UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| (X) | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, | |
OR | ||
| ( ) | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to | |
Commission File Number | Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | IRS Employer Identification No. | ||
1-14756 | Ameren Corporation | 43-1723446 | ||
(Missouri Corporation) | ||||
1901 Chouteau Avenue | ||||
St. Louis, Missouri 63103 | ||||
(314) 621-3222 | ||||
1-2967 | Union Electric Company | 43-0559760 | ||
(Missouri Corporation) | ||||
1901 Chouteau Avenue | ||||
St. Louis, Missouri 63103 | ||||
(314) 621-3222 | ||||
1-3672 |
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(Illinois Corporation) | ||||
300 Liberty Street | ||||
Peoria, Illinois 61602 | ||||
(309) 677-5271 | ||||
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(Illinois Corporation) | ||||
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Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:
The following securities aresecurity is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and areis listed on the New York Stock Exchange:
Registrant | Title of each class | |
Ameren Corporation | Common Stock, $0.01 par value per share | |
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
Registrant | Title of each class | ||||
Union Electric Company | Preferred Stock, cumulative, no par value, | ||||
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share Depository Shares, each representing one-fourth of a | |||||
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Ameren Energy Generating Company and Illinois Power Company dodoes not have securities registered under either Section 12(b) or 12(g) of the Securities Exchange Act of 1934.
Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.
Ameren Corporation | Yes | (X | ) | No | ( | ) | ||||||||||
Union Electric Company | Yes | (X | ) | No | ( | ) | ||||||||||
| Yes | ( | ) | No | (X | ) | ||||||||||
Ameren Energy Generating Company | Yes | ( | ) | No | ||||||||||||
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Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Ameren Corporation | Yes | ( | ) | No | (X | ) | ||||||||||
Union Electric Company | Yes | ( | ) | No | (X | ) | ||||||||||
| Yes | ( | ) | No | (X | ) | ||||||||||
Ameren Energy Generating Company | Yes | ( | ) | No | ||||||||||||
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Indicate by checkmark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Ameren Corporation | Yes | (X | ) | No | ( | ) | ||||||||||
Union Electric Company | Yes | (X | ) | No | ( | ) | ||||||||||
| Yes | (X | ) | No | ( | ) | ||||||||||
Ameren Energy Generating Company | Yes | (X | ) | No | ||||||||||||
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Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Ameren Corporation | (X) | |
Union Electric Company | (X) | |
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Ameren Energy Generating | ||
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| (X) |
Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate Web site,website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Ameren Corporation | Yes | (X | ) | No | ( | ) | ||||||||||
Union Electric Company | Yes | ( | ) | No | ( | ) | ||||||||||
| Yes | ( | ) | No | ( | ) | ||||||||||
Ameren Energy Generating Company | Yes | ( | ) | No | ||||||||||||
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Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
| Large Accelerated Filer | Accelerated Filer | Non-accelerated Filer | Smaller Company | |||||
Ameren Corporation | (X) | ( ) | ( ) | ( ) | ||||
Union Electric Company | ( ) | ( ) | (X) | ( ) | ||||
| ( ) | ( ) | (X) | ( ) | ||||
Ameren Energy Generating | ||||||||
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| ( ) | ( ) | (X) | ( ) |
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Ameren Corporation | Yes | ( | ) | No | (X | ) | ||||||||||
Union Electric Company | Yes | ( | ) | No | (X | ) | ||||||||||
| Yes | ( | ) | No | (X | ) | ||||||||||
Ameren Energy Generating Company | Yes | ( | ) | |||||||||||||
| No | |||||||||||||||
| (X | ) |
As of June 30, 2009,2010, Ameren Corporation had 214,228,275239,131,488 shares of its $0.01 par value common stock outstanding. The aggregate market value of these shares of common stock (based upon the closing price of these sharesthe common stock on the New York Stock Exchange on that date) held by nonaffiliates was $5,332,141,765.$5,684,155,470. The shares of common stock of the other registrants were held by affiliates as of June 30, 2009.2010.
The number of shares outstanding of each registrant’s classes of common stock as of January 29, 2010,31, 2011, was as follows:
Ameren Corporation | Common stock, $0.01 par value per share: | |
Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): 102,123,834 | |
| Common stock, no par value, held by Ameren Corporation (parent company of the registrant): 25,452,373 | |
Ameren Energy Generating Company | Common stock, no par value, held by Ameren Energy Resources Company, LLC (parent company of the registrant and subsidiary of Ameren Corporation): 2,000 | |
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company Centraland Ameren Illinois Public Service Company, and Central Illinois Light Company for the 20102011 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
OMISSION OF CERTAIN INFORMATION
Ameren Energy Generating Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, CentralAmeren Illinois Public Service Company and Ameren Energy Generating Company, Central Illinois Light Company, and Illinois Power Company. Each registrant hereto is filing on its own behalf all of the information contained in this annual report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.
This Form 10-Kreport contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on pages 3, 4 and 45 of this Form 10-Kreport under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.
GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.
2007 Illinois Electric Settlement Agreement–A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, effective January 2, 2007. The settlement, which became effective on August 28,in 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addressed the issue of power procurement, and it included a comprehensive rate relief and customer assistance program.
2009 Illinois Credit Agreement – Ameren’s and AIC’s $800 million senior secured credit agreement, which terminated on September 10, 2010.
2009 Multiyear Credit Agreement – Ameren’s, UE’s and Genco’s $1.15 billion credit agreement, which terminated on September 10, 2010. Collectively, this agreement and the 2009 Supplemental Credit Agreement are referred to herein as the “2009 Multiyear Credit Agreements.”
2009 Supplemental Credit Agreement – Ameren’s, UE’s and Genco’s $150 million supplemental credit agreement to the 2009 Multiyear Credit Agreement. This agreement expired in July 2010.
2010 Credit Agreements – The 2010 Genco Credit Agreement, the 2010 Illinois Credit Agreement, and the 2010 Missouri Credit Agreement, collectively.
2010 Genco Credit Agreement – On September 10, 2010, Ameren and Genco entered into a $500 million multiyear senior unsecured revolving credit facility. This agreement expires on September 10, 2013.
2010 Illinois Credit Agreement – On September 10, 2010, Ameren and AIC entered into an $800 million multiyear senior unsecured credit agreement. This agreement expires on September 10, 2013.
2010 Missouri Credit Agreement – On September 10, 2010, Ameren and UE entered into an $800 million multiyear senior unsecured revolving credit facility. This agreement expires on September 10, 2013, subject to UE’s borrowing sublimit extensions.
AERG– AmerenEnergy Resources Generating Company, a CILCO subsidiary until October 1, 2010, that operates a merchant electric generation business in Illinois. On October 1, 2010, AERG stock was distributed to Ameren and subsequently contributed by Ameren to Resources Company, which resulted in AERG becoming a subsidiary of Resources Company.
AFS– Ameren Energy Fuels and Services Company, a Resources Company subsidiary that procuresprocured fuel and natural gas and managesmanaged the related risks for the Ameren Companies.Companies prior to January 1, 2011. Effective January 1, 2011, the functions previously performed by AFS are performed within the Ameren Missouri, Ameren Illinois and Merchant Generation business segments.
AITCAIC– Ameren Illinois Transmission Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. This
business consists of the combined rate-regulated electric and natural gas transmission and distribution businesses operated by CIPS, CILCO and IP before the AIC Merger. References to AIC prior to the AIC Merger refer collectively to the rate-regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO and IP. Immediately after the AIC Merger, AIC distributed the common stock of AERG to Ameren Corporation. AERG is engaged in the construction andtreated as a discontinued operation of transmission assetswithin AIC’s financial statements. AIC operates its business in Illinois as Ameren Illinois.
AIC Merger – On October 1, 2010, CILCO and is regulated byIP merged with and into CIPS, with the ICC.surviving corporation renamed Ameren Illinois Company.
Ameren– Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies– The individual registrants within the Ameren consolidated group.
Ameren Illinois Utilities– CIPS, IP, and theA financial reporting segment consisting of AIC’s rate-regulated electric and natural gas utility operationsbusinesses. AIC also operates its business in Illinois as Ameren Illinois.
Ameren Missouri – A financial reporting segment consisting of CILCO.UE’s rate-regulated businesses. UE also operates its business in Missouri as Ameren Missouri.
Ameren Services– Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.
AMIL– The MISO balancing authority area operated by Ameren, which includes the load of the Ameren Illinois UtilitiesAIC and the generating assets of Genco (excluding EEI and Genco’s Elgin CT facility) and AERG.
AMMO– The MISO balancing authority area operated by Ameren, which includes the load and generating assets of UE.
AMT– Alternative minimum tax.
ARO– Asset retirement obligations.
ATX – Ameren Transmission Company, an Ameren Corporation subsidiary dedicated to electric transmission infrastructure investment.
ATXI – Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engaged in the construction and operation of electric transmission assets in Illinois.
Baseload–The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Btu– British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
CAIR – Clean Air Interstate Rule.
Capacity factor– A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.
CATR – Clean Air Transport Rule.
CILCO– Central Illinois Light Company, a CILCORPformer Ameren Corporation subsidiary that operatesoperated a rate-regulated electric transmission and distribution business, a merchant electric generation business through AERG, and a rate-regulatednaturalrate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO.before the AIC Merger. CILCO ownsowned all of the common stock of AERG.AERG and included AERG within its consolidated financial statements. Immediately after the AIC Merger, AIC distributed the common stock of AERG to Ameren Corporation. AERG is treated as a discontinued operation within AIC’s financial statements.
CILCORP– CILCORP Inc., ana former Ameren Corporation subsidiary that operatesoperated as a holding company for CILCO and its merchant generation subsidiary. On March 4, 2010, CILCORP ceased filing periodicmerged with and current reports with the SEC under the Exchange Act as a result of the covenant defeasance of its remaining outstanding senior bonds.into Ameren.
CIPS– Central Illinois Public Service Company, an Ameren Corporation subsidiary, renamed Ameren Illinois Company at the effective date of the AIC Merger, that operates a rate-regulated electric and natural gas transmission and distribution business, all in Illinois as AmerenCIPS.
CIPSCO– CIPSCO Inc., the former parent of CIPS.Illinois.
CO2–Carbon dioxide.
COLA–Combined nuclear plant construction and operating license application.
Cooling degree-days– The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is useful for estimating electricity demand by residential and commercial customers for summer cooling.
CT– Combustion turbine electric generation equipment used primarily for peaking capacity.
Development Company– Ameren Energy Development Company, which was an Ameren Energya Resources Company subsidiary and parent of Genco, Marketing Company, AFS, and Medina Valley. It was eliminated in an internal reorganization in February 2008.
DOE– Department of Energy, a U.S. government agency.
DRPlus– Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Dth (dekatherm)– One million Btus of natural gas.
EEI– Electric Energy, Inc., an 80%-owned Ameren CorporationGenco subsidiary that operates merchant electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior toBefore February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest were transferred to Resources Company. The remaining 20% is owned by Kentucky Utilities Company, a nonaffiliated entity. Effective January 1, 2010, in an internal reorganization, Resources Company contributed its 80% ownership interest in EEI to its subsidiary, Genco. The remaining 20% ownership interest is owned by Kentucky Utilities Company, a nonaffiliated entity.
EPA– Environmental Protection Agency, a U.S. government agency.
Equivalent availability factor– A measure that indicates the percentage of time an electric power generating unit was available for service during a period.
