes decreased $3 million and $6 million for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of lower property tax expenses. The nine-month period was also impacted by lower gross receipts taxes in 2007.
CILCO (Illinois Regulated) & IP
Three and nine months – Taxes other than income taxes were comparable between periods.
Non-rate-regulated Generation
Three and nine months - Taxes other than income taxes were comparable in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.
Other Income and Expenses
Ameren
Three and nine months – Miscellaneous income increased $8 million and $25 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of increased
interest income. Miscellaneous income in each period includes interest income on industrial development revenue bonds acquired by UE in conjunction with its purchase of CTs. These amounts are offset by an equivalent amount of interest expense associated with capital leases for the CTs recorded in interest charges on Ameren’s and UE’s statements of income. Miscellaneous expense increased $3 million and $6 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily as a result of contributions made to our charitable trust.
Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three and nine months – Miscellaneous income was comparable between the third quarter of 2007 and the third quarter of 2006. Miscellaneous income increased $6 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily as a result of increased interest income. As discussed above, miscellaneous income includes interest income related to industrial development revenue bonds that is offset in interest charges on UE’s statement of income. These interest amounts were $7 million for the third quarter in both 2007 and 2006 and $22 million and $16 million for the nine months ended September 30, 2007 and 2006, respectively. Miscellaneous expense was comparable for the three and nine months ended September 30, 2007, with the same periods in 2006.
Illinois Regulated
Miscellaneous income increased $3 million and $7 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. Miscellaneous expense was comparable for the three- and nine-month periods in 2007 compared with the same periods in 2006.
CILCO (Illinois Regulated) & IP
Three months – Miscellaneous income was comparable at CILCO (Illinois Regulated) in the third quarter of 2007 with the same period in the prior year. Miscellaneous income increased $2 million at IP in the three months ended September 30, 2007, compared with the same period in 2006 primarily because of increased interest income. Miscellaneous expense was comparable in the third quarter of 2007 with the same period in 2006.
Nine months - Miscellaneous income increased $2 million and $5 million at CILCO (Illinois Regulated) and IP in the nine months ended September 30, 2007, respectively, compared with the same period in 2006 primarily because of increased interest income. Miscellaneous expense was comparable at CILCO (Illinois Regulated) and IP between periods.
CIPS
Three and nine months - Other income and expenses were comparable between periods.
Non-rate-regulated Generation
Other income and expenses were comparable in the Non-rate-regulated Generation segment and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.
Interest
Ameren
Three and nine months - Interest expense increased $21 million and $62 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and other items noted below. Interest expense recognized on UE’s capital leases associated with the purchase of CTs is offset by an equivalent amount of interest income recorded in other income and expenses on Ameren’s and UE’s statement of income. With the adoption of FIN 48, we also began to record interest associated with uncertain tax positions as interest expense rather than income tax expense. These interest charges were $2 million and $9 million for the three and nine months ended September 30, 2007, respectively.
Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006, were as follows:
Missouri Regulated
UE
Three and nine months – Interest expense increased $7 million and $23 million for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The increase in the third quarter was due primarily to increased interest expense related to the issuance
of $425 million senior secured notes in June 2007. Interest expense increased in the nine-month period primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and because of increased interest expense related to the June 2007 debt issuance. As discussed above, interest charges include interest expense related to capital leases that is offset in other income and expenses on UE’s statement of income. Interest expense recorded in conjunction with the adoption of FIN 48 was $3 million for the nine months ended September 30, 2007.
Illinois Regulated
Interest expense increased $11 million and $27 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
CIPS
Three months – Interest expense was comparable between periods.
Nine months – Interest expense increased $5 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
CILCO (Illinois Regulated)
Three and nine months – Interest expense was comparable between periods.
IP
Three months – Interest expense increased $6 million for the third quarter of 2007, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates resulting from reduced credit ratings.
Nine months – Interest expense increased $18 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily because of the issuance of $75 million senior secured notes in June 2006 and because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
Non-rate-regulated Generation
Interest expense was comparable in the Non-rate-regulated Generation segment in the third quarter of 2007 with the same period in 2006. Interest expense increased $4 million in the nine months ended September 30, 2007, compared with the same period in 2006.
CILCORP (Parent Company Only) & CILCO (AERG)
Three months – Interest expense was comparable between periods.
Nine months - Interest expense increased $2 million and $4 million at CILCORP (Parent Company Only) and CILCO (AERG) for the nine months ended September 30, 2007, respectively, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
Genco & EEI
Three and nine months – Interest expense was comparable between periods.
Income Taxes
Ameren
Three and nine months - Ameren’s effective tax rate decreased 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 and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:
Missouri Regulated
UE
Three months – The effective tax rate decreased in 2007 from 2006 primarily because of an increase in reserves for uncertain tax positions in 2006 for tax returns filed in previous years, along with an increase in expenses deductible for tax purposes, which were not expensed for book purposes in 2007. These decreases were offset by lower favorable tax return-to-accrual adjustments in 2007 compared to the same period in 2006.
Nine months – The effective tax rate decreased in 2007 from 2006, primarily because of the items detailed above, along with the implementation of changes ordered by the MoPSC in UE’s 2007 electric rate order. The effective tax rate for the nine-month period in 2006 was increased by the effect of higher non-deductible expenses than the same period in 2007.
Illinois Regulated
The effective tax rate increased in the Illinois Regulated segment in the three months ended September 30, 2007, and decreased in the nine months ended September 30, 2007,
compared with the same periods in 2006, due to items detailed below.
CIPS
Three and nine months – The effective tax rate increased primarily because of unfavorable tax return-to-accrual adjustments in 2007 compared to favorable tax return-to-accrual adjustments in 2006.
CILCO (Illinois Regulated)
Three months – The effective tax rate increased primarily because of an increase in expenses deductible for tax purposes that were not expensed for book purposes on a pre-tax loss in 2007, along with a decrease in reserves for uncertain tax positions in 2006 for returns filed in previous years as compared to no change in reserves in 2007.
Nine months – The effective tax rate decreased primarily because of an increase in expenses deductible for tax, which were not expensed for book purposes, along with favorable tax return-to-accrual adjustments in 2007 compared with unfavorable tax return-to-accrual adjustments in 2006.
IP
Three months – The effective tax rate increased primarily because of favorable tax return-to-accrual adjustments on a pre-tax book loss in 2007 compared with unfavorable tax
return-to-accrual adjustments in 2006.
Nine months – The effective tax rate decreased primarily because of favorable tax return-to-accrual adjustments in 2007 compared with unfavorable tax return-to-accrual adjustments in 2006.
Non-rate-regulated Generation
The effective tax rate increased in the Non-rate-regulated Generation segment in the three and nine months ended September 30, 2007, compared with the same periods in 2006, due to items detailed below.
Genco
Three and nine months – The effective tax rate increased primarily because of lower reserves for uncertain tax positions in 2006 for tax returns filed in previous years as compared to 2007, a decrease in 2007 of expenses deductible for tax purposes but not expensed for book purposes when compared to 2006, and unfavorable tax return-to-accrual adjustments in 2007 compared with favorable tax return-to-accrual adjustments in 2006.
CILCO (AERG)
Three and nine months – The effective tax rate increased primarily because of lower reserves for uncertain tax positions in 2006 for tax returns filed in prior years, a decrease in expenses in 2007 that were deductible for tax purposes but not expensed for book purposes, and unfavorable tax return-to-accrual adjustments in 2007 compared to favorable tax return-to-accrual adjustments in 2006.
