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| AEE > SEC Filings for AEE > Form 10-Q on 10-Aug-2009 | All Recent SEC Filings |
10-Aug-2009
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 second quarter and first half of 2009 were lower compared with its earnings in the second quarter and first half of 2008 by $41 million and $38 million, respectively. Earnings in the second quarter and first half of 2009 were unfavorably impacted by higher net fuel costs, unfavorable unrealized MTM activity on derivatives, the absence in 2009 of a lump-sum payment from a coal supplier received last year as a result of the premature closure of a mine and termination of a contract, and other items. Reducing the impact of these factors in the second quarter and first half of 2009 were new utility service rates in Illinois, effective October 1, 2008, and in Missouri, effective March 1, 2009, as well as lower plant operations and maintenance expenses and warmer weather.
Ameren's rate-regulated businesses are currently earning well below their allowed rates of return largely as a result of regulatory lag associated with investments in utility infrastructure, as well as higher operating and financing costs and lower customer demand. Last fall, Ameren identified cost control measures in its rate-regulated businesses designed to reduce 2008 and 2009 capital and operating expenditures, as compared to prior plans, and took action to reduce such costs by $350 million to $400 million. Through recent planning efforts, Ameren has identified further possible opportunities to reduce planned capital expenditures and operations and maintenance expenses across its organization. Ameren is evaluating these opportunities, which it believes will lessen the impact of expected future energy cost increases on its customers while strengthening the financial profiles of the rate-regulated utilities. However, costs will not be reduced to a level that would prevent the Ameren Companies from providing safe and reliable service to their customers. In addition to identifying further possible opportunities to control costs, UE, CIPS, CILCO and IP have recently filed rate increase requests totaling over $600 million. The rate requests reflect the need to recover the significant investments made in utility infrastructure to improve reliability, increases in operating costs, higher financing costs and, in Missouri, rising net fuel costs.
At Ameren's Non-rate-regulated Generation segment, forward sales in prior years of expected generation is protecting its 2009 earnings from a significant decrease in market prices for power. Further, Non-rate-regulated Generation has hedged a substantial portion of its 2010 and 2011 forecasted generation. However, recent prices for electricity for 2010 and 2011 are lower than the prices being realized in 2009, or that have been locked-in through 2010 and 2011 forward sales. These lower power prices are linked to weak economic conditions, which are reducing the demand for power and other energy commodities. We believe that when the economy recovers, these prices will also rise.
The Non-rate-regulated Generation segment instituted cost control measures last fall to reduce 2008 and 2009 capital and operating expenditures, as compared to prior plans, and took action to reduce such costs by approximately $400 million to $450 million. The Non-rate-regulated Generation segment has now analyzed further its plans for 2010 through 2013 and implemented significant additional planned spending reductions. Approximately $1 billion of capital expenditure reductions have been made from Non-rate-regulated Generation's previous 2010 to 2013 estimates. These reductions are expected to be achieved by eliminating almost all capital expenditures other than mandatory environmental and maintenance-type projects. While the Non-rate-regulated Generation segment does not expect to realize the efficiencies that may have otherwise resulted from these expenditures, it does not believe such expenditures are cost-justified in the current power market and credit environment. However, as a result of eliminating these capital expenditures, reduced scheduled outage time is expected to more than offset increased unplanned outages. This should improve the net availability of Non-rate-regulated Generation's core baseload power plants. Non-rate-regulated Generation's small noncore generating facilities are not currently expected to be sold as was previously being explored. Alternative operating modes for these small plants are being considered to improve their profitability. It is the expectation that actions being taken to address costs in the Non-rate-regulated Generation segment will result in 2010 nonfuel operations and maintenance expenses that are 5% to 10% lower than 2008 levels.
Ameren has identified approximately $2 billion of opportunities to reduce Ameren consolidated planned capital expenditures for 2010 through 2013, as compared to earlier plans. This amount includes approximately $1 billion of planned capital expenditure reductions in the Non-rate-regulated Generation segment for this period, as discussed above. In Ameren's rate-regulated businesses, approximately $1 billion of potential reductions have been identified. Which projects may be eliminated or deferred is currently being evaluated. Ameren is also reviewing planned operations and maintenance expenditures across the organization, but especially in the Non-rate-regulated Generation business and business support functions. Ameren's objective is to significantly lower 2010 nonfuel operations and maintenance costs, relative to the 2008 level, in its Non-rate-regulated Generation segment. Planned and potential cost-containment actions include reduced scheduled Non-rate-regulated Generation power plant outages, wage and workforce reductions, and other cost reductions in business support functions.
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 and the payment of other expenses by the Ameren and CILCORP holding companies 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 for fuel 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 have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses, purchased power cost recovery mechanisms for our Illinois electric delivery businesses and a FAC for our Missouri electric utility business. See Note 2-Rate and Regulatory Matters to our financial statements under Part I, Item 1, for a discussion of pending rate cases in Missouri and Illinois, including UE's request for approval to implement an environmental cost recovery mechanism and to continue its FAC. 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.