ERISA– Employee Retirement Income Security Act of 1974, as amended.
ESP – Early Site Permit.
Exchange Act– Securities Exchange Act of 1934, as amended.
FAC– A fuel and purchased power cost recovery mechanism that allows UE to recover, through customer rates, 95% of changes in fuel (coal, coal transportation, natural gas for generation, and nuclear) and purchased
power costs, net of off-system revenues, including MISO costs and revenues, greater or less than the amount set in base rates, without a traditional rate proceeding.
FASB– Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.
FERC– The Federal Energy Regulatory Commission, a U.S. government agency.
Fitch– Fitch Ratings, a credit rating agency.
FTRs– Financial transmission rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.
Fuelco– Fuelco LLC, a limited-liabilitylimited liability company that provides nuclear fuel management and services to its members. The members are UE, Luminant, and Pacific Gas and Electric Company.
GAAP– Generally accepted accounting principles in the United States of America.
Genco– Ameren Energy Generating Company, a Resources Company subsidiary that operates a merchant electric generation business in Illinois and Missouri.Missouri and holds an 80% ownership interest in EEI.
Gigawatthour– One thousand megawatthours.
Heating degree-days– The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating forby residential and commercial customers.
IBEW– International Brotherhood of Electrical Workers, a labor union.
ICC– Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including the rate-regulated operations of CIPS, CILCOATXI and IP.AIC.
Illinois Customer Choice Law– Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring andrestructuring; it was designed to introduce competition into the retail supply of electric energy in Illinois.
Illinois EPA– Illinois Environmental Protection Agency, a state government agency.
Illinois Regulated– A financial reporting segment consisting of the regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO, IP and AITC.
IP– Illinois Power Company, ana former Ameren Corporation subsidiary. IP operatessubsidiary that operated a rate-regulated electric and natural gas transmission and distribution business, all in Illinois, as AmerenIP.before the AIC Merger.
IP LLC– Illinois Power Securitization Limited Liability Company, which was a special-purpose Delaware limited-liability company. It was dissolved in February 2009 because the remaining TFNs, with respect to which this entity was created, were redeemed by IP in September 2008.
IP SPT– Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law. It was dissolved in February 2009 because the remaining TFNs were redeemed by IP in September 2008.
IPA– Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and nonresidential customers.
ISRS– Infrastructure system replacement surcharge. Asurcharge, which is a cost recovery mechanism in Missouri that allows UE to recover gas infrastructure replacement costs from utility customers without filing a traditional rate case.
IUOE– International Union of Operating Engineers, a labor union.
Kilowatthour– A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.
LIUNA – Laborers’ International Union of North America, a labor union.
MACT–Maximum Achievable Control Technology.
Marketing Company– Ameren Energy Marketing Company, a Resources Company subsidiary that markets power for Genco, AERG, EEI and Medina Valley.
Medina Valley– AmerenEnergy Medina Valley Cogen LLC, a Resources Company subsidiary, which owns a 40-megawatt gas-fired electric generation plant.
Megawatthour– One thousand kilowatthours.
Merchant Generation– A financial reporting segment consisting primarily of the operations or activities of Resources Company, including Genco, the CILCORP parent company,Genco’s 80% ownership interest in EEI, AERG, EEI, Medina Valley and Marketing Company.
MGP– Manufactured gas plant.
MISO– Midwest Independent Transmission System Operator, Inc., an RTO.
MISO Energy and Operating Reserves Market– A market that uses market-based pricing, incorporatingwhich takes into account transmission congestion and line losses, to compensate market participants for power and ancillary services.
Missouri Environmental Authority– Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.
Missouri Regulated– A financial reporting segment consisting of UE’s rate-regulated businesses.
Mmbtu– One million Btus.
Money pool– Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools maintained for rate-regulated and non-rate-regulated business are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.
Moody’s– Moody’s Investors Service Inc., a credit rating agency.
MoPSC– Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including the rate-regulated operations of UE.
MPS– Multi-Pollutant Standard, an agreement, as amended, reached in 2006 among Genco, CILCO (AERG),AERG, EEI and the Illinois EPA, which was codified in Illinois environmental regulations.
MTM – Mark-to-market.
MW–Megawatt.
Native load–Wholesale customers and end-use retail customers, whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.
NCF&O– National Congress of Firemen and Oilers, a labor union.
NOx – Nitrogen oxide.
Noranda – Noranda Aluminum, Inc.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a U.S. government agency.
NSPS – New Source Performance Standards, a provision under the Clean Air Act.
NSR – New Source Review provisions of the Clean Air Act.Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.
NYMEX – New York Mercantile Exchange.
NYSE– New York Stock Exchange, Inc.
OATT–Open Access Transmission Tariff.
OCI – Other comprehensive income (loss) as defined by GAAP.
Off-system revenues – Revenues from other than native load sales.
OTC – Over-the-counter.
PGA – Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.
PJM – PJM Interconnection LLC.
PUHCA 2005 – The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.
Regulatory lag– AdjustmentsThe effect of adjustments to retail electric and natural gas rates arebeing based on historic cost and revenue levels. Rate increase requests can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue increases authorized by regulators will lag behind changing costs and revenue.revenue when based on historical periods.
Resources Company – Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, Genco’s 80% ownership interest in EEI, AERG, Marketing Company EEI, AFS, and Medina Valley. It is the successorOn October 1, 2010, AERG stock was distributed to Ameren, Energywhich then contributed it to Resources Company, which was eliminated in an internal reorganization in February 2008.thereby making AERG a subsidiary of Resources Company.
RFP – Request for proposal.
RTO – Regional Transmission Organization.
S&P – Standard & Poor’s Ratings Services, a credit rating agency that is a division of The McGraw-Hill Companies, Inc.
SEC – Securities and Exchange Commission, a U.S. government agency.
SERC – SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.
SO2 – Sulfur dioxide.
TFNUA – Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP designatedUnited Association of Plumbers and Pipefitters, a portion of cash received from customer billings to pay the TFNs. The designated funds received by IP were remitted to IP SPT. The designated funds were restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. After the implementation of authoritative accounting guidance on the consolidation of variable-interest entities, IP did not consolidate IP SPT. In September 2008, IP redeemed the remaining TFNs.labor union.
TVA – Tennessee Valley Authority, a public power authority.
UE – Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri, doing business as AmerenUE.Ameren Missouri.
VIE – Variable-interest entity.
Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve
risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
| Ÿ | regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of the pending UE |
| Ÿ | the effects of, or changes to, the Illinois power procurement process; |
| Ÿ | changes in laws and other governmental actions, including monetary, fiscal, and |
| Ÿ | changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers, including UE and Marketing Company; |
| Ÿ | the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels, and the implementation of deregulation, such as occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006; |
| Ÿ | the effects on demand for our services resulting from technological advances, including advances in energy efficiency and distributed generation sources, which generate electricity at the site of consumption; |
| Ÿ | increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely fashion in light of regulatory lag; |
| Ÿ | the effects of participation in, |
| Ÿ | the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural |
gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities; |
| Ÿ | the effectiveness of our risk management strategies and the use of financial and derivative instruments; |
| Ÿ | the level and volatility of future prices for power in the |
| Ÿ | business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products; |
| Ÿ | disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly; |
| Ÿ | our assessment of our liquidity; |
| Ÿ | the impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance; |
| Ÿ | actions of credit rating agencies and the effects of such actions; |
| Ÿ | the impact of weather conditions and other natural phenomena on us and our customers; |
| Ÿ | the impact of system outages; |
| Ÿ | generation, |
| Ÿ | the |
| Ÿ | the extent to which UE is permitted by its regulators to recover in rates (i) certain of the Taum Sauk rebuild costs not covered by insurance and |
| Ÿ | impairments of long-lived assets, intangible assets, or goodwill; |
| Ÿ | operation of UE’s nuclear power facility, including planned and unplanned outages, and decommissioning costs; |
| Ÿ | the effects of strategic initiatives, including mergers, acquisitions and divestitures; |
| Ÿ | the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements, including those related to greenhouse gases, other emissions, and energy efficiency, will be enacted over time, which could limit or terminate the operation of certain of our generating units, increase our costs, result in an impairment of our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect; |
| Ÿ | the impact of complying with renewable energy portfolio requirements in Missouri; |
| Ÿ | labor disputes, work force reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets; |
| Ÿ | the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit facilities, and financial instruments; |
| Ÿ | the cost and availability of transmission capacity for the energy generated by the Ameren Companies’ facilities or required to satisfy energy sales made by the Ameren Companies; |
| Ÿ | legal and administrative proceedings; and |
| Ÿ | acts of sabotage, war, terrorism, or intentionally disruptive acts. |
Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.
| ITEM 1. | BUSINESS. |
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was formed in 1997 by the merger of UE and CIPSCO.CIPSCO Inc. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, CIPS, Genco, CILCOAIC and IP.Genco. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Below is a summary description of UE, AIC and Genco. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
| Ÿ | UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. |
| Ÿ | AIC operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. |
| Ÿ | Genco operates a merchant electric generation business in Illinois and Missouri. |
As part of an internal reorganization, Resources Company transferred its 80% ownership interest in EEI to Genco, through a capital contribution, on January 1, 2010.
On October 1, 2010, after receiving all necessary approvals, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren (the AERG distribution) and the subsequent contribution by Ameren of the AERG stock to Resources Company. For additional information regarding the corporate reorganization, see Note 16 – Corporate Reorganization and Discontinued Operations under Part II, Item 8, of this report.
The following table presents our total employees at December 31, 2009:2010:
Ameren(a) | 9,474 | |||
UE | 4,372 | |||
| 2,752 | |||
Genco | ||||
| ||||
|
| (a) | Total for Ameren includes Ameren registrant and nonregistrant subsidiaries. |
As of January 1, 2010,2011, the IBEW, the IUOE, the LIUNA, the NCF&O and the Laborers and Gas FittersUA labor unions collectively represented about 59% of Ameren’s total employees. They represented 64% of the employees at UE, 83%67% at CIPS, 72%AIC, and 67% at Genco, 38% at CILCO, and 90% at IP.Genco. All collective bargaining agreements that expired in 2009 have been2010 were renegotiated and ratified. Most of theThe collective bargaining agreements have three- to five-year terms, and expire between 2011 and 2013.
In 2009, Several collective bargaining agreements between Ameren initiated a voluntary separation program that provided eligible managementsubsidiaries and the IBEW, IUOE, the LIUNA, NCF&O and the UA labor unions, covering approximately 925 employees, the opportunity to voluntarily terminate their employment and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management employees at Ameren’s subsidiaries, including UE, CIPS, Genco, CILCO and IP. Additionally, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. In the third quarter of 2009, Genco announced operational changes and staff reductions at three of its generating facilities. The affected three plants were the Meredosia, Grand Tower, and Hutsonville plants. In addition, Genco retired two of the four units at its Meredosia plant. The Grand Tower plant will be operated seasonally from May through September; a very limited staff will maintain the plant during the other months. The number of positions eliminated as a result of these separation programs and operational changes was approximately 300.expire throughout 2011.
For additional information about the development of our businesses, our business operations, and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
Ameren has three reportable segments: Ameren Missouri, Regulated,Ameren Illinois, Regulated, and Merchant Generation. CILCO has two reportable segments: Illinois Regulated and Merchant Generation. See Note 18 – Segment Information under Part II, Item 8, of this report for additional information on reporting segments.