CILCORP (Parent Company Only)
Three and nine months – The effective tax rate decreased primarily because of lower favorable tax return-to-accrual adjustments in 2007 as compared to 2006.
EEI
Three and nine months – The 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 (Illinois Regulated) and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG principally rely on power sales to Marketing Company, which sold power through the Illinois power procurement auction in September 2006, and is selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, 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 September 30, 2007, for Ameren, UE, Genco, CILCORP, CILCO, and IP. The Ameren Companies will reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings and in the case of Ameren subsidiaries, equity infusions from
Ameren. The Ameren Companies will incur significant capital expenditures over the next five years for compliance with environmental regulations or to make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures are expected to be funded with debt. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of the Illinois electric settlement agreement that among other things, will change the process for power procurement in Illinois in the future and will impact future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during the third quarter of 2007, and will result in further monthly credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for a majority of these refunds and credits from Illinois power generators, including Genco and CILCO (AERG).
The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2007 and 2006:
| | | Net Cash Provided By Operating Activities | | | Net Cash Used In Investing Activities | | | Net Cash Provided By (Used In) Financing Activities | |
| | | 2007 | | | 2006 | | | Variance | | | 2007 | | | 2006 | | | Variance | | | 2007 | | | 2006 | | | Variance | |
Ameren(a) | | $ | 920 | | | $ | 1,069 | | | $ | (149 | ) | | $ | (1,093 | ) | | $ | (1,044 | ) | | $ | (49 | ) | | $ | 206 | | | $ | (87 | ) | | $ | 293 | |
| UE | | | 519 | | | | 620 | | | | (101 | ) | | | (535 | ) | | | (611 | ) | | | 76 | | | | 15 | | | | (27 | ) | | | 42 | |
| CIPS | | | 11 | | | | 127 | | | | (116 | ) | | | (115 | ) | | | (47 | ) | | | (68 | ) | | | 99 | | | | (80 | ) | | | 179 | |
| Genco | | | 153 | | | | 49 | | | | 104 | | | | (137 | ) | | | (83 | ) | | | (54 | ) | | | (15 | ) | | | 36 | | | | (51 | ) |
| CILCORP | | | 20 | | | | 104 | | | | (84 | ) | | | (141 | ) | | | (33 | ) | | | (108 | ) | | | 201 | | | | (71 | ) | | | 272 | |
| CILCO | | | 48 | | | | 127 | | | | (79 | ) | | | (141 | ) | | | (75 | ) | | | (66 | ) | | | 162 | | | | (52 | ) | | | 214 | |
| IP | | | 23 | | | | 108 | | | | (85 | ) | | | (133 | ) | | | (129 | ) | | | (4 | ) | | | 110 | | | | 21 | | | | 89 | |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
Ameren’s cash from operating activities decreased in the first nine months of 2007, as compared with the first nine months of 2006. The Illinois electric settlement agreement resulted in $45 million of customer refunds and program funding. Under the terms of the settlement agreement, the Ameren Illinois Utilities will receive reimbursements from Illinois electricity generators in future months for a majority of these expenditures. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from Illinois electric customers lagged payments for power purchases. A decrease in income taxes paid (net of refunds) of $59 million benefited cash flows from operations in the first nine months of 2007. Increases in electric and gas margins also benefited operating cash flows, but were reduced by higher operations and maintenance expenses as discussed in Results of Operations, primarily as a result of the Callaway nuclear plant refueling and maintenance outage and storm-related outage repairs.
At UE, cash from operating activities decreased in the first nine months of 2007, compared with the first nine months of 2006. Increased storm repair costs and increased other operations and maintenance expenses as a result of the Callaway nuclear plant refueling and maintenance outage were only partially offset by increased electric and gas margins, as discussed in Results of Operations. In addition, there was an increase in accounts receivable, primarily because of higher prices for interchange power sales and warmer summer weather. Compared to the prior-year period, decreases in cash paid for Taum Sauk-related costs (net of insurance recoveries) of $24 million, and a decrease in income tax payments (net of refunds) of $97 million benefited cash flows from operations.
At CIPS, cash from operating activities decreased in the first nine months of 2007, compared with the first nine months of 2006. Operating cash flows were lower, primarily because of $15 million of customer refunds and program funding related to the Illinois electric settlement agreement, and increased other operations and maintenance expenses. Under the terms of the settlement agreement, CIPS will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. Income tax payments (net of refunds) decreased $26 million, benefiting cash flows from operations.
Genco’s cash from operating activities increased in the first nine months of 2007 compared to the 2006 period, primarily because of an increase in electric margins, as discussed in Results of Operations, and a reduction in cash spent for fuel inventory due to large cash outlays made in 2006 to replenish coal inventory after disruptions in rail deliveries caused by train derailments. Reducing these increases in cash from operating activities was an increase in income tax payments (net of refunds) of $23 million.
Cash from operating activities decreased for CILCORP and CILCO in the nine months ended September 30, 2007,
compared with the same period of 2006. The positive cash effect of increased electric margins discussed in Results of Operations was more than offset by $9 million of customer refunds and program funding related to the Illinois electric settlement agreement. Under the terms of the settlement agreement, CILCO will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. In addition, Income tax payments (net of refunds) increased $21 million and $18 million for CILCORP and CILCO, respectively.
IP’s cash from operating activities decreased in the nine months ended September 30, 2007, compared with the same period in 2006. The Illinois electric settlement agreement resulted in $21 million of customer refunds and program funding. Under the terms of the settlement agreement, IP will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. Storm repair costs increased $11 million compared to the prior year, and income tax payments (net of refunds) increased by $32 million, further reducing cash flows from operations.
Cash Flows from Investing Activities
Ameren had an increase in cash used in investing activities in the first nine months of 2007 compared to the first nine months of 2006. Net cash used for capital expenditures increased in 2007 as a result of increased storm repair costs, power plant scrubber projects and upgrades at various power plants. These expenditures were offset by the lack of CT acquisitions in 2007 as occurred in 2006. The absence in 2007 of $11 million of proceeds from sales of non-core properties received in 2006 also contributed to the increase in cash used in investing activities. A decrease in purchases of emission allowances was partially offset by fewer sales of emission allowances resulting in a $19 million net benefit to investing cash flows.
UE’s cash used in investing activities decreased in the first nine months of 2007, compared to the same period in 2006, principally because of the $292 million expended for CT purchases in 2006, partially offset by a $152 million increase in capital expenditures in the first nine months of 2007 as compared with the first nine months of 2006. The increased capital expenditures in 2007 were related to storm repair costs, a power plant scrubber project, and other power plant upgrades. In the 2006 period, UE received proceeds of $67 million from an intercompany note related to the transfer of UE’s Illinois territory to CIPS, which had reduced cash used in investing activities in the same period in 2006.
CIPS had an increase in its net use of cash from investing activities during 2007 as compared to the same period in 2006. The net $68 million increase was primarily due to an increase in money pool advances. In the 2007 period, CIPS made net advances of $94 million compared to $18 million in the 2006 period. Reducing this increase in net use of cash from investing activities, capital expenditures decreased by $5 million compared to the prior year.