Net income attributable to Ameren Corporation decreased to $165 million, or 77 cents per share, in the second quarter of 2009, from $206 million, or 98 cents per share, in the second quarter of 2008. Net income attributable to Ameren Corporation in the second quarter of 2009 increased in the Illinois Regulated segment by $29 million from the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated and Non-rate-regulated Generation segments decreased by $40 million and $23 million, respectively, from the same period in 2008.
Net income attributable to Ameren Corporation decreased to $306 million, or $1.43 per share, in the first six months of 2009 from $344 million, or $1.64 per share, in the first six months of 2008. Net income attributable to Ameren Corporation increased in the Illinois Regulated segment by $38 million in the first six months of 2009 compared to the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated and Non-rate-regulated Generation segments decreased by $71 million and $8 million, respectively, from the same period in 2008.
Earnings were negatively impacted in the second quarter and first six months of 2009 as compared with the same periods in 2008 by:
• lower electric and gas margins at our rate-regulated businesses, primarily as a result of higher net fuel costs at UE, excluding favorable impacts of rate increases noted below (20 cents per share and 37 cents per share, respectively);
• unfavorable net unrealized MTM activity on derivatives (19 cents per share and 10 cents per share, respectively);
• the absence in 2009 of a settlement agreement reached with a coal mine owner that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation incurred in 2008 and expected to be incurred in 2009 due to the premature closure of an Illinois mine at the end of 2007 (18 cents per share and 18 cents per share, respectively);
• higher financing costs (5 cents per share and 9 cents per share, respectively);
• increased depreciation and amortization expense (5 cents per share and 6 cents per share, respectively);
• reduced sales to Noranda due to a severe storm-related outage (3 cents per share and 6 cents per share, respectively);
• the absence in 2009 of storm costs recorded as a regulatory asset as a result of an accounting order issued by the MoPSC (4 cents per share and 4 cents per share, respectively); and
• increased distribution system reliability expenditures (2 cents per share and 3 cents per share, respectively).
Earnings were favorably impacted in the second quarter and first six months of 2009 as compared with the same period in 2008 by:
• higher electric and natural gas delivery service rates, effective October 1, 2008, in the Illinois Regulated segment pursuant to an ICC consolidated rate order for CIPS, CILCO, and IP (14 cents per share and 26 cents per share, respectively);
• higher electric rates, effective March 1, 2009, in the Missouri Regulated segment pursuant to a MoPSC rate order (12 cents per share and 15 cents per share, respectively);
• decreased plant operations and maintenance expense (10 cents per share and 12 cents per share, respectively);
• favorable weather conditions (estimated at 7 cents per share and 4 cents per share, respectively);
• higher electric margins in the Non-rate-regulated Generation segment (5 cents per share and 8 cents per share, respectively); and
• the reduced impact in 2009 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (2 cents per share and 3 cents per share, respectively).
In addition to the above items affecting both periods, earnings were unfavorably impacted in the first six months of 2009, as compared with the first six months of 2008, by the implementation of redesigned gas delivery service rates at the Ameren Illinois Utilities, which impacts quarterly earnings comparison but is not expected to have a material impact on annual margins (4 cents per share).
The cents per share information presented above is based on average shares outstanding in the second quarter and first six months of 2008.
Because it is a holding company, net income attributable to Ameren Corporation 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 net income attributable to Ameren Corporation for the three and six months ended June 30, 2009 and 2008:
Three Months Six Months
2009 2008 2009 2008
Net income (loss):
UE $ 82 $ 122 $ 103 $ 185 (a)
CIPS 1 (3 ) 7 (1 )
Genco 46 74 93 120
CILCORP 24 4 (408 )(b) 24
IP 13 (10 ) 26 (8 )
Other(c) (1 ) 19 485 (b) 24
Net income attributable to Ameren Corporation $ 165 $ 206 $ 306 $ 344
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(a) Includes earnings from a non-rate-regulated 40% interest in EEI through February 29, 2008.
(b) Includes goodwill impairment loss of $462 million offset by intercompany elimination in Other as no impairment was recognized at the consolidated Ameren level. See Note 14 - Goodwill Impairment to our financial statements under Part I, Item 1, of this report for additional information.
(c) Includes earnings from EEI, other non-rate-regulated operations, as well as corporate general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI prior to February 29, 2008, and an 80% interest in EEI since that date.