Rates
The rates that UE CIPS, CILCO and IPAIC are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to UE CIPS, CILCO and IPAIC customers are determined, in large part, by governmental entities, including the MoPSC, the ICC, and FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the prudency of expenditures, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views, and are largely outside of our control.views. Decisions made by these governmental entities regarding rates are largely outside of UE’s and AIC’s control. These decisions, as well as the regulatory lag involved in filing and getting new rates approved, could have a material impact on the results of operations, financial position, and liquidity of Ameren, UE CIPS, CILCO and IP.AIC. Rate orders are also subject to appeal and stay requests, which create additional uncertainty as to the rates UE and AIC are ultimately allowed to charge for their services.
The ICC regulates rates and other matters for CIPS, CILCOAIC and IP.AITX. The MoPSC regulates rates and other matters
for UE. The FERC regulates UE, CIPS,AIC, Genco, CILCO and IPAITX as to their ability to charge market-based rates for the sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.
About 38%46% of Ameren’s electric and 14%15% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2009.2010. About 39%31% of Ameren’s electric and 86%85% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2009.2010. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.
Ameren Missouri Regulated(UE)
Electric
About 83%98% of UE’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2009. Effective2010. Beginning March 1, 2009, as a result of a MoPSC electric rate order issued in January 2009, UE’s retail electric rates include a FAC forthat allows billing adjustments for changes in prudently incurred fuel and purchased power costs. On May 28, 2010, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $230 million. This order allowed UE to continue to use the regulatory tracking mechanisms for vegetation management and infrastructure costs and pension and postretirement benefit costs. See below for cost recovery of energy efficiency programs. UE’s 2009 and 2010 electric rate orders are still subject to court appeals.
On September 3, 2010, UE filed a request with the MoPSC to increase its annual revenues for electric service by approximately $263 million. Approximately $110 million of the request relates to recovery of the cost of installing and operating two scrubbers at UE’s Sioux plant. Also included in this requested increase is a $73 million anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. Absent initiation of this general rate proceeding, 95% of this amount would have been reflected in rate adjustments implemented under UE’s FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the increase request. As a part of its filing, UE also requested that the MoPSC approve the implementation of an infrastructure investment tracking mechanism as well as enhanced energy efficiency cost recovery. UE also requested continued use of its existing FAC, vegetation management and infrastructure cost tracker, and the regulatory tracking mechanism for pension and postretirement benefit costs the MoPSC previously authorized in earlier electric rate orders. In February 2011, the MoPSC staff responded to the UE request for an electric service rate increase. The MoPSC staff recommended an increase to UE’s annual revenues of between $45 million and $99 million based on a return on equity of 8.25% to
9.25%. Included in this recommendation was approximately $50 million of increases in normalized net fuel costs and $32 million of asset disallowances relating to the Sioux plant scrubbers. Other parties also made recommendations through testimony filed in this case.
FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files a regional transmission tariff rates for approval by FERC. All memberstransmission service within that RTO areis then subjected to those rates.that tariff. As a member of MISO, UE’s transmission rate is calculated in accordance with MISO’sthe MISO tariff rate formula. The transmission rate is updated in June of each year based on FERC filings.UE’s filing with FERC. This rate is charged directly to wholesale customers. This rate is not directly charged to Missouri retail customers because in Missouri the MoPSC includes transmission-related costs in setting bundled retail rates in Missouri.rates.
Natural Gas
All of UE’s natural gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2009.2010. In January 2011, the MoPSC approved a stipulation and agreement that allows UE to increase annual natural gas revenues by $9 million resolving a June 2010 rate increase request. The new rates became effective on February 20, 2011. As part of the stipulation and agreement, UE agreed not to file a separate natural gas rate increase request before December 31, 2012; however, UE can file a combined natural gas and electric rate case before that date. Further, this agreement does not prevent UE from filing to recover infrastructure replacement costs through an ISRS during this moratorium. The return on equity to be used by UE for purposes of an ISRS tariff filing is 10%.
If certain criteria are met, UE’s natural gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer. The ISRS also permits prudently incurred natural gas infrastructure replacement costs to be passed directly to the consumer.
As part of a 2007 stipulation and agreement approved by the MoPSC that authorized an increase in 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. This agreement did not prevent UE from filing to recover gas infrastructure replacement costs through an ISRS during this three-year rate moratorium. Since April 1, 2007, the MoPSC has approved three separate requests from UE for an ISRS to recover annual revenues of $3 million, in the aggregate. These surcharges remain in place until new rates go into effect.
For additional information on Missouri rate matters, including UE’s 2011 natural gas rate order, UE’s pending electric rate case, and UE’s 2009 and 2010 electric rate order,orders and related court appeals and regulatory proceedings, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
Ameren Illinois Regulated(AIC)
The following table presents the approximate percentageAll of AIC’s electric and natural gas operating revenues were subject to regulation by the ICC for each of the Illinois Regulated companies foror FERC in the year ended December 31, 2009:2010.
| Electric | Natural Gas | |||||
CIPS | 100 | % | 100 | % | ||
CILCO(a) | 41 | 100 | ||||
IP | 100 | 100 |
Under the Illinois Customer Choice Law, all electric customers in Illinois may choose their own electric energy provider. However, the Ameren Illinois Utilities areAIC is required to serve as the provider of last resort (POLR) for electric customers within theirits territory who have not chosen an alternative retail electric supplier. The Ameren Illinois Utilities’AIC’s obligation to provide full requirements electric service, including power supply, as a POLR varies by customer size. The Ameren Illinois Utilities areAIC is not required to offer fixed pricedfixed-priced electric service to many of their largest customers with electric demands of 400 kilowatts or greater, as the market for service to this group of customers has been declared competitive. The powerPower procurement costs incurred by the Ameren Illinois UtilitiesAIC are passed directly to theirits customers through a cost recovery mechanism.
Environmental adjustment rate riders authorized byIn April 2010, the ICC permitissued a rate order for AIC, which was amended in May 2010, that approved a net increase in annual revenues for electric delivery service of $35 million and a net decrease in annual revenues for natural gas delivery service of $20 million. The rate changes became effective in May 2010. The ICC order confirmed the previously approved 80% allocation of fixed non-volumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of prudently incurred MGP remediationfixed non-volumetric electric residential and litigationcommercial customer charges. The percentage of costs to be recovered through fixed non-volumetric electric residential and commercial customer and meter charges increased from CIPS’, CILCO’s27% to 40%. AIC and IP’s Illinoiscertain intervenors were granted a rehearing with the ICC. In November 2010, the ICC approved an order on the rehearing issues, which authorized an increase in annual revenues of $25 million, in addition to the net $15 million increase authorized in the ICC’s May 2010 amended rate order. The overall annual delivery service revenue increase as a result of these orders is $40 million. The rate changes relating to the rehearing issues became effective on November 19, 2010.
AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric and natural gas utility customers.delivery service by $60 million and $51 million, respectively. In addition, IPan attempt to limit regulatory lag, AIC is using a future test year, 2012, in this rate request. Additionally, AIC is requesting a rider mechanism for its pension costs and the continuation of existing riders described below, including cost recovery mechanisms for energy efficiency costs. The requested pension cost rider mechanism would allow AIC to recover from or refund to customers any difference between pension expense incurred and the amount allowed in rates annually without a formal regulatory proceeding.
AIC has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates is recoverable by IPare recovered from a trust fund established bywhen Ameren acquired IP. At December 31, 2009,2010, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, IPAIC will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recoverablerecovered through charges assessed to customers under
the tariff rider. Following the AIC Merger, this rider is only applicable for claims that occurred within IP’s historical service territory. Similarly, the rider will seek recovery only from customers within IP’s historical service territory.
In 2009, a new law became effective in Illinois that allows electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their base rates. In February 2010, the ICC approved the Ameren Illinois Utilities’AIC’s electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in base rates.
If certain criteria are met, CIPS’, CILCO’s and IP’sAIC’s natural gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.
FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files a regional transmission tariff rates for approval by FERC. All memberstransmission service within that RTO areis then subjected to those rates.that tariff. As membersa member of MISO, the Ameren Illinois Utilities’AIC’s transmission rate is calculated in accordance with MISO’sthe MISO tariff rate formula. The transmission rate is updated in June of each year based on AIC’s filings with FERC filings. This rate is charged directly to wholesale customers and alternative retail electric suppliers. For retail customers who have not chosen an alternative retail electric supplier, the transmission rate is collected through a rider mechanism.
For additional information on Illinois rate matters, including theAIC’s currently pending electric and natural gas rate cases, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
Merchant Generation
Merchant Generation revenues are determined by market conditions and contractual arrangements. We expect the Merchant Generation fleet of assets to have 6,3706,263 megawatts of capacity available for the 20102011 peak summer electrical demand. As discussed below, Genco AERG and EEIAERG sell all of their power and capacity to Marketing Company through power supply agreements. Marketing Company attempts to optimize the value of those assets and mitigate risks through a variety of hedging techniques, including wholesale sales of capacity and energy, retail sales in the non-rate-regulated Illinois market, spot market sales primarily in MISO and PJM, and financial transactions. Marketing Company enters into long-term and short-term contracts. Marketing Company’s counterparties include cooperatives, municipalities, commercial and industrial customers, power marketers, MISO, PJM and investor-owned utilities, such as the Ameren Illinois Utilities.AIC. For additional information on Marketing Company’s hedging activities and Marketing Company’s sales to the Ameren Illinois Utilities,AIC, see Outlook in Management’s
Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 7 – Derivative Financial Instruments and Note 14 – Related Party Transactions under Part II, Item 8, of this report.
General Regulatory Matters
UE CIPS, CILCO and IPAIC must receive FERC approval to issue short-term debt securities and to conduct certain acquisitions, mergers and consolidations involving electric utility holding companies having a value in excess of $10 million. In addition, these Ameren utilities must receive authorization from the applicable state public utility regulatory
agency to issue stock and long-term debt securities (with maturities of more than 12 months) and to conduct mergers, affiliate transactions, and various other activities. Genco AERG and EEIAERG are subject to FERC’s jurisdiction when they issue any securities.
Under PUHCA 2005, FERC and any state public utility regulatory agencies may access books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren,the MoPSC and the ICC or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.
Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on June 11, 2024. UE intends to submit a license extension application with the NRC to extend the plant’s operating license to 2044. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for UE’s Osage hydroelectric plant expires on March 30, 2047, and the license for UE’s Taum Sauk plant expires on June 30, 2010.2047. In June 2008, UE filed ana relicensing application with FERC to relicenseoperate its Taum Sauk plantpumped-storage hydroelectric facility for another 40 years. Approval and relicensure are expected in 2012. Operations are permittedThe existing FERC license expired on June 30, 2010. On July 2, 2010, UE received a license extension that allows Taum Sauk to continue underoperations until FERC issues a new license. UE conducted studies using current field data and submitted the current license whilestudy results to multiple state and federal agencies in February 2011. UE anticipates filing the application for relicensingstudy results with FERC in the spring of 2011. A FERC order is pending. Theexpected after a review of the study results is completed; however, we cannot predict the ultimate outcome of the order. Taum Sauk returned to service in April 2010 after the plant is currently out of service. It is beingwas rebuilt due to a majorfollowing the breach of theits upper reservoir in December 2005. UE expects the Taum Sauk plant to become operational in the second quarter of 2010. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.