Genco’s cash used in investing activities increased in the first nine months of 2007 compared with the 2006 period. Capital expenditures increased $73 million, principally due to a scrubber project at one of its power plants and various plant upgrades, while emission allowance purchases decreased by $19 million.
CILCORP’s and CILCO’s cash used in investing activities increased in the nine months ended September 30, 2007, compared with the same period in 2006. Cash flow used in investing activities increased as a result of a $108 million increase in capital expenditures, primarily due to a power plant scrubber project and plant upgrades at AERG. The absence in 2007 of $11 million of proceeds received in 2006 from the sale of leveraged leases, and (for CILCORP only) the absence in 2007 of a 2006 note receivable payment from Resources Company in the amount of $42 million related to the 2005 transfer of leveraged leases from CILCORP to Resources Company also resulted in an increase in cash used in investing activities. The receipt of a $42 million repayment of prior-year money pool advances and a $12 million reduction of emission allowance purchases reduced cash flows used in investing activities in the 2007 period compared to 2006.
IP’s cash used in investing activities increased in the first nine months of 2007 compared to the same period in 2006 as a result of increased capital expenditures.
See Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.
We continually review our power supply needs. As a result, we could modify plans for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity
may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.
Cash Flows from Financing Activities
Cash provided by financing activities increased for Ameren in the first nine months of 2007 from the year-ago period. Cash from financing activities increased as a result of a
$425 million debt issuance in June 2007 by UE, which was larger than the prior year’s issuances that totaled $232 million. The proceeds of the $425 million offering were used to reduce short-tem debt at UE. Overall, short-term debt increased $432 million year-over-year at Ameren. The increased short-term debt was used to pay maturing long-term notes and to fund working capital requirements at Ameren’s subsidiaries. Cash was reduced by a $7 million decrease in common stock issuances and a $327 million increase in long-term debt redemptions, repurchases and maturities, including the maturity of $350 million in notes at Ameren Corporation in the first nine months of 2007.
UE had a net source of cash from financing activities in the first nine months of 2007, compared to a net use of cash in the same period of the prior year. Contributing to the increase was the issuance of $425 million in long-term debt in June 2007. The proceeds were used to reduce short-term debt. Overall, short-term debt decreased $142 million in 2007 compared to an increase of $128 million in 2006. Short-term borrowings were used in 2007 to fund working capital requirements and increased capital expenditures, and in 2006 principally to fund the acquisition of CTs. A $92 million increase in dividend payments and $20 million of net repayments on an intercompany borrowing arrangement with Ameren reduced cash provided by financing activities in the first nine months of 2007 compared to the same period in 2006.
CIPS had a net source of cash from financing activities for the nine months ended September 30, 2007, compared to a net use of cash for the first nine months of 2006. Cash from financing activities increased as a result of a $100 million net increase in short-tem debt, a $50 million decrease in dividends paid, a $20 million reduction in long-term debt maturities, and the absence in 2007 of a 2006 intercompany note payment to UE in the amount of $67 million. Reducing these positive effects was the absence in 2007 of $61 million in proceeds from long-term debt issuances in 2006.
Genco had a net use of cash from financing activities for the nine months ended September 30, 2007, compared to a net source of cash for the first nine months of 2006. The increase in cash used in financing activities in 2007 was a result of a $20 million increase in dividend payments and a $75 million capital contribution received in 2007 compared to $150 million received in 2006. Reducing the net cash used in financing activities was a net increase in short-term debt of $75 million in the first nine months of 2007 compared to the same period in 2006.
CILCORP and CILCO had a net source of cash from financing activities for the nine months ended September 30, 2007, compared to a net use of cash for the first nine months of 2006. Short-term debt increased year-over-year by $325 million for CILCORP and $200 million for CILCO. Dividends were not paid by either company in 2007, compared to $50 million and $65 million paid in 2006 by CILCORP and CILCO, respectively. Also benefiting cash in 2007 compared to 2006 was the absence of money pool repayments in 2007, compared to 2006 repayments of $92 million at CILCORP and $99 million at CILCO. In addition, there was a $14 million capital contribution received by CILCO in 2007 from CILCORP. Cash flows from financing activities were reduced by a $43 million increase in CILCORP note repayments, a $96 million reduction in long-term debt proceeds at both CILCORP and CILCO, and increased redemptions, repurchases, and maturities of long-term debt of $18 million and $30 million at CILCORP and CILCO, respectively.
IP had a net increase in cash from financing activities in the first nine months of 2007, compared to the same period of the prior year. Cash benefited by $125 million of short-term debt borrowings in 2007 compared to none in 2006, a $17 million net increase in money pool borrowings, and by the lack of $17 million in TFN overfunding. These benefits to cash were reduced by the lack of long-term debt proceeds in 2007, compared to $75 million in 2006.
Short-term Borrowings and Liquidity
Short-term borrowings typically consist of drawings under committed bank credit facilities and commercial paper issuances. For additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements, see Note 3 – Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.
The following table presents the various committed bank credit facilities of the Ameren Companies and AERG and their availability as of September 30, 2007:
Credit Facility | Expiration | Amount Committed | | | Amount Available | |
Ameren, UE and Genco: | | | | | | |
Multiyear revolving(a) | July 2010 | $ | 1,150 | | | $ | 728 | |
CIPS, CILCORP, CILCO, IP and AERG: | | | | | | | | |
2007 Multiyear revolving(b) | January 2010 | | 500 | | | | - | |
2006 Multiyear revolving(c) | January 2010 | | 500 | | | | 125 | |
| (a) | Ameren Companies may access this credit facility through intercompany borrowing arrangements. The maximum amount directly available to Ameren, UE and Genco under the facility is $1.15 billion, $500 million and $150 million, respectively. |
| (b) | The maximum amount available to each borrower at September 30, 2007, including for the issuance of letters of credit, was limited as follows: CILCORP - $125 million, IP - $200 million and AERG - $100 million. CIPS and CILCO have the option of permanently reducing their ability to borrow under the 2006 $500 million credit facility and shifting such capacity, up to the same limits, to the 2007 $500 million credit facility. In July 2007, CILCO shifted $75 million of its sublimit under the 2006 $500 million credit facility to this facility. |
| (c) | The maximum amount available to each borrower at September 30, 2007, including for issuance of letters of credit, was limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. In July 2007, CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of October 31, 2007, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility. |
In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2006, FERC issued an order authorizing these subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion; CIPS - $250 million; and CILCO - $250 million. The authorization was effective as of April 1, 2006, and terminates on March 31, 2008. IP has unlimited short-term debt authorization from FERC.
Genco is authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt authorization from FERC.
With the repeal of PUHCA 1935, the issuance of short-term unsecured debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer subject to approval by any regulatory body.
The Ameren Companies continually evaluate the adequacy and appropriateness of their credit arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.