Below is a table of income statement components by segment for the three and six months ended June 30, 2009 and 2008:
Non-rate- Other /
Missouri Illinois regulated Intersegment
Regulated Regulated Generation Eliminations Total
Three Months 2009:
Electric margin $ 534 $ 223 $ 259 $ (7 ) $ 1,009
Gas margin 14 72 - - 86
Other revenues 1 - - (1 ) -
Other operations and maintenance (220 ) (153 ) (84 ) 6 (451 )
Depreciation and amortization (90 ) (54 ) (31 ) (7 ) (182 )
Taxes other than income taxes (66 ) (25 ) (7 ) 1 (97 )
Other income and (expenses) 13 2 - (5 ) 10
Interest expense (57 ) (40 ) (23 ) (4 ) (124 )
Income taxes (45 ) (8 ) (39 ) 9 (83 )
Net income (loss) 84 17 75 (8 ) 168
Noncontrolling interest and
preferred dividends (2 ) (2 ) - 1 (3 )
Net income (loss) attributable
to Ameren Corporation 82 15 75 (7 ) 165
Three Months 2008:
Electric margin $ 595 $ 188 $ 322 $ (4 ) $ 1,101
Gas margin 17 63 - (2 ) 78
Other operations and maintenance (238 ) (160 ) (92 ) 14 (476 )
Depreciation and amortization (82 ) (55 ) (27 ) (7 ) (171 )
Taxes other than income taxes (60 ) (24 ) (6 ) 1 (89 )
Other income and (expenses) 13 3 2 (7 ) 11
Interest expense (50 ) (37 ) (29 ) (2 ) (118 )
Income taxes (71 ) 9 (64 ) 7 (119 )
Net income (loss) 124 (13 ) 106 - 217
Noncontrolling interest and
preferred dividends (2 ) (1 ) (8 ) - (11 )
Net income (loss) attributable
to Ameren Corporation 122 (14 ) 98 - 206
Six Months 2009:
Electric margin $ 945 $ 416 $ 546 $ (10 ) $ 1,897
Gas margin 41 183 - - 224
Other revenues 2 4 - (6 ) -
Other operations and maintenance (436 ) (289 ) (162 ) 15 (872 )
Depreciation and amortization (176 ) (107 ) (59 ) (14 ) (356 )
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Non-rate- Other /
Missouri Illinois regulated Intersegment
Regulated Regulated Generation Eliminations Total
Taxes other than income taxes (128 ) (64 ) (14 ) (1 ) (207 )
Other income and (expenses) 24 3 - (5 ) 22
Interest expense (110 ) (81 ) (48 ) (3 ) (242 )
Income taxes (56 ) (22 ) (93 ) 18 (153 )
Net income (loss) 106 43 170 (6 ) 313
Noncontrolling interest and
preferred dividends (3 ) (3 ) (2 ) 1 (7 )
Net income (loss) attributable to
Ameren Corporation 103 40 168 (5 ) 306
Six Months 2008:
Electric margin $ 1,036 $ 366 $ 596 $ (17 ) $ 1,981
Gas margin 45 188 - (2 ) 231
Other operations and maintenance (455 ) (307 ) (171 ) 28 (905 )
Depreciation and amortization (163 ) (110 ) (54 ) (13 ) (340 )
Taxes other than income taxes (120 ) (67 ) (14 ) (1 ) (202 )
Other income and (expenses) 25 7 1 (8 ) 25
Interest expense (91 ) (72 ) (50 ) (5 ) (218 )
Income taxes (100 ) - (116 ) 10 (206 )
Net income (loss) 177 5 192 (8 ) 366
Noncontrolling interest and
preferred dividends (3 ) (3 ) (16 ) - (22 )
Net income (loss) attributable to
Ameren Corporation 174 2 176 (8 ) 344
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Margins
The following table presents the favorable (unfavorable) variations in the registrants' electric and gas margins for the three and six months ended June 30, 2009, compared with the same periods in 2008. 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) $ 20 $ 17 $ 2 $ - $ - $ - $ 1 Regulated rates: Changes in base rates 69 42 5 - - - 22 Noranda sales (14 ) (14 ) - - - - - Illinois pass-through power costs (46 ) - (6 ) - (16 ) (16 ) (24 ) Non-rate-regulated Generation sales price changes 30 - - 39 17 17 - Off-system revenues (59 ) (59 ) - - - - - Illinois electric settlement agreement, net of reimbursement 3 - - 2 2 2 - Net MTM gains 5 (7 ) - - - - - Generation output and other (40 ) 10 (7 ) (19 ) 12 12 (10 ) Total electric revenue change $ (32 ) $ (11 ) $ (6 ) $ 22 $ 15 $ 15 $ (11 ) Fuel and purchased power change: Fuel: Generation and other $ (59 ) $ (7 ) $ - $ (61 ) $ 3 $ 3 $ - Reduced net MTM gains (75 ) (52 ) - (15 ) (3 ) (3 ) - Price (13 ) - - (4 ) (1 ) (1 ) - Purchased power 41 9 8 - 7 7 11 Illinois pass-through power costs 46 - 6 - 16 16 24 Total fuel and purchased power change $ (60 ) $ (50 ) $ 14 $ (80 ) $ 22 $ 22 $ 35 Net change in electric margin $ (92 ) $ (61 ) $ 8 $ (58 ) $ 37 $ 37 $ 24 Gas margin change: Effect of weather (estimate) $ (1 ) $ - $ - $ - $ - $ - $ (1 ) Gas rate increases 12 - 3 - (1 ) (1 ) 10 Illinois seasonal rate redesign 5 - 1 - 1 1 3 Other (8 ) (3 ) (1 ) - (5 ) (5 ) (1 ) Net change in gas margin $ 8 $ (3 ) $ 3 $ - $ (5 ) $ (5 ) $ 11 |
Six Months Ameren (a) UE CIPS Genco CILCORP CILCO IP Electric revenue change: Effect of weather (estimate) $ 8 $ 6 $ 1 $ - $ - $ - $ 1 . . . |
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