For additional information on regulatory matters, see Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report, which include a discussion about the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.
Environmental Matters
Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These environmental statutes and regulations include requirements for identification, generation, storage, handling, transportation, disposal, recordkeeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials,materials; safety and health standards,standards; and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants and the management of waste and byproduct materials. Failure to comply with those statutes or regulations could have material adverse effects on us. We could be subject to criminal or civil penalties by regulatory
agencies. We agencies or we could be ordered to make payment to private parties by the courts.courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.
In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco, that operate coal-fired power plants. Significant new rules already proposed or promulgated within the past year include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NOx emissions, lowering the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO2 and NOx emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act that could require significant capital expenditures, such as new water intake structures or cooling towers at our power plants, and a MACT standard for the control of hazardous air pollutants, such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effect of the new and proposed environmental regulations may result in significant capital expenditures or increased operating costs over the next five to eight years for Ameren, UE and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our generating facilities, which could have an adverse effect on our results of operations, financial position, and liquidity.
For additional discussion of environmental matters, including NOx, SO2, and mercury emission reduction requirements, global climate change, remediation efforts, and UE’s receipt in January 2010 of a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and New Source Performance Standards (NSPS) provisions,Title V Programs, and the complaint filed by the EPA
against UE in January 2011 alleging violation of the Clean Air Act and Missouri law in performing projects at UE’s Rush Island coal-fired generating facility, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
TRANSMISSION AND SUPPLY FOROF ELECTRIC POWER
Ameren owns an integrated transmission system that comprises the transmission assets of UE, CIPS, CILCO, IPAIC and AITC.ATXI. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes CIPS, CILCO, IP, AITC,AIC, ATXI, Genco, excluding EEI and Genco’s Elgin CT facility, and AERG). During 2009,2010, the peak demand in AMMO was 8,0818,797 MW and in AMIL was 8,6079,166 MW. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
UE, CIPS, CILCOAIC and IPATXI are transmission-owning members of MISO. Transmission service on the UE, CIPS, CILCO and IPAmeren transmission systems is provided pursuant to the terms of the MISO OATT on file with FERC. EEI operates its own balancing authority area and its own transmission facilities in southern Illinois. The EEI transmission system is directly connected to MISO, the Tennessee Valley Authority, and TVA.Louisville Gas and Electric Company. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.
On August 2, 2010, Ameren announced the formation of ATX. ATX intends to build projects initially within Illinois and Missouri, with the potential for expanding to other areas in the future. ATX’s initial investments are expected to be the Grand Rivers projects, the first of which involves building a 345 kilovolt line across the state of Illinois, from the Missouri border to the Indiana border. The investment could total more than $1.3 billion through 2021, with a potential investment of $265 million from 2011 to 2015.
The Ameren Companies and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in much of the southeastern United States,many states, including all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa, and Texas. As a result of the Energy Policy Act of 2005, owners and operators of the bulk electric power system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and its regional entities, such as SERC, and enforced by FERC. The Ameren Companies must follow these standards, which are in place to require that proper functions are performed to ensure the reliability of the bulk electric power system.
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
Ameren Missouri Regulated(UE)
UE’s electric supply is obtained primarily from its own generation. Factors that could cause UE to purchase power
include, among other things, absence of sufficient owned generation, plant outages, the fulfillment of renewable energy requirements, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it.
UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s
integrated resource plan filed with the MoPSC in February 20082011 included the expectation that new baseload generation capacity would be required in the 2018 tobetween 2020 time frame. Due toand 2030. Because of the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studyingcontinues to study future plant alternatives, includingas well as energy efficiency programs that could help defer new plant construction. UE’s 2008 integrated resource plan included proposalsTo prepare for the long-term need for baseload capacity, and to pursueprepare for potentially more stringent environmental regulation of coal-fired power plants, which could lead to the retirement of current baseload assets, UE is taking steps to preserve options to meet future demand. These steps include seeking improvements in regulatory treatment of energy efficiency programs, expandinvestments, evaluating potential sites for natural gas-fired generation, and pursuing an ESP for an additional unit at its existing nuclear plant site, subject to passage of state legislation that would ensure rate recovery of the roleESP costs once the ESP has been approved by the NRC. In December 2010 and January 2011, the Missouri Energy Partnership Act was separately introduced in both the Missouri Senate and House of renewable energy sourcesRepresentatives. The purpose of this legislation is to maintain an option for nuclear power in UE’s overall generation mix, increase operational efficiency at existing power plants,the state of Missouri, recover the costs of the ESP for a period up to 20 years, and possibly retire some generating units that are older and less efficient. UE will file a new integrated resource plan withprovide appropriate consumer protections. This legislation remains pending as of the MoPSC in 2011.date of this report.
See also Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
Ameren Illinois Regulated(AIC)
As of January 1, 2007, CIPS, CILCO and IP wereAIC is required to obtain from market sources all electric supply requirements for customers, except those customers in markets declared competitive, who diddo not purchase electric supply from third-party suppliers. The power procurement costs incurred by CIPS, CILCO and IPAIC are passed directly to theirits customers through a cost recovery mechanism.
In September 2006, a reverse power procurement auction was held, as a result of which CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including Marketing Company. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve the electric load needs of fixed-price residential and small commercial customers (with less than one MW of demand) at an all-inclusive fixed price. These contracts commenced on January 1, 2007, with one-third of the supply contracts expiring in May 2008, 2009 and 2010.
As part of the 2007 Illinois Electric Settlement Agreement, the reverse power procurement auction process was discontinued and a new competitive power procurement process led by the IPA was implemented beginning in 2009 was established. In January 2009,2009. The IPA administers a RFP process that procures AIC’s expected supply obligation. Since the start of this process, the ICC has approved the outcomes of multiple electric power procurement plan filed by the IPARFPs for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy, swaps, and renewable energy credits through an RFP process on behalf of the Ameren
Illinois Utilities in the second quarter of 2009. In August 2009, the IPA submitted its plan to the ICC for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The plan was modified and approved by the ICC in December 2009. The IPA will procure energy swaps, capacity and renewable energy credits and long-term renewable supply.covering different time periods.
A portion of the electric power supply required for the Ameren Illinois UtilitiesAIC to satisfy theirits distribution customers’ requirements is purchased in the RFP process administered by the IPA from Marketing Company on behalf of Genco, AERG and EEI. AlsoIn addition, as part of the 2007 Illinois Electric Settlement Agreement, the Ameren Illinois UtilitiesAIC entered into financial contracts with Marketing Company (for the benefit of Genco and AERG) to lock in energy prices for 400 to 1,000 megawatts annually of theirits round-the-clock power requirements during the period June 1, 2008, through December 31, 2012, at relevantthe market prices relevant at that time. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy.
See Note 2 – Rate and Regulatory Matters, Note 14 – Related Party Transactions and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for additional information on power procurement in Illinois.
Merchant Generation
Genco and AERG have entered into power supply agreements with Marketing Company whereby Genco and AERG sell, and Marketing Company purchases, all the capacity available from Genco’s and AERG’s generation fleets and the associated energy. These power supply agreements continue through December 31, 2022, and from year to year thereafter unless either party elects to
terminate the agreement by providing the other party with no less than six months advance written notice. EEI and Marketing Company have entered into a power supply agreement for EEI to sell all of its capacity and energy to Marketing Company. This agreement expires on DecemberMay 31, 2015.2016. All of Genco’s, AERG’s and EEI’s generating facilities compete for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 14 – Related Party Transactions under Part II, Item 8, of this report for additional information.
FactorsOn September 28, 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could cause Marketing Companylead to purchase powerrepowering a unit at Genco’s Meredosia plant. This would create the world’s first full-scale, oxy-combustion coal-fired plant designed for permanent CO2 capture and storage. Ameren and two independent companies will assess the Merchant Generation business segment include, among other things, absence of sufficient owned generation, plant outages,project in phases to validate the fulfillment of renewable energy requirements,project’s scope, cost, schedule and commercial viability. If the failure of suppliers to meet their power supply obligations, extreme weather conditions,first phases are successful and the availability of power at a cost lower thanproject has received regulatory approval, Ameren and its partners will initiate the cost of generating it.construction necessary to repower the plant.