Long-term Debt and Equity
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts and including any redemption premiums) and preferred stock for the nine months ended September 30, 2007 and 2006, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.
| | | | Nine Months | |
| | Month Issued, Redeemed, Repurchased or Matured | | 2007 | | | 2006 | |
Issuances | | | | | | | |
Long-term debt | | | | | | | |
UE: | | | | | | | |
6.40% Senior secured notes due 2017 | June | | $ | 425 | | | $ | - | |
CIPS: | | | | | | | | | |
6.70% Senior secured notes due 2036 | June | | | - | | | | 61 | |
CILCO: | | | | | | | | | |
6.20% Senior secured notes due 2016 | June | | | - | | | | 54 | |
6.70% Senior secured notes due 2036 | June | | | - | | | | 42 | |
IP: | | | | | | | | | |
6.25% Senior secured notes due 2016 | June | | | - | | | | 75 | |
| Total Ameren long-term debt issuances | | | $ | 425 | | | $ | 232 | |
| | | | | |
| | | | Nine Months | |
| | Month Issued, Redeemed, Repurchased or Matured | | 2007 | | | 2006 | |
Common stock | | | | | | | | | |
Ameren: | | | | | | | | | |
DRPlus and 401(k) | Various | | $ | 71 | | | $ | 78 | |
| Total common stock issuances | | | $ | 71 | | | $ | 78 | |
| Total Ameren long-term debt and common stock issuances | | | $ | 496 | | | $ | 310 | |
Redemptions, Repurchases and Maturities | | | | | | | | | |
Long-term debt | | | | | | | | | |
Ameren: | | | | | | | | | |
2002 5.70% notes due 2007 | February | | $ | 100 | | | $ | - | |
Senior notes due 2007 | May | | | 250 | | | | - | |
CIPS: | | | | | | | | | |
7.05% First mortgage bonds due 2006 | June | | | - | | | | 20 | |
CILCORP: | | | | | | | | | |
9.375% Senior notes due 2029 | March/April | | | - | | | | 12 | |
CILCO: | | | | | | | | | |
7.73% First Mortgage bonds due 2025 | July | | | - | | | | 20 | |
7.50% First mortgage bonds due 2007 | January | | | 50 | | | | - | |
IP: | | | | | | | | | |
Note payable to IP SPT: | | | | | | | | | |
5.65% Series due 2008 | Various | | | 65 | | | | - | |
5.54% Series due 2007 | Various | | | - | | | | 86 | |
Preferred Stock | | | | | | | | | |
CILCO: | | | | | | | | | |
5.85% Series | July | | | 1 | | | | 1 | |
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities | | | $ | 466 | | | $ | 139 | |
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of September 30, 2007:
| | Effective Date | | Authorized Amount | | | Issued | | | Available | |
| Ameren | June 2004 | | $ | 2,000 | | | $ | 459 | | | $ | 1,541 | |
| UE | October 2005 | | | 1,000 | | | | 685 | | | | 315 | |
| CIPS | May 2001 | | | 250 | | | | 211 | | | | 39 | |
In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus.
Ameren is also currently selling newly issued shares of its common stock under certain of its 401(k) plans pursuant to effective SEC Form S-8 registration statements. Under DRPlus and its 401(k) plans, Ameren issued a total of 1.4 million new shares of common stock valued at $71 million in the nine months ended September 30, 2007.
Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will 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 September 30, 2007, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets or make our access to the capital markets uncertain or limited. Such events would increase our cost of
capital and adversely affect our ability to access the capital markets.
Dividends
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues, including Ameren’s historical earnings and cash flow, projected earnings, projected cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics, impacts of regulatory orders or legislation and overall business considerations.
See Note 3 – Credit Facilities and Liquidity and Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At September 30, 2007, except as discussed below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.
The 2007 $500 million credit facility and 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to common and preferred stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured credit rating to below investment-grade, causing it to be subject to this dividend payment limitation. As of September 30, 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 thereunder are not currently limited in their dividend payments by this provision of the 2007 or 2006 $500 million credit facilities.
The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the nine months ended September 30, 2007 and 2006.
| | | Nine Months | |
| | | 2007 | | | 2006 | |
| UE | | $ | 246 | | | $ | 154 | |
| CIPS | | | - | | | | 50 | |
| Genco | | | 113 | | | | 93 | |
CILCORP(a) | | | - | | | | 50 | |
| Nonregistrants | | | 36 | | | | 44 | |
| Dividends paid by Ameren | | $ | 395 | | | $ | 391 | |
| (a) | CILCO paid to CILCORP dividends of $50 million for the nine months ended September 30, 2006. |
Contractual Obligations
For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K, and Other Obligations in Note 8 – Commitments and Contingencies under Part I, Item 1, of this report. See Note 11 – Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan. See also Note 1 – Summary of Significant Accounting Policies to our financial statements under Part I, Item 1, of this report for the unrecognized tax benefits under the provisions of FIN 48.
Subsequent to December 31, 2006, obligations related to the procurement of coal and related transportation, natural gas and nuclear fuel materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $5,560 million, $1,759 million, $400 million, $356 million, $1,346 million, $1,346 million and $1,527 million, respectively, as of September 30, 2007. The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The amount of unrecognized tax benefits under the provisions of FIN 48 are $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. UE also entered into a commitment to purchase heavy forgings during 2007. As of September 30, 2007, UE’s commitment to purchase heavy forgings totaled $88 million. Total obligations at September 30, 2007, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,415 million, $2,301 million, $445 million, $392 million, $1,409 million, $1,409 million and $1,680 million, respectively.
As a result of the Illinois electric settlement agreement reached in July 2007 and the enactment of related legislation into law, which occurred on August 28, 2007, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million
from Genco and $28 million from AERG. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco and CILCO (AERG) incurred charges to earnings of $59 million, $8 million, $5 million,
$11 million, $24 million and $11 million, respectively, under the terms of the settlement agreement during the quarter ended September 30, 2007. At September 30, 2007, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $108 million, $37 million, $21 million and $50 million, respectively. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the Illinois electric settlement agreement.
Credit Ratings
The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:
| | Moody’s | S&P | Fitch |
Ameren: | | | |
| Issuer/corporate credit rating | Baa2 | BBB- | BBB+ |
| Unsecured debt | Baa2 | BB+ | BBB+ |
| Commercial paper | P-2 | A-3 | F2 |
UE: | | | |
| Issuer/corporate credit rating | Baa1 | BBB- | A- |
| Secured debt | A3 | BBB | A+ |
| Commercial paper | P-2 | A-3 | F2 |
CIPS: | | | |
| Issuer/corporate credit rating | Ba1 | BB | BB+ |
| Secured debt | Baa3 | BBB | BBB |
Genco: | | | |
| Issuer/corporate credit rating | - | BBB- | BBB+ |
| Unsecured debt | Baa2 | BBB- | BBB+ |
CILCORP: | | | |
| Issuer/corporate credit rating | - | BB | BB+ |
| Unsecured debt | Ba2 | B+ | BB+ |
CILCO: | | | |
| Issuer/corporate credit rating | Ba1 | BB | BB+ |
| Secured debt | Baa2 | BBB | BBB |
IP: | | | |
| Issuer/corporate credit rating | Ba1 | BB | BB+ |
| Secured debt | Baa3 | BBB- | BBB |
During March and April of 2007, Moody’s, S&P, and Fitch downgraded various credit ratings of certain of the Ameren Companies. Depending on the specific credit rating agency action and the specific legal entities affected, the downgrade of these credit ratings was a result of the actions of various Illinois state legislators, including passage of forms of legislation that would have rolled back and frozen the electric rates of CIPS, CILCO and IP, and in the case of UE was prompted by higher costs, lower financial metrics and a continued challenging regulatory environment in Missouri.
On August 1, 2007, Fitch changed the rating outlook at Ameren to stable. In addition, Fitch revised the rating watch on CIPS, CILCORP, CILCO and IP to positive. The positive watch followed the announcement of the Illinois electric settlement agreement. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for further discussion of the Illinois settlement agreement.
