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| AEE > SEC Filings for AEE > Form 10-Q on 10-Nov-2008 | All Recent SEC Filings |
10-Nov-2008
Quarterly Report
The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q as well as Management's Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of the various segments of our business to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole.
OVERVIEW
Ameren Executive Summary
Ameren's earnings in the third quarter of 2008 were lower than its earnings in the 2007 comparable period principally because of net unrealized mark-to-market losses from nonqualifying hedges, the negative impacts of milder summer weather, higher fuel prices, increased spending on utility distribution system reliability, and higher other operating expenses. These factors more than offset the positive impacts of the reduced impact in 2008 of the Illinois electric settlement agreement, higher electric margins from Non-rate-regulated Generation's operations, and the timing benefit of seasonally redesigned electric rates in Illinois.
Ameren's earnings in the first nine months of 2008 exceeded its earnings in the comparable period in 2007 principally because of the impact of net unrealized mark-to-market gains from nonqualifying hedges; a lump-sum payment in July 2008 from a coal supplier for expected higher fuel costs for our Non-rate-regulated Generation segment in 2009 as a result of the premature closure of a mine in late 2007 and the resulting termination of a contract; the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms; the estimated minimum amount of January 2007 storm costs that UE expects to recover, as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset in the second quarter of 2008; a March 2007 FERC order that resettled costs among market participants retroactive to 2005; and the reduced impact in 2008 of the Illinois electric settlement agreement.
In September 2008, the ICC authorized increases in electric and natural gas rates for CIPS, CILCO and IP totaling $161 million. The new Illinois rates went into effect on October 1, 2008. These increased rates will improve the earnings and cash flows of the Ameren Illinois Utilities from depressed levels. However, the Ameren Illinois Utilities continue to expect that these rates will not keep pace with the level of costs they are currently experiencing. Consequently, the Ameren Illinois Utilities are evaluating the timing of their next rate case filings in Illinois. The Ameren Illinois Utilities expect to file rate cases more frequently in the future to minimize regulatory lag as well as to make bill increases more manageable for customers.
UE's pending electric rate case is progressing. UE requested an annual electric revenue increase of approximately $251 million due to higher costs across its business, including fuel and reliability costs, as well as higher infrastructure investments. The MoPSC staff filed in August 2008 a report and direct testimony with the MoPSC recommending a $51 million increase, and the staff did not support UE's request for a fuel and purchased power cost recovery mechanism. UE expects the MoPSC to issue a rate order in late January or early February 2009, with new rates effective March 1, 2009.
The global financial markets have experienced extreme volatility and disruption in 2008, and in particular, since early September. This disruption has lead to major financial institutions coming under financial duress, significant strains in the capital and credit markets, deteriorating global economic conditions and steep declines in stock prices.
We believe that the extreme disruption in the capital and credit markets has made our ability to access the capital and credit markets to support our operations and refinance short-term debt more challenging. We are proactively taking prudent actions to modify our short-term plans to address the current economic and financial market uncertainties. At October 31, 2008, our available liquidity, which represents our cash on hand and amounts available under our credit facilities, was approximately $1.45 billion, up about $550 million from this same time last year. Despite this solid liquidity position, we are reducing 2009 operating and capital expenditures in our Non-rate-regulated Generation business by a total of $400 million to $500 million. Operating and capital expenditures in 2009 for this business will be approximately $300 million to $400 million below 2008 levels. Other meaningful capital expenditure deferral and reduction opportunities are also under review throughout the rest of our company. We will remain focused on prudently managing our operations and maintaining strong overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plans.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren's primary assets are the common stock of its subsidiaries. Ameren's subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock are dependent on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below.
· UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.
· CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
· Genco operates a non-rate-regulated electric generation business in Illinois and Missouri.
· CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG) in Illinois.
· IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren's earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren's earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding during the applicable period. All tabular dollar amounts are in millions, unless otherwise indicated.