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2010, 2009 2008 and 2007:2008:
| Coal | Nuclear | Natural Gas | Hydroelectric | Oil | Coal | Nuclear | Natural Gas | Hydroelectric | Oil | ||||||||||||||||||||||||||
Ameren:(a) | |||||||||||||||||||||||||||||||||||
2010 | 85 | % | 12 | % | 1 | % | 2 | % | (b | )% | |||||||||||||||||||||||||
2009 | 83 | % | 13 | % | 1 | % | 3 | % | (b | )% | 83 | 13 | 1 | 3 | (b | ) | |||||||||||||||||||
2008 | 85 | 12 | 1 | 2 | (b | ) | 85 | 12 | 1 | 2 | (b | ) | |||||||||||||||||||||||
2007 | 84 | 12 | 2 | 2 | (b | ) | |||||||||||||||||||||||||||||
Missouri Regulated: | |||||||||||||||||||||||||||||||||||
UE: | |||||||||||||||||||||||||||||||||||
Ameren Missouri (UE): | |||||||||||||||||||||||||||||||||||
2010 | 77 | % | 19 | % | 1 | % | 3 | % | - | % | |||||||||||||||||||||||||
2009 | 75 | % | 21 | % | (b | )% | 4 | % | - | % | 75 | 21 | (b | ) | 4 | - | |||||||||||||||||||
2008 | 77 | 19 | 1 | 3 | (b | ) | 77 | 19 | 1 | 3 | (b | ) | |||||||||||||||||||||||
2007 | 76 | 19 | 2 | 3 | (b | ) | |||||||||||||||||||||||||||||
Merchant Generation: | |||||||||||||||||||||||||||||||||||
Genco: | |||||||||||||||||||||||||||||||||||
2010 | 98 | % | - | % | 2 | % | - | % | (b | )% | |||||||||||||||||||||||||
2009 | 99 | % | - | % | 1 | % | - | % | (b | )% | 99 | - | 1 | - | (b | ) | |||||||||||||||||||
2008 | 99 | - | 1 | - | (b | ) | 99 | - | 1 | - | (b | ) | |||||||||||||||||||||||
2007 | 96 | - | 4 | - | (b | ) | |||||||||||||||||||||||||||||
CILCO (AERG): | |||||||||||||||||||||||||||||||||||
Genco: | |||||||||||||||||||||||||||||||||||
2010 | 99 | % | - | % | 1 | % | - | % | (b | )% | |||||||||||||||||||||||||
2009 | 100 | % | - | % | (b | )% | - | % | - | % | 100 | - | (b | ) | - | (b | ) | ||||||||||||||||||
2008 | 99 | - | 1 | - | - | 99 | - | 1 | - | (b | ) | ||||||||||||||||||||||||
2007 | 99 | - | 1 | - | (b | ) | |||||||||||||||||||||||||||||
EEI: | |||||||||||||||||||||||||||||||||||
2009 | 100 | % | - | % | - | % | - | % | - | % | |||||||||||||||||||||||||
2008 | 100 | - | - | - | - | ||||||||||||||||||||||||||||||
2007 | 100 | - | - | - | - | ||||||||||||||||||||||||||||||
Total Merchant Generation: | |||||||||||||||||||||||||||||||||||
2009 | 99 | % | - | % | 1 | % | - | % | (b | )% | |||||||||||||||||||||||||
2008 | 99 | - | 1 | - | (b | ) | |||||||||||||||||||||||||||||
2007 | 98 | - | 2 | - | (b | ) | |||||||||||||||||||||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | Less than 1% of total fuel supply. |
The following table presents the cost of fuels for electric generation for the years ended December 31, 2010, 2009 2008 and 2007:2008:
| Cost of Fuels(Dollars per million Btus) | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Ameren: | ||||||||||||||||||||||
Coal(a) | $ | 1.654 | $ | 1.572 | (b) | $ | 1.399 | $ | 1.848 | $ | 1.654 | $ | 1.572 | (b) | ||||||||
Nuclear | 0.620 | 0.493 | 0.490 | 0.701 | 0.620 | 0.493 | ||||||||||||||||
Natural gas(c) | 8.685 | 10.503 | 7.939 | 6.539 | 8.685 | 10.503 | ||||||||||||||||
Weighted average – all fuels(d) | $ | 1.591 | $ | 1.573 | (b) | $ | 1.462 | $ | 1.803 | $ | 1.591 | $ | 1.573 | (b) | ||||||||
Missouri Regulated: | ||||||||||||||||||||||
UE: | ||||||||||||||||||||||
Ameren Missouri (UE): | ||||||||||||||||||||||
Coal(a) | $ | 1.534 | $ | 1.426 | $ | 1.284 | $ | 1.675 | $ | 1.534 | $ | 1.426 | ||||||||||
Nuclear | 0.620 | 0.493 | 0.490 | 0.701 | 0.620 | 0.493 | ||||||||||||||||
Natural gas(c) | 8.544 | 10.264 | 7.580 | 6.199 | 8.544 | 10.264 | ||||||||||||||||
Weighted average – all fuels(d) | $ | 1.386 | $ | 1.340 | $ | 1.271 | $ | 1.563 | $ | 1.386 | $ | 1.340 | ||||||||||
Merchant Generation: | ||||||||||||||||||||||
Coal(a) | $ | 2.063 | $ | 1.813 | $ | 1.746 | (b) | |||||||||||||||
Natural gas(c) | 6.972 | 8.796 | 10.764 | |||||||||||||||||||
Weighted average – all fuels(d) | $ | 2.169 | $ | 1.934 | $ | 1.919 | (b) | |||||||||||||||
Genco: | ||||||||||||||||||||||
Coal(a) | $ | 1.877 | $ | 1.958 | (b) | $ | 1.717 | $ | 2.112 | $ | 1.869 | $ | 1.786 | |||||||||
Natural gas(c) | 13.159 | 15.857 | 8.440 | 7.881 | 13.159 | 15.857 | ||||||||||||||||
Weighted average – all fuels(d) | $ | 2.001 | $ | 2.121 | (b) | $ | 1.939 | $ | 2.206 | $ | 1.957 | $ | 1.896 | |||||||||
CILCO (AERG): | ||||||||||||||||||||||
Coal(a) | $ | 1.643 | $ | 1.598 | $ | 1.309 | ||||||||||||||||
Weighted average – all fuels(d) | $ | 1.673 | $ | 1.721 | $ | 1.450 | ||||||||||||||||
EEI: | ||||||||||||||||||||||
Coal(a) | $ | 1.855 | $ | 1.438 | $ | 1.329 | ||||||||||||||||
Total Merchant Generation: | ||||||||||||||||||||||
Coal(a) | $ | 1.813 | $ | 1.746 | (b) | $ | 1.545 | |||||||||||||||
Natural gas(c) | 8.796 | 10.764 | 8.390 | |||||||||||||||||||
Weighted average – all fuels(d) | $ | 1.934 | $ | 1.919 | (b) | $ | 1.759 | |||||||||||||||
| (a) | The fuel cost for coal represents the cost of coal, costs for transportation, which includes railroad diesel fuel |
| (b) | Excludes impact of the Genco coal supply contract settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report. |
| (c) | The fuel cost for natural gas represents the cost of natural gas and firm and variable costs for transportation, storage, balancing, and fuel losses for delivery to the plant. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the generating facilities. |
| (d) | Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal. |
Coal
Ameren, UE Genco, AERG and EEIGenco have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2019. Ameren, UE Genco, AERG and EEIGenco expect to enter into additional contracts to purchase coal from time to time. Coal supply agreements typically have an initial term of up to five years, with about 20% of the contracts expiring annually. UE has an ongoing need for coal to serve its native load customers and pursues a price hedging strategy consistent with this requirement. Merchant Generation’s forward coal requirements are dependent on the volume of power sales that have been contracted. As such, Merchant Generation strives to achieve increased margin certainty by aligning its fuel purchases with its power sales. Ameren burned 37.639 million tons (UE – 21.322 million, Genco – 7.9 million, AERG – 4.0 million, EEI – 4.413 million) of coal in 2009.2010. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.
About 96%97% of Ameren’s coal (UE – 96%97%, Genco – 99%, AERG – 89%, EEI – 100%97%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Ameren, UE Genco, AERG and EEIGenco have a policygoal to maintain coal inventory consistent with their projected usage.risk management policies. Inventory may be adjusted because of changes in burn or uncertainties of supply due to potential
potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. In the past, deliveries from the Powder River Basin have occasionally been restricted because of rail maintenance, weather, and derailments. As of December 31, 2009,2010, coal inventories for Ameren, UE Genco, AERG and EEIGenco were at targeted levels. However, in 2011 Merchant Generation is targeting a reduction in its coal inventory, relative to previous levels. Disruptions in coal deliveries could cause Ameren, UE Genco, AERG and EEIGenco 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.
Nuclear
DevelopingThe steps in the process to provide nuclear fuel generally involvesinvolve the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, the enrichment of that gas, and the fabrication of the enriched uranium hexafluoride gas into usable fuel assemblies. UE has entered into uranium, uranium conversion, enrichment, and fabrication contracts to procure the fuel supply for its Callaway nuclear plant.
Fuel assemblies for the 2010 spring2011 fall refueling at UE’s Callaway nuclear plant have been manufacturedare scheduled for manufacture and delivered
delivery to the plant.plant during May to July 2011. UE also has agreements or inventories to price-hedge approximately 89%98%, 84%, and 71% of Callaway’s 2011, 2013, and 79% of Callaway’s 20132014 refueling requirements.requirements, respectively. UE has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium and conversion requirements through at least through 2014. UE has enriched uranium inventories and enrichment supply contracts sufficient to satisfy enrichment requirements through 2012.2013. Fuel fabrication services are under contract through 2010.2014. UE expects to enter into additional contracts to purchase nuclear fuel. As a member of Fuelco, UE can join with other member companies to increase its purchasing power, enhance diversification and pursue opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in November 2008.May 2010. There is no refueling scheduled for 2012 and 2015. The nuclear fuel markets are competitive, and prices can be volatile; however, we do not anticipate any significant problems in meeting our future supply requirements.
Natural Gas Supply
To maintain gas deliveries to gas-fired generating units throughout the year, especially during the summer peak demand, Ameren’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. UE Genco and EEIGenco primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to generating units. In addition to physical transactions, Ameren uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
UE, GencoUE’s and EEI’sGenco’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. UE, Genco and EEI do this in two ways. They optimizeThis is accomplished by optimizing transportation and storage options and minimizeminimizing cost and price risk through various supply and price-hedging agreements that allow them to maintain access to multiple gas pools, supply basins, and storage.storage services. As of December 31, 2009,2010, UE had price-hedged about 89%30% and Genco had price-hedged 100%84% of theirits expected natural gas supply requirements for generation in 2010. As of December 31, 2009, EEI did not have any of its required gas supply for generation hedged for price risk.2011.
Renewable Energy
Illinois and Missouri have enacted laws requiring electric utilities to include renewable energy resources in their portfolios. Illinois requires renewable energy resources to equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers as of June 1, 2008, increasing to 10%15% by June 1, 2015, and to 25% by June 1, 2025. The Ameren Illinois Utilities haveAIC has procured renewable energy credits under the ICC-approved RFPIPA-administered procurement process to
meet thisthe renewable energy portfolio requirement through May 2010.2011. In December 2010, AIC entered into a 20-year power purchase agreement with renewable energy suppliers and will begin purchasing power under the agreement starting in June 2012, to help supplement these requirements. Approximately 50% of the 2012 renewable energy requirement will be met through this agreement. See Note 2 – Rate
and Regulatory Matters under Part II, Item 8, for additional information about the Illinois power procurement process.
In Missouri, utilities will beare required to purchase or generate electricity from renewable energy sources electricity equaling at least 2% of native load sales, by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each renewable energy portfolio requirement must be derived from solar energy. UE expects to satisfy the 2011nonsolar requirement through 2017 with existing renewable generation in its current fleet along with a 15-year, 102-MW power purchase agreement with a wind farm operator in Iowa that began generationbecame effective in 2009 and the 15-MW landfill gas project discussed below. Currently, UE expects to meet the solar energy requirement through the purchase of solar-generated renewable energy credits.
In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which wouldis expected to generate approximately 15-MW15MW of electricity by burning methane gas collected from the landfill. Construction ofSite preparation for the CTs is expected to beginbegan in 2010 and theconstruction will begin in 2011. The CTs are expected to begin generating power in 2011.2012. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas.
Energy Efficiency
Ameren’s regulated utilities have implemented energy efficiency programs to educate and help their customers become more efficient users of energy. A new law in Missouri allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The new law could, among other things, allow UE to earn a return on its energy efficiency programs equivalent to the return UE could earn with supply-side capital investments, such as new power plants. UE introduced multiple energy efficiency programs in 2009. The goal of these recently announced2009 and future UE energy efficiency programs is to reduce usage by 540-MW by 2025.2010. UE has set up a website at www.uefficiency.com in order to provide more information to its customers regarding energy efficiency.
The Ameren Illinois Utilities areAIC is participating in the Illinois Clean Energy Community Foundation, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities. In June 2008, the ICC issued an orderorders approving the Ameren Illinois Utilities’AIC’s electric energy efficiency plan as well as a cost recovery mechanismmechanisms by which the program costs will beare being recovered from electric customers. In October 2008, the ICC issued an order approving the Ameren Illinois Utilities’ natural gas energy efficiency plan as well as a cost recovery mechanism by which the program costs will be recovered from natural gas customers. The Ameren Illinois Utilities haveAIC has set up a website at www.actonenergy.com in order to provide more information to theirits customers regarding energy efficiency.
NATURAL GAS SUPPLY FOR DISTRIBUTION
UE CIPS, CILCO and IPAIC are responsible for the purchase and delivery of natural gas to their gas utility customers. UE CIPS, CILCO and IPAIC develop and manage a portfolio of gas supply resources. These include firm gas supply under term
agreements with producers, interstate and intrastate firm transportation capacity, firm storage capacity leased from interstate pipelines, and on-system storage facilities to maintain gas deliveries to customers throughout the year and especially during peak demand. UE CIPS, CILCO and IPAIC primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, the Northern Border Pipeline Company and the Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to physical transactions, financial instruments, including those entered into in the NYMEX futures market and in the OTC financial markets, are used to hedge the price paid for natural gas. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about natural gas supply contracts. Prudently incurred natural gas purchase costs are passed on to customers of UE CIPS, CILCO and IPAIC in IllinoisMissouri and MissouriIllinois under PGA clauses, subject to prudency reviewreviews by the ICCMoPSC and the MoPSC.ICC. As of December 31, 2010, UE had price-hedged 90%, and AIC had price-hedged 89%, of its expected natural gas supply requirements for distribution in 2011.