On August 29, 2007, Moody’s changed the rating outlook at Ameren and Genco to stable. The rating outlook of CIPS, CILCORP, CILCO, and IP was upgraded to positive. These actions were prompted by the Illinois electric settlement agreement. Moody’s stated that “the settlement significantly reduces the likelihood of a rate freeze being enacted in Illinois and provides the foundation for a potentially improving political and regulatory environment for investor-owned-utilities in the state.”
On August 29, 2007, S&P issued a research update in response to the Illinois settlement agreement, as discussed above. The outlook on the ratings of Ameren, UE and Genco was changed to stable. The outlook on the ratings of CIPS, CILCORP, CILCO, and IP was upgraded to positive. On September 6, 2007, S&P upgraded its senior secured debt ratings of UE, CIPS, and CILCO from “BBB-” to “BBB” as a result of changes in its first mortgage bond rating methodology.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made as of the end of the third quarter of 2007 were $76 million, $4 million, $8 million, $27 million, $27 million, and $33 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively, resulting from our reduced corporate and issuer credit ratings. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 2007, could have resulted in Ameren, UE, CIPS, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $160 million, $43 million, $16 million, $20 million, $22 million, $22 million, and $39 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
OUTLOOK
Below are some key events and trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2007 and beyond.
Revenues
| · | The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. With rising costs, including fuel and related transportation, purchased power, labor and material costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until requests to increase rates to recover such costs are granted by state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering into a period where more frequent rate cases will be necessary. The Ameren Illinois Utilities filed delivery service rate cases with the ICC in November 2007 due to inadequate recovery of costs and low returns on equity being experienced in 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates. In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until October 2008 to render a decision in these rate cases. UE is actively considering the timing of its next electric rate case filing in Missouri. |
| · | In current and future rate cases, UE, CIPS, CILCO and IP will also seek cost recovery mechanisms from their state regulators to reduce regulatory lag. In their electric and natural gas delivery service rate cases filed in November 2007, the Ameren Illinois Utilities requested ICC approval to implement rate adjustment mechanisms for bad debt expenses, electric infrastructure investments and the decoupling of natural gas revenues from sales volumes. In July 2005, a law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006. Detailed rules for the environmental cost recovery mechanism are being developed and expected to be effective in the first half of 2008. |
| · | Average residential electric rates for CIPS, CILCO and IP increased significantly following the expiration of a rate freeze at the end of 2006. Electric rates rose because of the increased cost of power purchased on behalf of the Ameren Illinois Utilities’ customers and an increase in electric delivery service rates. Due to the magnitude of these increases, a comprehensive settlement agreement was reached with key stakeholders in Illinois that provides approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Pursuant to the settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. To fund these contributions, the Ameren Illinois Utilities, Genco and AERG will need to increase their respective borrowings. |
| · | As part of the Illinois electric settlement agreement and related legislation, the reverse auction used for power procurement in Illinois was discontinued and replaced with a new power procurement process led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary baseload, intermediate and peaking power requirements through a request-for-proposal process, subject to ICC review and approval. Existing supply contracts from the September 2006 reverse auction will remain in place. The impact of the new procurement process in Illinois is uncertain. |
| · | The MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service with new electric rates effective June 4, 2007. This order included provisions to extend UE's Callaway nuclear plant and fossil generation plant lives and to change the income tax method associated with cost of property removal. Such provisions are expected to decrease Ameren's and UE's expenses by $58 million annually. The MoPSC also approved a stipulation and agreement authorizing an increase in UE’s annual natural gas delivery revenues of $6 million, effective April 1, 2007. UE agreed not to file a natural gas delivery rate case before March 15, 2010. |
| · | 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 and Missouri rate matters. |
| · | Very volatile power prices in the Midwest affect the amount of revenues Ameren, UE, Genco, CILCO (through AERG) and EEI can generate by marketing power into the wholesale and spot markets and influence the cost of power purchased in the spot markets. |
| · | The availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. 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. |
| · | All but 5 million megawatthours of Genco and AERG’s pre-2006 wholesale and retail electric power supply agreements expired during 2006. In 2007, 1 million megawatthours of these agreements will expire and another 2 million contracted megawatthours will expire in 2008. These agreements had an average embedded selling price of $36 per megawatthour. These agreements are being replaced with market-based sales. The Non-rate-regulated Generation segment expects to generate 31 million megawatthours of power in 2007 (Genco – 17 million, AERG – 6 million, EEI – 8 million). |
| · | The marketing strategy for Non-rate-regulated Generation is to optimize generation output in a low risk manner to minimize earnings and cash flow volatility, while capitalizing on its low-cost generation fleet to provide for solid, sustainable returns. Through a mix of physical and financial sales contracts, including contracts resulting from the Illinois 2006 power procurement auction and the Illinois electric settlement agreement, the Non-rate-regulated Generation segment has sold approximately 90% of its expected 2007 generation output at an average price of $51 per megawatthour (fiscal year 2008 - 75%, or 24 million megawatthours; fiscal year 2009 - 55%, or 18 million megawatthours). Expected sales in 2007 include an estimated 7.6 million megawatthours of power sold through the 2006 Illinois power procurement auction at about $65 per megawatthour (2008 - 6.8 million, 2009 - 4.3 million). |
| · | The future development of ancillary services and capacity markets in MISO could increase the electric margins of UE, Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider's transmission system. A capacity market allows participants to purchase or sell capacity products that meet reliability requirements. MISO is currently in the process of developing a centralized regional wholesale ancillary services market, which is expected to begin during 2008. In September 2007, MISO filed a new proposed ancillary services market tariff with the FERC subject to normal FERC procedural review. We expect MISO will begin development of a capacity market once its ancillary services market is in place. |
| · | We expect continued economic growth in our service territory to benefit energy demand in 2007 and beyond, but higher energy prices could result in reduced demand from customers, especially in Illinois. Future energy efficiency programs developed by UE, CIPS, CILCO and IP could also result in reduced demand for our electric generation and our electric and gas transmission and distribution services. |
Fuel and Purchased Power
| · | In 2006, 85% of Ameren’s electric generation (UE - 77%, Genco - 97%, CILCO - 99%, EEI – 100%) was supplied by its coal-fired power plants. About 93% of the coal used by these plants (UE - 97%, Genco - 87%, CILCO - 69%, EEI - 100%) was delivered by railroads from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather and derailments. As of September 30, 2007, coal inventories for UE, Genco, AERG and EEI were adequate, and consistent with historical levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources. |
| · | Ameren’s coal and related transportation costs are expected to increase 15% to 20% in 2007 over 2006 and 5% to 10% in 2008. Further increases are expected beyond 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. |
| · | Ameren’s coal and related transportation costs are expected to increase 15% to 20% in 2007 over 2006 and 5% to 10% in 2008. Further increases are expected beyond 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 2007, Ameren and IP will 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 2007, Ameren expects to reduce levels of emission allowance sales in order to retain remaining allowances for future environmental compliance needs. |
Other Costs
| · | In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk plant, assuming successful resolution of outstanding issues with authorities of the state of Missouri. UE received approval from FERC to rebuild the upper reservoir in August 2007 and hired a contractor in November 2007. Should the Taum Sauk plant be rebuilt, UE would expect it to be out of service through at least the fall of 2009, if not longer. UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities (but not penalties or lost electric margins) |