RESULTS OF OPERATIONS
Earnings Summary
Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren's revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently have a fuel and purchased power cost recovery mechanism in Missouri for our electric utility business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, for a discussion of UE's pending electric rate case, the September 24, 2008 ICC order in the Ameren Illinois Utilities rate proceedings and the Illinois electric settlement agreement. Fluctuations in interest rates and conditions in the capital and credit markets 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 $204 million, or 97 cents per share, in the third quarter of 2008, from $244 million, or $1.18 per share, in the third quarter of 2007. Net income in the third quarter of 2008 increased in the Illinois Regulated and Non-rate-regulated Generation segments by $21 million and $37 million, respectively, from the prior-year period, while net income in the Missouri Regulated segment declined by $80 million from the same period in 2007.
Ameren's net income increased to $548 million, or $2.61 per share, in the first nine months of 2008, from $510 million, or $2.46 per share, in the first nine months of 2007. Net income increased in the Missouri Regulated and Non-rate-regulated Generation segments by $9 million and $87 million, respectively, in the first nine months of 2008 compared to the prior-year period, while net income in the Illinois Regulated segment decreased by $30 million from the same period in 2007.
Earnings were favorably impacted in the third quarter and first nine months of 2008 as compared with the same periods in 2007 by:
· the reduced impact in 2008 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (15 cents per share and 8 cents per share, respectively);
· the implementation of redesigned seasonal electric delivery service rates at the Ameren Illinois Utilities, which impacts quarterly earnings comparisons in 2008 but is not expected to have an impact on annual margins (11 cents per share and 5 cents per share, respectively); and
· higher realized electric margins in the Non-rate-regulated Generation segment.
Earnings were negatively impacted in the third quarter and first nine months of 2008 as compared with the same periods in 2007 by:
· higher fuel and related transportation prices, excluding net mark-to-market losses on fuel-related transactions, (8 cents per share and 25 cents per share, respectively);
· unfavorable weather conditions (estimated at 18 cents per share in both periods);
· increased distribution system reliability expenditures (6 cents per share and 20 cents per share, respectively);
· higher plant operations and maintenance expense (2 cents per share and 10 cents per share, respectively);
· higher labor and employee benefit costs (3 cents per share and 9 cents per share, respectively);
· higher bad debt expenses (2 cents per share and 5 cents per share, respectively);
· increased depreciation and amortization expense (2 cents per share and 5 cents per share, respectively); and
· higher financing costs (1 cent per share and 7 cents per share, respectively).
In addition to the above items affecting both periods, earnings were favorably impacted in the first nine months of 2008 as compared with the first nine months of 2007 by:
· a settlement agreement with a coal mine owner reached in June 2008 that reimbursed Genco, in the form of a lump-sum payment of $60 million, for increased costs for coal and transportation that it is incurring in 2008 ($33 million) and expects to incur in 2009 ($27 million) due to the premature closure of an Illinois mine at the end of 2007 (18 cents per share);
· the absence of costs in 2008 that were incurred in 2007 relating to a refueling and maintenance outage at UE's Callaway nuclear plant (16 cents per share);
· net unrealized mark-to-market gains primarily related to energy-related transactions (6 cents per share);
· the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms (9 cents per share);
· the minimum amount of January 2007 storm costs that UE expects to recover, as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset (4 cents per share);
· higher electric rates, lower depreciation expense and decreased income tax expense in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (8 cents per share); and
· a March 2007 FERC order that resettled costs among market participants retroactive to 2005 (5 cents per share).
Earnings were negatively impacted in the first nine months of 2008 as compared with the first nine months of 2007 by the absence in 2008 of the reversal, recorded in 2007, of the Illinois Customer Elect electric rate increase phase-in plan accrual (5 cents per share) and higher labor and employee benefit costs (4 cents per share).
Earnings were negatively impacted in the third quarter of 2008 as compared with the third quarter of 2007 by net unrealized mark-to-market losses on nonqualifying hedges primarily related to fuel-related transactions (20 cents per share).
The cents per share information presented above is based on average shares outstanding in the third quarter and first nine months of 2007.