For additional information on our fuel and purchased power supply, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation and Changing Prices in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. Also see Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report, Note 1 – Summary of Significant Accounting Policies, Note 7 – Derivative Financial Instruments, Note 10 – Callaway Nuclear Plant, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies and Note 16 – Callaway Nuclear Plant under Part II, Item 8.
We are facing issues common to the electric and natural gas utility industry and the merchant electric generation industry. These issues include:
| Ÿ | continually developing and complex environmental laws, regulations and issues, including air and water-quality standards, mercury regulations, and increasingly likely greenhouse gas limitations and ash management requirements; |
| Ÿ | political and regulatory resistance to higher rates, especially in a |
| Ÿ | the potential for changes in laws, regulation, and policies at the state and federal level, including those resulting from election cycles; |
| Ÿ | access to, and uncertainty in, the capital and credit markets; |
| Ÿ | the potential for more intense competition in generation, supply and distribution, including new technologies; |
| Ÿ | pressure on customer growth and usage in light of current economic |
| Ÿ | the potential for reregulation in some states, including Illinois, which could cause electric distribution companies to build or acquire generation facilities and to purchase less power from electric generating companies such as Genco, AERG and EEI; |
| Ÿ | changes in the structure of the industry as a result of changes in federal and state laws, including the formation of merchant generating and independent transmission entities and RTOs; |
| Ÿ | increases, |
| Ÿ | the availability of fuel and increases or decreases in fuel prices; |
| Ÿ | the availability of qualified labor and material, and rising costs; |
| Ÿ | regulatory lag; |
| Ÿ |
|
|
| Ÿ | public concern about the siting of new facilities; |
| Ÿ | aging infrastructure and the need to construct new power generation, transmission and distribution facilities; |
| Ÿ | proposals for programs to encourage or mandate energy efficiency and renewable sources of power; |
| Ÿ | public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste; and |
| Ÿ | consolidation of electric and natural gas companies. |
We are monitoring these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
| Electric Operating Statistics –Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||||
Electric Sales – kilowatthours (in millions): | ||||||||||||||||||||||||
Missouri Regulated: | ||||||||||||||||||||||||
Ameren Missouri: | ||||||||||||||||||||||||
Residential | 13,413 | 13,904 | 14,258 | 14,640 | 13,413 | 13,904 | ||||||||||||||||||
Commercial | 14,510 | 14,690 | 14,766 | 15,002 | 14,510 | 14,690 | ||||||||||||||||||
Industrial | 7,037 | 9,256 | 9,675 | 8,656 | 7,037 | 9,256 | ||||||||||||||||||
Other | 1,655 | �� | 785 | 759 | 1,429 | 1,655 | 785 | |||||||||||||||||
Native load subtotal | 36,615 | 38,635 | 39,458 | 39,727 | 36,615 | 38,635 | ||||||||||||||||||
Off-system sales | 12,447 | 10,457 | 10,984 | 8,496 | 12,447 | 10,457 | ||||||||||||||||||
Subtotal | 49,062 | 49,092 | 50,442 | 48,223 | 49,062 | 49,092 | ||||||||||||||||||
Illinois Regulated: | ||||||||||||||||||||||||
Ameren Illinois: | ||||||||||||||||||||||||
Residential | ||||||||||||||||||||||||
Power supply and delivery service | 11,089 | 11,667 | 11,857 | 12,341 | 11,089 | 11,667 | ||||||||||||||||||
Commercial | ||||||||||||||||||||||||
Power supply and delivery service | 5,235 | 6,095 | 7,232 | 4,419 | 5,235 | 6,095 | ||||||||||||||||||
Delivery service only | 6,797 | 6,147 | 5,178 | 8,051 | 6,797 | 6,147 | ||||||||||||||||||
Industrial | ||||||||||||||||||||||||
Power supply and delivery service | 514 | 1,442 | 1,606 | 1,389 | 514 | 1,442 | ||||||||||||||||||
Delivery service only | 10,712 | 11,300 | 11,199 | 11,147 | 10,712 | 11,300 | ||||||||||||||||||
Other | 546 | 555 | 576 | 545 | 546 | 555 | ||||||||||||||||||
Native load subtotal | 34,893 | 37,206 | 37,648 | 37,892 | 34,893 | 37,206 | ||||||||||||||||||
Merchant Generation: | ||||||||||||||||||||||||
Nonaffiliate energy sales | 25,673 | 26,395 | 25,196 | 30,788 | 25,673 | 26,395 | ||||||||||||||||||
Affiliate native energy sales | 3,529 | 6,055 | 7,296 | 949 | 3,529 | 6,055 | ||||||||||||||||||
Subtotal | 29,202 | 32,450 | 32,492 | 31,737 | 29,202 | 32,450 | ||||||||||||||||||
Eliminate affiliate sales | (3,529 | ) | (6,055 | ) | (7,296 | ) | (949 | ) | (3,529 | ) | (6,055 | ) | ||||||||||||
Eliminate Illinois Regulated/Merchant Generation common customers | (5,566 | ) | (4,939 | ) | (5,800 | ) | ||||||||||||||||||
Eliminate Ameren Illinois/Merchant Generation common customers | (5,016 | ) | (5,566 | ) | (4,939 | ) | ||||||||||||||||||
Ameren total | 104,062 | 107,754 | 107,486 | 111,887 | 104,062 | 107,754 | ||||||||||||||||||
Electric Operating Revenues (in millions): | ||||||||||||||||||||||||
Missouri Regulated: | ||||||||||||||||||||||||
Ameren Missouri: | ||||||||||||||||||||||||
Residential | $ | 982 | $ | 948 | $ | 980 | $ | 1,193 | $ | 982 | $ | 948 | ||||||||||||
Commercial | 881 | 838 | 839 | 1,004 | 881 | 838 | ||||||||||||||||||
Industrial | 314 | 372 | 390 | 399 | 314 | 372 | ||||||||||||||||||
Other | 122 | 108 | 93 | 147 | 122 | 108 | ||||||||||||||||||
Native load subtotal | 2,299 | 2,266 | 2,302 | $ | 2,743 | $ | 2,299 | $ | 2,266 | |||||||||||||||
Off-system sales | 401 | 490 | 484 | 287 | 401 | 490 | ||||||||||||||||||
Subtotal | $ | 2,700 | $ | 2,756 | $ | 2,786 | $ | 3,030 | $ | 2,700 | $ | 2,756 | ||||||||||||
Illinois Regulated: | ||||||||||||||||||||||||
Ameren Illinois: | ||||||||||||||||||||||||
Residential | ||||||||||||||||||||||||
Power supply and delivery service | $ | 1,094 | $ | 1,112 | $ | 1,055 | $ | 1,270 | $ | 1,094 | $ | 1,112 | ||||||||||||
Commercial | ||||||||||||||||||||||||
Power supply and delivery service | 521 | 616 | 666 | 425 | 521 | 616 | ||||||||||||||||||
Delivery service only | 103 | 77 | 54 | 143 | 103 | 77 | ||||||||||||||||||
Industrial | ||||||||||||||||||||||||
Power supply and delivery service | 22 | 102 | 105 | 66 | 22 | 102 | ||||||||||||||||||
Delivery service only | 36 | 30 | 24 | 38 | 36 | 30 | ||||||||||||||||||
Other | 157 | 285 | 372 | 119 | 189 | 305 | ||||||||||||||||||
Native load subtotal | $ | 1,933 | $ | 2,222 | $ | 2,276 | $ | 2,061 | $ | 1,965 | $ | 2,242 | ||||||||||||
Merchant Generation: | ||||||||||||||||||||||||
Nonaffiliate energy sales | $ | 1,340 | $ | 1,389 | $ | 1,310 | $ | 1,442 | $ | 1,340 | $ | 1,389 | ||||||||||||
Affiliate native energy sales | 385 | 441 | 461 | 231 | 385 | 441 | ||||||||||||||||||
Other | (15 | ) | 106 | 41 | 20 | (15 | ) | 106 | ||||||||||||||||
Subtotal | $ | 1,710 | $ | 1,936 | $ | 1,812 | $ | 1,693 | $ | 1,710 | $ | 1,936 | ||||||||||||
Eliminate affiliate revenues | (434 | ) | (547 | ) | (591 | ) | (263 | ) | (435 | ) | (547 | ) | ||||||||||||
Ameren total | $ | 5,909 | $ | 6,367 | $ | 6,283 | $ | 6,521 | $ | 5,940 | $ | 6,387 | ||||||||||||
| Electric Operating Statistics –Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||||
Electric Generation – megawatthours (in millions): | ||||||||||||||||||||||||
Missouri Regulated | 48.7 | 49.3 | 50.3 | |||||||||||||||||||||
Ameren Missouri | 48.1 | 48.7 | 49.3 | |||||||||||||||||||||
Merchant Generation: | ||||||||||||||||||||||||
Genco | 13.4 | 16.6 | 17.4 | 22.0 | 20.5 | 24.6 | ||||||||||||||||||
AERG | 6.8 | 6.7 | 5.3 | 7.5 | 6.8 | 6.7 | ||||||||||||||||||
EEI | 7.1 | 8.0 | 8.1 | |||||||||||||||||||||
Medina Valley | 0.2 | 0.2 | 0.2 | 0.1 | 0.2 | 0.2 | ||||||||||||||||||
Subtotal | 27.5 | 31.5 | 31.0 | 29.6 | 27.5 | 31.5 | ||||||||||||||||||
Ameren total | 76.2 | 80.8 | 81.3 | 77.7 | 76.2 | 80.8 | ||||||||||||||||||
Price per ton of delivered coal (average) | $ | 29.85 | $ | 26.90 | (a) | $ | 25.20 | $ | 32.91 | $ | 29.85 | $ | 26.90 | (a) | ||||||||||
Source of energy supply: | ||||||||||||||||||||||||
Coal | 67.0 | % | 70.1 | % | 68.7 | % | 65.7 | % | 67.0 | % | 70.1 | % | ||||||||||||
Gas | 0.6 | 0.8 | 1.8 | |||||||||||||||||||||
Nuclear | 10.8 | 9.5 | 9.4 | 8.9 | 10.8 | 9.5 | ||||||||||||||||||
Hydroelectric | 2.0 | 1.8 | 1.6 | 1.6 | 2.0 | 1.8 | ||||||||||||||||||
Purchased and interchanged, net | 19.6 | 17.8 | 18.5 | |||||||||||||||||||||
Gas | 1.0 | 0.6 | 0.8 | |||||||||||||||||||||
Purchased – Wind | 0.3 | 0.1 | - | |||||||||||||||||||||
Purchased – Other | 22.5 | 19.5 | 17.8 | |||||||||||||||||||||
| 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||||
| Gas Operating Statistics –Year Ended December 31, | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||||
Gas Sales (millions of Dth) | ||||||||||||||||||||||||
Missouri Regulated: | ||||||||||||||||||||||||
Ameren Missouri: | ||||||||||||||||||||||||
Residential | 7 | 8 | 7 | 7 | 7 | 8 | ||||||||||||||||||
Commercial | 4 | 4 | 4 | 4 | 4 | 4 | ||||||||||||||||||
Industrial | 1 | 1 | 1 | 1 | 1 | 1 | ||||||||||||||||||
Subtotal | 12 | 13 | 12 | 12 | 12 | 13 | ||||||||||||||||||
Illinois Regulated: | ||||||||||||||||||||||||
Ameren Illinois: | ||||||||||||||||||||||||
Residential | 60 | 65 | 59 | 60 | 60 | 65 | ||||||||||||||||||
Commercial | 26 | 28 | 25 | 23 | 26 | 28 | ||||||||||||||||||
Industrial | 7 | 11 | 10 | 7 | 7 | 11 | ||||||||||||||||||
Subtotal | 93 | 104 | 94 | 90 | 93 | 104 | ||||||||||||||||||
Other: | ||||||||||||||||||||||||
Industrial | 3 | 4 | 2 | 1 | 3 | 4 | ||||||||||||||||||
Subtotal | 3 | 4 | 2 | 1 | 3 | 4 | ||||||||||||||||||
Eliminate affiliate sales | - | (1 | ) | - | - | - | (1 | ) | ||||||||||||||||
Ameren total | 108 | 120 | 108 | 103 | 108 | 120 | ||||||||||||||||||
Natural Gas Operating Revenues (in millions) | ||||||||||||||||||||||||
Missouri Regulated: | ||||||||||||||||||||||||
Ameren Missouri: | ||||||||||||||||||||||||
Residential | $ | 106 | $ | 121 | $ | 108 | $ | 100 | $ | 106 | $ | 121 | ||||||||||||
Commercial | 47 | 54 | 47 | 43 | 47 | 54 | ||||||||||||||||||
Industrial | 10 | 12 | 12 | 10 | 10 | 12 | ||||||||||||||||||
Other | 7 | 14 | 7 | 13 | 7 | 14 | ||||||||||||||||||
Subtotal | $ | 170 | $ | 201 | $ | 174 | $ | 166 | $ | 170 | $ | 201 | ||||||||||||
Illinois Regulated: | ||||||||||||||||||||||||
Ameren Illinois: | ||||||||||||||||||||||||
Residential | $ | 646 | $ | 819 | $ | 687 | $ | 649 | $ | 646 | $ | 819 | ||||||||||||
Commercial | 259 | 338 | 272 | 223 | 259 | 338 | ||||||||||||||||||
Industrial | 38 | 119 | 103 | 44 | 38 | 119 | ||||||||||||||||||
Other | 58 | (21 | ) | 39 | 37 | 72 | (11 | ) | ||||||||||||||||
Subtotal | $ | 1,001 | $ | 1,255 | $ | 1,101 | $ | 953 | $ | 1,015 | $ | 1,265 | ||||||||||||
Other: | ||||||||||||||||||||||||
Industrial | $ | 15 | $ | 26 | $ | 16 | $ | 4 | $ | 15 | $ | 26 | ||||||||||||
Subtotal | $ | 15 | $ | 26 | $ | 16 | $ | 4 | $ | 15 | $ | 26 | ||||||||||||
Eliminate affiliate revenues | (5 | ) | (10 | ) | (12 | ) | (6 | ) | (5 | ) | (10 | ) | ||||||||||||
Ameren total | $ | 1,181 | $ | 1,472 | $ | 1,279 | $ | 1,117 | $ | 1,195 | $ | 1,482 | ||||||||||||
Peak day throughput (thousands of Dth): | ||||||||||||||||||||||||
UE | 163 | 158 | 155 | |||||||||||||||||||||
CIPS | 280 | 266 | 250 | |||||||||||||||||||||
CILCO | 423 | 399 | 401 | |||||||||||||||||||||
IP | 650 | 615 | 574 | |||||||||||||||||||||
Total peak day throughput | 1,516 | 1,438 | 1,380 | |||||||||||||||||||||
Peak day throughput (thousands of Dth): UE AIC Total peak day throughputGas Operating Statistics –Year Ended December 31, 2010 2009 2008 167 163 158 1,227 1,353 1,280 1,394 1,516 1,438