| | caused by the breach, including rebuilding the plant, will be covered by insurance. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties and by authorities in the state of Missouri. UE is currently in discussions with state authorities to resolve outstanding issues associated with this incident. The Taum Sauk incident is also under investigation at the MoPSC. We are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized. See Note 2 – Rate and Regulatory Matters and Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of Taum Sauk matters. |
| · | UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the fall of 2008 and is expected to last 30 days. 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 and gas rates. |
| · | Genco expects its annual depreciation expense will decrease by $12 million annually based on a depreciation study completed in September 2007. |
| · | 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. Costs for these types of projects continue to escalate. These investments will also result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 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. |
| · | Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. The costs to comply with future legislation or regulations could be so expensive that Ameren and other similarly-situated electric power generators may be forced to close some coal-fired facilities. 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 issue this report in mid-December 2007. Investments to control carbon emissions at Ameren’s coal-fired plants would significantly increase future capital expenditures and operations and maintenance expenses. |
| · | UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until at least 2018. However, due to the significant time required to plan, acquire permits for and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In 2007, UE signed an agreement with UniStar Nuclear to assist UE in the preparation of a combined construction and operating license application (COLA) for filing with the NRC. A COLA describes how a nuclear plant would be designed, constructed and operated. In addition, UE has also signed contracts for certain long lead-time equipment. Preparing a COLA and entering into these contracts does not mean a decision has been made to build a nuclear plant. They are only the first steps in the regulatory licensing and procurement process. UE and UniStar Nuclear must submit the COLA to the NRC in 2008 to be eligible for incentives available under provisions of the 2005 Energy Policy Act. |
| · | Over the next few years, we expect to make significant investments in our electric and gas infrastructure and incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher labor and material costs for these capital expenditures. UE announced in July 2007 plans to spend $300 million over three years for underground cabling and reliability improvement, $135 million ($45 million per year) for tree-trimming, and $84 million over three years (approximately $28 million per year) for circuit and device inspection and repair. We would expect these costs or investments to be recovered in rates. |
| · | Increased investments for environmental compliance, reliability improvement and new baseload capacity will result in higher financing costs. |
Affiliate Transactions
| · | As a result of the termination of the JDA on December 31, 2006, UE and Genco no longer have the obligation to provide power to each other. UE is able to sell any excess power it has at market prices, which we believe will most likely be higher than the prices paid to it by Genco. Genco will no longer receive the margins on sales that it made, which were fulfilled with power from UE. The electric rate order issued in May 2007 by the MoPSC incorporated the net decrease in UE’s revenue requirement from increased margins expected to result from the termination of the JDA. See Note 7 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a discussion of the effects of terminating the JDA. |
Other
| · | 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. |
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 and pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers.
Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risks.
Interest Rate Risk
We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at September 30, 2007:
| | | Interest Expense | | | Net Income(a) | |
| Ameren | | $ | 20 | | | $ | (13 | ) |
| UE | | | 6 | | | | (4 | ) |
| CIPS | | | 2 | | | | (1 | ) |
| Genco | | | 1 | | | | (1 | ) |
| CILCORP | | | 5 | | | | (3 | ) |
| CILCO | | | 4 | | | | (2 | ) |
| IP | | | 6 | | | | (4 | ) |
| (a) | Calculations are based on an effective tax rate of 38%. |
The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.
Our physical and financial instruments are subject to credit risk consisting of trade accounts receivable and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At September 30, 2007, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with power purchase and sale activity with nonaffiliated companies. These companies also have credit exposure to affiliates. At September 30, 2007, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading purchases and sales was each less than $1 million, net of collateral (2006 – less than $1 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $32 million at September 30, 2007 (2006 - $35 million).
The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois settlement agreement, which will provide $488 million in rate relief over a four-year period to certain electric customers of the Ameren Illinois Utilities. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities will bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.
Equity Price Risk
Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect would be reflected in net income and OCI, and in the amount of cash required to be contributed to the plans.
Commodity Price Risk
We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through structured risk management programs and policies, which include structured forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.
The following table shows how our earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 2007 through 2010:
| | | Net Income(a) | |
| Ameren | | $ | (23 | ) |
| UE | | | (9 | ) |
| Genco | | | (7 | ) |
| CILCO (AERG) | | | (2 | ) |
| EEI | | | (6 | ) |
| (a) | Calculations are based on an effective tax rate of 38% |
Ameren also utilizes its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any negative material financial impact.
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.
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 | % | | | 98 | % | | | 51 | % |
| Coal transportation | | | 100 | | | | 96 | | | | 44 | |
| Nuclear fuel | | | 100 | | | | 100 | | | | 73 | |
| Natural gas for generation | | | 100 | | | | 19 | | | | - | |
| Natural gas for distribution | | (a) | | | | 26 | | | | 12 | |
Purchased power for Illinois Regulated(b) | | | 100 | | | | 91 | | | | 60 | |
UE: | | | | | | | | | | | | |
| Coal | | | 100 | % | | | 99 | % | | | 54 | % |
| Coal transportation | | | 100 | | | | 97 | | | | 62 | |
| Nuclear fuel | | | 100 | | | | 100 | | | | 73 | |
| Natural gas for generation | | | 100 | | | | 14 | | | | - | |
| Natural gas for distribution | | (a) | | | | 58 | | | | 9 | |
CIPS: | | | | | | | | | | | | |
| Natural gas for distribution | | (a) | | | | 23 | % | | | 14 | % |
Purchased power(b) | | | 100 | % | | | 91 | | | | 60 | |
Genco: | | | | | | | | | | | | |
| Coal | | | 100 | % | | | 100 | % | | | 47 | % |
| Coal transportation | | | 100 | | | | 98 | | | | 32 | |
| Natural gas for generation | | | 100 | | | | 17 | | | | - | |
CILCORP/CILCO: | | | | | | | | | | | | |
| Coal (AERG) | | | 100 | % | | | 83 | % | | | 41 | % |
| Coal transportation (AERG) | | | 100 | | | | 79 | | | | 24 | |
| Natural gas for distribution | | (a) | | | | 20 | | | | 10 | |
Purchased power(b) | | | 100 | | | | 91 | | | | 60 | |
IP: | | | | | | | | | | | | |
| Natural gas for distribution | | (a) | | | | 23 | % | | | 13 | % |
Purchased power(b) | | | 100 | % | | | 91 | | | | 60 | |
EEI: | | | | | | | | | | | | |
| Coal | | | 100 | % | | | 100 | % | | | 55 | % |
| Coal transportation | | | 100 | | | | 100 | | | | - | |
| (a) | The year 2007 is non-applicable for this table. The year 2008 represents November 2007 through March 2008. This continues each successive year through March 2011. |
| (b) | Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than 1 megawatt of demand and includes the financial contracts that the Ameren Illinois Utilities entered into with Marketing Company, effective August 28, 2007, as part of the Illinois electric settlement agreement. Larger customers are purchasing power from the competitive markets. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for a discussion of these financial contracts and the new power procurement process pursuant to the Illinois electric settlement agreement. |
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) | | $ | 11 | | | $ | (7 | ) | | $ | 15 | | | $ | (10 | ) |
| UE | | | 4 | | | | (3 | ) | | | 6 | | | | (4 | ) |
| Genco | | | 4 | | | | (2 | ) | | | 3 | | | | (2 | ) |
| CILCORP | | | 2 | | | | (1 | ) | | | 2 | | | | (1 | ) |
| CILCO (AERG) | | | 2 | | | | (1 | ) | | | 2 | | | | (1 | ) |
| EEI | | | 1 | | | | (1 | ) | | | 4 | | | | (3 | ) |
| (a) | Calculations are based on an effective tax rate of 38%. |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
In the event of a significant change in coal and coal transportation prices, UE, Genco, AERG and EEI would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.
See Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.
Fair Value of Contracts
Most of our commodity contracts qualify for treatment as normal purchases and sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission allowances. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three and nine months ended September 30, 2007. The sources used to determine the fair value of these contracts were active quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than five years.
| | | Ameren(a) | | | UE | | | CIPS | | | Genco(b) | | | CILCORP/ CILCO | | | IP | |
Three Months | | | | | | | | | | | | | | | | | | |
| Fair value of contracts at beginning of period, net | | $ | 52 | | | $ | 5 | | | $ | - | | | $ | (2 | ) | | $ | 3 | | | $ | (15 | ) |
| Contracts realized or otherwise settled during the period | | | (25 | ) | | | (1 | ) | | | 2 | | | | - | | | | 4 | | | | 18 | |
| Changes in fair values attributable to changes in valuation technique and assumptions | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Fair value of new contracts entered into during the period | | | 7 | | | | 11 | | | | - | | | | (1 | ) | | | (1 | ) | | | - | |
| Other changes in fair value | | | 4 | | | | (6 | ) | | | (6 | ) | | | 1 | | | | (6 | ) | | | (19 | ) |
| Fair value of contracts outstanding at end of period, net | | $ | 38 | | | $ | 9 | | | $ | (4 | ) | | $ | (2 | ) | | $ | - | | | $ | (16 | ) |
Nine Months | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of contracts at beginning of period, net | | $ | 41 | | | $ | 9 | | | $ | (7 | ) | | $ | (1 | ) | | $ | (3 | ) | | $ | (34 | ) |
| Contracts realized or otherwise settled during the period | | | (16 | ) | | | (4 | ) | | | 5 | | | | - | | | | 7 | | | | 36 | |
| Changes in fair values attributable to changes in valuation technique and assumptions | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Fair value of new contracts entered into during the period | | | 15 | | | | 6 | | | | - | | | | (1 | ) | | | (4 | ) | | | (7 | ) |
| Other changes in fair value | | | (2 | ) | | | (2 | ) | | | (2 | ) | | | - | | | | - | | | | (11 | ) |
| Fair value of contracts outstanding at end of period, net | | $ | 38 | | | $ | 9 | | | $ | (4 | ) | | $ | (2 | ) | | $ | - | | | $ | (16 | ) |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | In conjunction with the new power supply agreement between Marketing Company and Genco that went into effect January 1, 2007, the mark-to-market value of hedges entered into during 2006 for Genco was transferred from Genco to Marketing Company. |
The following table presents maturities of derivative contracts as of September 30, 2007:
Sources of Fair Value | | Maturity Less than 1 Year | | | Maturity 1-3 Years | | | Maturity 4-5 Years | | | Maturity in Excess of 5 Years | | | Total Fair Value | |
Ameren: | | | | | | | | | | | | | | | |
| Prices actively quoted | | $ | 8 | | | $ | (1 | ) | | $ | - | | | $ | - | | | $ | 7 | |
Prices provided by other external sources(a) | | | (23 | ) | | | (1 | ) | | | - | | | | - | | | | (24 | ) |
Prices based on models and other valuation methods(b) | | | 39 | | | | 16 | | | | - | | | | - | | | | 55 | |
| Total | | $ | 24 | | | $ | 14 | | | $ | - | | | $ | - | | | $ | 38 | |
UE: | | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Prices provided by other external sources(a) | | | (1 | ) | | | - | | | | - | | | | - | | | | (1 | ) |
Prices based on models and other valuation methods(b) | | | 8 | | | | 2 | | | | - | | | | - | | | | 10 | |
| Total | | $ | 7 | | | $ | 2 | | | $ | - | | | $ | - | | | $ | 9 | |
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 | |
CIPS: | | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Prices provided by other external sources(a) | | | (2 | ) | | | (1 | ) | | | (1 | ) | | | - | | | | (4 | ) |
Prices based on models and other valuation methods(b) | | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | | $ | (2 | ) | | $ | (1 | ) | | $ | (1 | ) | | $ | - | | | $ | (4 | ) |
Genco: | | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | | $ | (1 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | (1 | ) |
Prices provided by other external sources(a) | | | (1 | ) | | | - | | | | - | | | | - | | | | (1 | ) |
Prices based on models and other valuation methods(b) | | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | | $ | (2 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | (2 | ) |
CILCORP/CILCO: | | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | | $ | 1 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1 | |
Prices provided by other external sources(a) | | | (1 | ) | | | - | | | | - | | | | - | | | | (1 | ) |
Prices based on models and other valuation methods(b) | | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | |
IP: | | | | | | | | | | | | | | | | | | | | |
| Prices actively quoted | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Prices provided by other external sources(a) | | | (17 | ) | | | 1 | | | | - | | | | - | | | | (16 | ) |
Prices based on models and other valuation methods(b) | | | - | | | | - | | | | - | | | | - | | | | - | |
| Total | | $ | (17 | ) | | $ | 1 | | | $ | - | | | $ | - | | | $ | (16 | ) |
| (a) | Principally fixed price for floating over-the-counter power swaps, power forwards and fixed price for floating over-the-counter natural gas swaps. |
| (b) | Principally coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates. |
ITEM 4. CONTROLS AND PROCEDURES.
| (a) | Evaluation of Disclosure Controls and Procedures |
As of September 30, 2007, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
| (b) | Change in Internal Controls |
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.
For additional information on legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 7 – Related Party Transactions and Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, and Item 1A, Risk Factors, below of this report.
ITEM 1A. RISK FACTORS.
The Form 10-K includes a detailed discussion of our risk factors. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in the Form 10-K.
The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions which are largely outside of our control. Where these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position or liquidity.
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, and liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on our results of operations, financial position, or liquidity.
Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. With rising costs, including fuel and related transportation, purchased power, labor and material costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until rate relief is granted from state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary. Ameren remains subject to competitive, economic, political, legislative and regulatory pressures that could have a material adverse effect on our results of operations, financial position, or liquidity.
Illinois
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 requesting a modification of their electric delivery service rates effective January 2, 2007. In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS - an $8 million decrease, CILCO - a $21 million increase and IP - an $84 million increase) based on an allowed return on equity of 10%. In May 2007, the ICC issued an order disallowing the recovery of certain administrative and general expenses totaling $50 million. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which included the cost of power, so these delivery service revenue changes do not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.
Due to inadequate recovery of costs and low returns on equity being experienced in 2007, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates. In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until October 2008 to render a decision in these rate cases and could materially reduce the amount of the increase requested, or even reduce rates.
Electric Settlement Agreement
Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expired on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006. New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased
on behalf of Ameren Illinois Utilities’ customers in the September 2006 auction.