Because it is a holding company, Ameren's net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren's principal subsidiaries to Ameren's consolidated net income for the three months and nine months ended September 30, 2008 and 2007:
Three Months Nine Months
2008 2007 2008 2007
Net income (loss):
UE(a) $ 98 $ 192 $ 283 $ 303
CIPS 6 - 5 17
Genco 20 25 140 84
CILCORP 18 1 42 34
IP 4 (5 ) (4 ) 16
Other(b) 58 31 82 56
Ameren net income $ 204 $ 244 $ 548 $ 510
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(a) Includes earnings from a non-rate-regulated 40% interest in EEI through February 29, 2008.
(b) Includes earnings from non-rate-regulated operations and an 80% interest in EEI held by Resources Company since February 29, 2008, as well as corporate general and administrative expenses, and intercompany eliminations. Prior to February 29, 2008, included a 40% interest in EEI held by Development Company, as well as corporate general and administrative expenses and intercompany eliminations.
Below is a table of income statement components by segment for the three months and nine months ended September 30, 2008 and 2007:
Non-rate- Other /
Missouri Illinois regulated Intersegment
Regulated Regulated Generation Eliminations Total
Three Months 2008:
Electric
margin $ 570 $ 234 $ 315 $ (23 ) $ 1,096
Gas margin 10 50 - (1 ) 59
Other revenues 1 - - (1 ) -
Other operations and
maintenance (234 ) (149 ) (77 ) 11 (449 )
Depreciation and
amortization (83 ) (60 ) (29 ) (8 ) (180 )
Taxes other than income
taxes (69 ) (24 ) (6 ) 1 (98 )
Other income and
(expenses) 15 3 (1 ) (4 ) 13
Interest
expense (51 ) (34 ) (24 ) (4 ) (113 )
Income taxes (60 ) (5 ) (61 ) 13 (113 )
Minority interest and preferred
dividends (1 ) (2 ) (9 ) 1 (11 )
Net income
(loss) $ 98 $ 13 $ 108 $ (15 ) $ 204
Three Months 2007:
Electric
margin $ 677 $ 186 $ 265 $ (13 ) $ 1,115
Gas margin 9 49 - (1 ) 57
Other revenues 1 1 - (2 ) -
Other operations and
maintenance (222 ) (138 ) (77 ) 20 (417 )
Depreciation and
amortization (81 ) (59 ) (28 ) (8 ) (176 )
Taxes other than income
taxes (70 ) (23 ) (6 ) 2 (97 )
Other income and
(expenses) 8 6 1 (4 ) 11
Interest
expense (49 ) (35 ) (28 ) 2 (110 )
Income taxes (94 ) 7 (49 ) 6 (130 )
Minority interest and preferred
dividends (1 ) (2 ) (7 ) 1 (9 )
Net income
(loss) $ 178 $ (8 ) $ 71 $ 3 $ 244
Nine Months 2008:
Electric
margin $ 1,606 $ 600 $ 911 $ (40 ) $ 3,077
Gas margin 55 239 - (4 ) 290
Other revenues 1 - - (1 ) -
Other operations and
maintenance (689 ) (446 ) (245 ) 40 (1,340 )
Depreciation and
amortization (246 ) (181 ) (86 ) (21 ) (534 )
Taxes other than income
taxes (189 ) (91 ) (20 ) - (300 )
Other income and
(expenses) 40 10 - (12 ) 38
Interest
expense (142 ) (106 ) (74 ) (9 ) (331 )
Income taxes (160 ) (5 ) (177 ) 23 (319 )
Minority interest and preferred
dividends (4 ) (5 ) (25 ) 1 (33 )
Net income
(loss) $ 272 $ 15 $ 284 $ (23 ) $ 548
Nine Months 2007:
Electric
margin $ 1,579 $ 572 $ 766 $ (32 ) $ 2,885
Gas margin 50 227 - (4 ) 273
Other revenues 2 3 - (5 ) -
Other operations and
maintenance (668 ) (383 ) (234 ) 55 (1,230 )
Depreciation and
amortization (252 ) (177 ) (85 ) (20 ) (534 )
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Non-rate- Other /
Missouri Illinois regulated Intersegment
Regulated Regulated Generation Eliminations Total
Taxes other than income
taxes (187 ) (89 ) (20 ) 1 (295 )
Other income and
(expenses) 24 16 3 (9 ) 34
Interest
expense (146 ) (97 ) (81 ) 8 (316 )
Income taxes (135 ) (22 ) (132 ) 10 (279 )
Minority interest and preferred
dividends (4 ) (5 ) (20 ) 1 (28 )
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Margins
The following table presents the favorable (unfavorable) variations in the registrants' electric and gas margins for the three months and nine months ended September 30, 2008, compared with the same periods in 2007. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange, and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies' presentations or more useful than the GAAP information we provide elsewhere in this report.