| (a) | Includes impact of the Genco coal settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See Note 1 – Summary of Significant Account Policies under Part II, Item 8, of this report. |
The Ameren Companies make available free of charge through Ameren’s Web sitewebsite (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Ameren’s eXtensible Business Reporting Language (XBRL) documents, and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through an Internet Web sitewebsite maintained by the SEC (www.sec.gov). Ameren also uses its Web sitewebsite (www.ameren.com) as a channel of distribution of material information relating to the Ameren Companies. Financial and other material information regarding the Ameren Companies is routinely posted and accessible at Ameren’s Web site.website.
The Ameren Companies also make available free of charge through Ameren’s Web sitewebsite (www.ameren.com) the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, finance committee, nuclear oversight and environmental committee, and public policy committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to the Ameren Companies. The information on Ameren’s Web site,website, or any other Web sitewebsite referenced in this report, is not incorporated by reference into this report.
| ITEM 1A. | RISK FACTORS. |
Investors should review carefully the following risk factors and the other information contained in this report. The risks that the Ameren Companies face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect the financial position, results of operations, financial position, and liquidity of the Ameren Companies. See Forward-looking Statements above and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.
We are subject to extensive regulation of our businesses, which could adversely affect our results of operations, financial position, and liquidity.
We are subject to, or affected by, extensive federal and state regulation. This extensive regulatory framework, some but not all of which is more specifically identified in the following risk factors, regulates, among other matters, the electric and natural gas industries; rate and cost structure of utilities; operation of nuclear power facilities; construction and operation of generation, transmission and distribution facilities; acquisition, disposal, depreciation and amortization of assets and facilities; transmission reliability; and present or prospective wholesale and retail competition. We must address in our business planning and management of operations the effects of existing and proposed laws and regulations and potential changes in the regulatory framework, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities. Significant changes in the nature of the regulation of our businesses could require changes to our business planning and management of our businesses and could adversely affect our results of operations, financial position, and liquidity. Failure to obtain adequate rates or regulatory approvals in a timely manner, failure to obtain necessary licenses or permits from regulatory authorities, new or changed laws, regulations, standards, interpretations, or other legal requirements, or increased compliance costs could adversely impact our results of operations, financial position, and liquidity.
The electric and natural gas rates that UE CIPS, CILCO and IPAIC are allowed to charge are determined through regulatory proceedings, which are subject to appeal, and are subject to legislative actions, which are largely outside of their control. Any such events that prevent UE CIPS, CILCO or IPAIC from recovering their respective costs or from earning appropriate returns on their investments could have a material adverse effect on future results of operations, financial position, and liquidity.
The rates that UE CIPS, CILCO and IPAIC are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to UE CIPS, CILCO and IPAIC customers are determined, in large part,
by governmental entities, including the MoPSC, the ICC, and FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the
prudency of expenditures, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views, and are largely outside of our control.views. Decisions made by these governmental entities regarding rates as well as the regulatoryare largely outside of UE’s and AIC’s control. Regulatory lag involved in filing and getting new rates approved could have a material adverse effect on our results of operations, financial position, and liquidity. Rate orders are also subject to appeal and stay requests, which create additional uncertainty as to the rates UE and AIC will ultimately be allowed to charge for their services.
UE CIPS, CILCO and IPAIC electric and natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Rates established in those proceedings for UE are primarily based on historical costs and revenues,revenues. Rates established in those proceedings for AIC may be based on historical or estimated future costs and theyrevenues. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rates include an allowed return on investments by the regulator.regulators. Although rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all the costs of UE and AIC to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs or an adequate return on those investments.
Our company, and the industry as a whole, is going through a periodDuring periods of rising costs and investments. The fact that rates atinvestments or declining retail usage, UE CIPS, CILCO and IP are primarily based on historical costs and revenues means that these companiesAIC may not be able to earn the allowed return established by their regulators andregulators. This could result in deferral or elimination of planned capital investments. As a result, UE CIPS, CILCO and IPAIC expect to file rate cases frequently. A period of increasing rates for our customers, especially during weak economic times, could result in additional regulatory and legislative actions, as well as competitive and political pressures, thatwhich could have a material adverse effect on our results of operations, financial position, and liquidity.
We are subject to various environmental laws and regulations that require significant capital expenditures or could result in closure of facilities, could increase our operating costs, and could adversely influence or limit our results of operations, financial position, and liquidity, or expose us to environmental fines and liabilities.
We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address noise, emissions, impacts to air, land and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and
chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.
Compliance with environmentalIn addition to existing laws and regulations cangoverning our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco that operate coal-fired power plants. Significant new rules already proposed or promulgated within the past year include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NOx emissions that increase the stringency of the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO2 and NOx emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act, which could require significant capital expenditures such as new water intake structures or cooling towers at our power plants; NSPS and operating costs. Periodically, environmental statutesemission guidelines for greenhouse gas emissions applicable to new and existing electric generating units; and a MACT standard for the control of hazardous air pollutants such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many of the details of these future regulations are amendedunknown, the combined effect of the new and new statutesproposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to eight years for Ameren, UE and regulations are adopted that
impose new or modified obligations on our facilities and operations.Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, wethese regulations could be requiredrequire us to close or to significantly alter the operation of our generating facilities, which could have an adverse effect on our results of operations, financial position, and liquidity.
Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures affecting operating assets. measures.
We are also subject to liability under environmental laws for remediating environmental contamination of property now or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such sites include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws and regulations against us and could allege injury from exposure to hazardous materials.
Ameren also may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative targeted at coal-fired power plants in the United States to determine whether thosecoal-fired power plants failed to comply
with the requirements of the NSR and New Source Performance Standards (NSPS)NSPS provisions under the Clean Air Act when the plants implemented modifications. Failure to comply with the NSR and NSPS provisions under the Clean Air Act can result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties. Ameren and Genco have received requests for information from the EPA pursuant to Section 114(a) of the Clean Air Act. In January 2010, UE received a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V programs. In the Notice of Violation, the EPA contends that various projects at UE’s Labadie, Meramec, Rush Island, and Sioux coal-fired power plant facilities, dating back to the mid-1990s, triggered NSR requirements. In October 2010, the EPA supplemented and amended the Notice of Violation to include additional projects at UE’s coal-fired power plant facilities. The amended Notice of Violation followed a series of information requests under Section 114(a). In January 2011, the EPA filed a complaint against UE in the United States District Court for the Eastern District of Missouri. The EPA’s complaint alleges that in performing projects at its Rush Island coal-fired generating facility, UE violated provisions of the Clean Air Act and Missouri law. At present, the complaint does not include UE’s other coal-fired facilities. Litigation of this matter could take many years to resolve. An outcome in this matter adverse to UE could require substantial capital expenditures and the payment of substantial penalties, neither of which can be determined at this time. Such expenditures could affect unit retirement and replacement decisions and our results of operations, financial position, and liquidity if such costs are not recovered through regulated rates.
Ameren, UE Genco, AERG and EEIGenco have incurred and expect to incur significant costs related to environmental compliance and site remediation. 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, or closure of facilities for Ameren, UE Genco, AERG and EEI.Genco. 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 cost recovery mechanism for recovery of costsGenco or for Genco, AERG or EEI.Ameren’s Merchant Generation business segment. We are unable to predict the ultimate impact of these matters on our results of operations, financial position, and liquidity.
Future limits on greenhouse gas emissions would likely require Ameren, UE Genco, CILCO (through AERG) and EEIGenco to incur significant increases in capital expenditures and operating costs, which, if excessive, could result in the closures of coal-fired generating plants, impairment of
assets, or otherwise materially adversely affect our results of operations, financial position, and liquidity.