Due to the magnitude of these rate increases, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP at the rates that were in effect prior to January 2, 2007, and would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. The rate rollback and freeze legislation would have prevented the Ameren Illinois Utilities from recovering from retail customers substantial portions of the cost of electric energy the Ameren Illinois Utilities are purchasing under wholesale contracts entered into as a result of the September 2006 auction, and would have caused the Ameren Illinois Utilities to under-recover their delivery service costs until the ICC could approve higher delivery service rates.
As a result of these concerns, in July 2007, an agreement was reached among key stakeholders in Illinois that addresses the increase in electric rates and the future power procurement process. The settlement agreement was subject to enactment of legislation into law, which occurred on August 28, 2007. Ameren, on behalf of Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon, on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings, Inc., Midwest Generation, LLC, and MidAmerican Energy Company agreed to contribute an aggregate of approximately $1 billion over four years to fund both rate relief programs and the IPA. The agreement provides that if legislation is enacted in Illinois before August 1, 2011 freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on generation of electricity, then the remaining funding commitments will expire and any funds set aside in support of those commitments will be refunded to the utilities and electric generators. Also pursuant to the agreement, all pending litigation and regulatory actions by the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the electric space heating marketing practices of the Ameren Illinois utilities were withdrawn with prejudice.
Although we cannot fully predict the effect of the implementation of the settlement agreement and related comprehensive rate relief program on Ameren, the Ameren Illinois Utilities, Genco or AERG, we believe the settlement agreement significantly reduces the risk that legislation will be enacted into law that reduces and freezes electric rates of CIPS, CILCO and IP to rates that were in effect prior to January 2, 2007, or that imposes a tax on electric generation in Illinois. The following factors resulting from implementation of the Illinois electric settlement agreement could have a material adverse effect on the results of operations, financial position or liquidity of Ameren, the Ameren Illinois Utilities, Genco or AERG:
| · | uncertainty as to the implementation of the new power procurement process in Illinois for 2008 and 2009, including ICC review and approval requirements, the role of the IPA, and the ability of the Ameren Illinois Utilities to lease, or invest in, generation facilities; |
| · | the increase in short-term or long-term borrowings by the Ameren Illinois Utilities, Genco and AERG to fund contributions under the settlement agreement; |
| · | the failure by the electric generators that are party to the settlement agreement to perform in a timely manner under their respective funding agreements, which permit the Ameren Illinois Utilities to seek reimbursement for a portion of the rate relief that will be provided to certain of their electric customers; and |
| · | the extent to which Genco and AERG will be successful in making future sales to supply a portion of Illinois’ total electric demand through the revised power procurement mechanism. |
If, notwithstanding the Illinois settlement agreement, any decision is made or action occurs that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner, and such decision or action is not promptly enjoined, it could result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP.
Missouri
With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In March 2007, a stipulation and agreement was approved by the MoPSC authorizing an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. As part of this stipulation and agreement, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement does not prevent UE from filing to recover infrastructure costs through a statutory infrastructure system replacement surcharge (ISRS) during this three-year rate moratorium. The return on equity to be used by UE for purposes of any future ISRS tariff filing is 10.0%.
In May 2007, the MoPSC issued an order authorizing a $43 million increase in UE’s base rates for electric service based on a return on equity of 10.2%. The MoPSC denied UE’s and other intervenors’ applications for rehearing with respect to certain aspects of the MoPSC
rate order. In July 2007, UE appealed certain aspects of the MoPSC decision, principally the 10.2% return on equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both intervenors in the electric rate case, also appealed certain aspects of the MoPSC decision to the Circuit Court of Cole County. We cannot predict the outcome of these appeals of the MoPSC rate order. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.
Increased federal and state environmental regulation will cause UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and to incur increased operating costs. Future limits on greenhouse gas emissions would likely require UE, Genco, CILCO (through AERG) and EEI to incur significant additional increases in capital expenditures and operating costs and could result in the closures of coal-fired generating plants.
About 61% of Ameren’s generating capacity is coal-fired and about 85% of its electric generation was produced by its coal-fired plants in 2006. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. In May 2005, the EPA issued final regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. These regulations require significant additional reductions in the emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of aggregate capital compliance expenditures for UE, Genco, and EEI range from $3.5 billion to $4.5 billion by 2016.
Missouri rules, which substantially follow the federal regulations and became effective in April 2007, are expected to reduce mercury emissions 81% by 2018 and reduce NOx emissions 30% and SO2 emissions 75% by 2015.
Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. Genco, AERG and EEI will begin putting into service 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.
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity by the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. The costs to comply with future legislation or regulations could be so expensive that Ameren and other similarly situated electric power generators may be forced to close some coal-fired facilities. Mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.
The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were made.
In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. We are currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Resolution of the matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, Genco, AERG and EEI. A resolution could result in increased capital expenditures, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would likely require the installation of control technology, some of which is already
planned for compliance with other regulatory requirements such as the Clean Air Interstate Rule and the Illinois mercury emission rules.
New environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties and closure of power plants for UE, Genco, CILCO (through AERG) and EEI. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.
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 |
| July 1 – July 31, 2007 | | | 2,950 | | | $ | 49.11 | | | | - | | | | - | |
| August 1 – August 31, 2007 | | | - | | | | - | | | | - | | | | - | |
| September 1 – September 30, 2007 | | | 4,625 | | | | 53.58 | | | | - | | | | - | |
| Total | | | 7,575 | | | $ | 51.84 | | | | - | | | | - | |
| (a) | These shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligation upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998, as amended. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
The following table presents CILCO’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 |
| July 1 – July 31, 2007 | | | 11,000 | | | $ | 100.00 | | | | - | | | | - | |
| August 1 – August 31, 2007 | | | - | | | | - | | | | - | | | | - | |
| September 1 – September 30, 2007 | | | - | | | | - | | | | - | | | | - | |
| Total | | | 11,000 | | | $ | 100.00 | | | | - | | | | - | |
| (a) | CILCO redeemed these shares of its 5.85% Class A preferred stock to satisfy the mandatory sinking fund redemption requirement for this series of preferred stock for 2007. CILCO 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 July 1 to September 30, 2007 period.
ITEM 6. EXHIBITS.
The documents listed below are being filed on behalf of the Ameren Companies as indicated.
Exhibit Designation | Registrant(s) | Nature of Exhibit |
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 |
Exhibit Designation | Registrant(s) | Nature of Exhibit |
| 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 |
| 31.8 | Genco | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco |
| 31.9 | CILCORP | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP |
| 31.10 | CILCORP | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP |
| 31.11 | CILCO | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO |
| 31.12 | CILCO | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO |
| 31.13 | IP | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP |
| 31.14 | IP | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP |
Section 1350 Certifications |
| 32.1 | Ameren | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren |
| 32.2 | UE | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE |
| 32.3 | CIPS | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS |
| 32.4 | Genco | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco |
| 32.5 | CILCORP | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCORP |
| 32.6 | CILCO | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO |
| 32.7 | IP | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP |
SIGNATURES
Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
AMEREN CORPORATION
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
UNION ELECTRIC COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and
Principal Accounting Officer
(Principal Accounting Officer)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
AMEREN ENERGY GENERATING COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
�� Vice President and Controller
(Principal Accounting Officer)
CILCORP INC.
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
CENTRAL ILLINOIS LIGHT COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
ILLINOIS POWER COMPANY
(Registrant)
/s/ Martin J. Lyons
Martin J. Lyons
Vice President and Controller
(Principal Accounting Officer)
Date: November 9, 2007
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