Three Months Ameren(a) UE CIPS Genco CILCORP CILCO IP
Electric revenue
change:
Effect of weather
(estimate) $ (76 ) $ (30 ) $ (13 ) $ - $ (8 ) $ (8 ) $ (25 )
Interchange revenues,
excluding estimate
weather impact of $44
million (33 ) (33 ) - - - - -
Illinois electric
settlement agreement,
net
of reimbursement 43 - 7 17 12 12 10
Illinois rate redesign 46 - 15 - 7 7 24
Net mark-to-market
gains (losses) on
energy contracts 55 (5 ) - - - - -
Other, including
growth and Illinois
customer switching 21 (6 ) (20 ) - 41 41 (13 )
Total electric revenue
change $ 56 $ (74 ) $ (11 ) $ 17 $ 52 $ 52 $ (4 )
Fuel and purchased
power change:
Fuel:
Generation and other $ 18 $ 13 $ - $ 12 $ (7 ) $ (9 ) $ -
Emission allowance
sales (costs) (1 ) (5 ) - 3 - - -
Net mark-to-market
(losses) on fuel
contracts (111 ) (59 ) - (30 ) (8 ) (8 ) -
Price (29 ) (8 ) - (14 ) (4 ) (4 ) -
Purchased power 57 26 28 1 (3 ) (3 ) 31
Illinois rate redesign (9 ) - (3 ) - (1 ) (1 ) (5 )
Total fuel and
purchased power change $ (75 ) $ (33 ) $ 25 $ (28 ) $ (23 ) $ (25 ) $ 26
Net change in electric
margins $ (19 ) $ (107 ) $ 14 $ (11 ) $ 29 $ 27 $ 22
Net change in gas
margins $ 2 $ 1 $ 2 $ - $ (3 ) $ (3 ) $ 4
Nine Months
Electric revenue
change:
Effect of weather
(estimate) $ (100 ) $ (35 ) $ (20 ) $ - $ (11 ) $ (11 ) $ (34 )
UE electric rate
increase 16 16 - - - - -
Interchange revenues,
excluding estimated
weather impact of $54
million 41 41 - - - - -
Illinois electric
settlement agreement,
net
of reimbursement 24 - 4 8 6 6 6
FERC-ordered MISO
resettlements -
March 2007 (16 ) - - (12 ) (4 ) (4 ) -
Illinois rate redesign 16 - 5 - 2 2 9
Net mark-to-market
gains on
energy contracts 48 13 - - - - -
Other, including
growth and Illinois
customer switching 60 27 (55 ) 19 71 71 (41 )
Total electric revenue
change $ 89 $ 62 $ (66 ) $ 15 $ 64 $ 64 $ (60 )
Fuel and purchased
power change:
Fuel:
Generation and other $ (1 ) $ 7 $ - $ 17 $ (26 ) $ (28 ) $ -
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Nine Months Ameren(a) UE CIPS Genco CILCORP CILCO IP Emission allowance sales 2 (4 ) - 5 - - - Net mark-to-market (losses) on fuel contracts (12 ) (5 ) - (2 ) - - - Price (88 ) (40 ) - (31 ) (9 ) (9 ) - Coal contract settlement 60 - - 60 - - - Purchased power 108 (6 ) 60 25 (8 ) (8 ) 63 Illinois rate redesign 2 - 1 - 1 1 - FERC-ordered MISO resettlements - March 2007 32 11 7 - 3 3 11 Total fuel and . . . |
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