Initiatives to limit greenhouse gas emissions and to address climate change arehave been subject to active consideration in the U.S. Congress. In June 2009,the past two years, legislation has been passed in the U.S. House of Representatives passed energy legislation entitled “The American Clean Energy and Security Act of 2009” that, if enacted, would establish an economy-wide cap-and-trade program. The overarching goal of this
proposed cap-and-trade program isin the Senate to reduce greenhouse gas emissions from cappeddesignated sources, including coal-fired electric generation units, to 3% below 2005 levels by 2012, 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. In September 2009, climate change legislation entitled “The Clean Energy Jobs and American Power Act” was introduced in the U.S. Senate that was similar to that passed by the U.S. Houseunits. Many of Representatives in June 2009, although it proposes a slightly greater reduction in greenhouse gas emissions in the year 2020 and grants fewer emission allowances to the electricity sector. Under both proposed pieces of legislation, large sources of CO2 emissions will be required to obtain and retire an allowance for each ton of CO2 emitted.these proposals have included economy-wide cap-and-trade programs. The allowances may be allocated to the sources without cost, sold to the sources through auctions or other mechanisms, or traded among parties. “The Clean Energy Jobs and American Power Act” was voted out of committee in November 2009. In December 2009, Senators Kerry, Graham and Lieberman introduced a framework for Senate legislation in 2010. The framework lacks specifics, but it is consistent with the House-passed legislation except that it emphasizes the need for greater support for nuclear power and energy independence through support for clean energy and drilling for oil and natural gas. Senate leadership has stated that consideration of climate legislation will be postponed until spring 2010. In addition, the reduction of greenhouse gas emissions has been identified as a high priority by President Obama’s administration. Although we cannot predict the date of enactment or the requirements of any future climate change legislation or regulations, we believe it is possible that some form of federal legislation or regulations to control emissions of greenhouse gases will become law during the current administration.
Potential impacts from climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost containmentcost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, ourOur emissions of greenhouse gases vary among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas.. Ameren’s analysis shows that if either “The American Clean Energy and Security Actmost versions of 2009” or “The Clean Energy Jobs and American Power Act”the recently proposed climate change bills were enacted into law, in its current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest
because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits per kilowatthour about half the amount ofas much CO2 thatas coal emits when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy-wide shifts favoringto natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes. Ameren believesprocesses that wholesaleuse natural gas costs could rise significantly as well.gas. Higher costs for energy could contribute to reduced demand for electricity and natural gas.
Additional requirements to control greenhouse gas emissions and address global climate change may also arise pursuant to the Midwest Greenhouse Gas Reduction Accord, an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin, and Minnesota to develop a strategy to achieve energy security and to reduce greenhouse gas emissions through a cap-and-trade mechanism. The advisory group to the Midwest governors provided draft final recommendations on the design of a greenhouse gas reduction program in June 2009. The recommendations have not been endorsed or approved by the state governors. It is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.
With regard to the control of greenhouse gas emissions under federal regulation, in 2007, the U.S. Supreme Court issued a decision finding that the EPA has the authority to regulate CO2 and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision required the EPA to determine whether greenhouse gas emissions may reasonably be anticipated to endanger public health or welfare, or, in the alternative, to provide a reasonable explanation as to why greenhouse gas emissions should not be regulated. In December 2009, in response to the decision of the U.S. Supreme Court, the EPA issued its “endangerment finding” determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. It is expected thatIn March 2010, the EPA will issueissued a rule by the end of March 2010 to controldetermination that greenhouse gas emissions from light-duty vehiclesstationary sources, such as automobiles. Once this rule is effective, greenhouse gases will, for the first time,power plants, would be a regulated air pollutant under the Clean Air Act. The EPA has taken the position that thesubject to regulation of greenhouse gas emissions from new motor vehicles under the Clean Air Act in 2011. As a result of these actions, we will triggerbe required to consider the applicabilityemissions of other Clean Air Act programs, such as the Title V Operating Permit Program and the NSR program, which apply to greenhouse gas emissions from stationary sources. This would include fossil fuel-fired electricity generating plants.in any air permit application submitted by us or pending after January 1, 2011.
Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA announcedfinalized in September 2009 a proposed rule,May 2010 regulations known as the “tailoring rule,“Tailoring Rule,” that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The Tailoring Rule became effective in January 2011. The rule would requirerequires any source that emits at least 25,000 tons per year of greenhouse gases measured as CO2 equivalents (CO2e) to obtainalready has an operating permit under Title V Operating Permit Program of
the Clean Air Act. Sources that alreadyto have an operating permit would have greenhouse gas-specificgreenhouse-gas-specific provisions added to their permits upon renewal. Currently, all Ameren power plants have operating permits that, depending on the final rule,when renewed, may be modified when they are renewed to address greenhouse gas emissions. The proposed tailoring ruleTailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases of at least 75,000 tons per year, measured as CO2 equivalents, such
projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would setbe required to obtain such a new applicability threshold for subjecting stationary sourcespermit and to install the requirements ofbest available control technology if their greenhouse gas emissions exceed the NSR programapplicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil-fuel fired power plants. In the announcement, the EPA said it will propose standards for power plants in July 2011 and issue final standards in May 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at our power plants as a result of any of the EPA’s new and future rules. Legal challenges to the EPA’s greenhouse gas rules have been filed and more challenges are expected. Any federal climate change legislation that is enacted may preempt the EPA’s regulation of greenhouse gas emissions, threshold for determining when modifications at such stationary sources would requireincluding the sourceTailoring Rule, particularly as it relates to obtainpower plant greenhouse gas emissions. The extent to which the Tailoring Rule could have a permit andmaterial impact on our generating facilities depends upon how state agencies apply the EPA’s guidelines as to implementwhat constitutes the best available control technology to addressfor greenhouse gas emissions.emissions from power plants, whether physical changes or changes in operations subject to the rule occur at our power plants, and whether federal legislation that preempts the rule is passed.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent we requestUE requests recovery of these costs through rates, ourits regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force Ameren, UE Genco, CILCO (through AERG) and EEIGenco as well as other similarly situated electric power generators to close some coal-fired facilities and could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s (through AERG) and EEI’sGenco’s results of operations, financial position, and liquidity.
The construction of, and capital improvements to, Ameren’s, UE’s CIPS’, CILCO’s and IP’sAIC’s electric and gas utility infrastructure as well as to Genco’s, CILCO’s (through AERG)Ameren’s and EEI’sGenco’s merchant generation facilities involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as scheduled, cost disallowances by regulators and the inability to earn a reasonable rate of return on invested capital, at our rate-regulated utilities, any of which could result in higher costs and the closure of facilities.
Over the next five years, the Ameren Companies will incur significant capital expenditures to comply with existing and known environmental regulations and to make investments in their electric and gas natural utility infrastructure and their merchant generation facilities. The
Ameren Companies estimate that they will incur up to $8.1$8.2 billion (UE – up to $4.2$4.1 billion; CIPSAIC – up to $555 million;$2.4 billion; Genco – up to $1.0 billion; CILCO (Illinois Regulated)other – up to $400 million; CILCO (AERG) – up to $180 million; IP – up to $1.1 billion; EEI – up to $460 million; Other – up to $220$700 million) of capital expenditures during the period 20102011 through 2014.2015. These expenses include construction expenditures, capitalized interest or allowance for funds used during construction, and compliance with environmental standards. Construction costs as well as the cost of capital have escalated in recent years andyears. They are expected to either stay at current levels or to escalate further.
Investments in Ameren’s regulated operations are expected to be recoverable from ratepayers, but are subject to prudency reviews and regulatory lag. The recoverability of amounts expended in merchant generation operations will depend on whetherupon market prices for power adjust to reflect increased costs for generators.capacity and energy.
The ability of the Ameren Companies to complete facilities under construction successfully, and to complete future projects within established estimates, is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors who do not perform as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on favorable terms, or other events beyond our control maythat could occur that may materially affect the schedule, cost and performance of these projects. With respect to capital spent for pollution control equipment, there is a risk that electric generating plants will not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such construction efforts be unsuccessful, the Ameren Companies could be subject to additional costs and to the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase electricity for their customers until the projects are completed. All of these risks may have a material adverse effect on the Ameren Companies’ results of operations, financial position, and liquidity.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to various arrangements who owe us money, credit, energy, coal, or other commodities or services will not be able to perform their obligations or, with respect to our credit facilities, will fail to honor their commitments. Should the counterparties to commodity arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. Should the lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements would decrease unless we were able to find replacement lenders to assume the nonperforming lender’s commitment. In such an event, we might incur losses, or our results of operations, financial position, and liquidity could otherwise be adversely affected.
Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries as a result of transactions involving energy, coal, other commodities and services, and as a result of hedging transactions. If one Ameren entity failed to perform under any of these arrangements, other Ameren entities might incur losses. Their results of operations, financial position, and liquidity could be adversely affected, resulting in the nondefaulting Ameren entity being unable to meet its obligations, including to unrelated third parties.
Increasing costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee-relatedemployee benefits could materially adversely affect our results of operations, financial position, and liquidity.
We offer defined benefit retirement and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2009,2010, its investment performance in 2009,2010, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $225$110 million in each of the next five years, with aggregate estimated contributions of $740$470 million. We expect UE’s, CIPS’,AIC’s, and Genco’s CILCO’s, and IP’s portion of the future funding requirements to be 66%63%, 6%, 9%, 9%28%, and 10%9%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits could increase our financing needs and otherwise materially adversely affect our results of operations, financial position, and liquidity.
Our electric generating, transmission and distribution facilities are subject to operational risks that could materially adversely affect our results of operations, financial position, and liquidity.
The Ameren Companies’ financial performance depends on the successful operation of electric generating, transmission, and distribution facilities. Operation of electric generating, transmission, and distribution facilities involves many risks, including:
| Ÿ | facility shutdowns due to operator error or a failure of equipment or processes; |
| Ÿ | longer-than-anticipated maintenance outages; |
| Ÿ | older generating equipment may require significant expenditures to keep it operating at peak efficiency; |
| Ÿ | disruptions in the delivery of fuel or lack of adequate inventories; |
| Ÿ | lack of water for cooling plant operations; |
| Ÿ | labor disputes; |
| Ÿ | inability to comply with regulatory or permit requirements, including those relating to environmental contamination; |
| Ÿ | disruptions in the delivery of electricity, including impacts on us or our customers; |
| Ÿ | handling and storage of fossil-fuel combustion |
| Ÿ | unusual or adverse weather conditions, including severe storms, droughts, and floods; |
| Ÿ | a workplace accident that might result in injury or loss of life, extensive property damage, or environmental damage; |
| Ÿ | information security risk, such as a breach of systems where sensitive utility customer data and account information are stored; |
| Ÿ | catastrophic events such as fires, explosions, pandemic health events, or other similar occurrences; |
| Ÿ | limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generating, transmission, and distribution facilities; and |
| Ÿ | other unanticipated operations and maintenance expenses and liabilities. |
We are subject to federal regulatory compliance and proceedings, which increase our risk of regulatory penalties and other sanctions.
The Energy Policy Act of 2005 increased FERC’s civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1 million per violation per day. Under the Energy Policy Act of 2005, the Ameren Companies, as owners and operators of bulk power transmission systems and/or electric generation facilities, are subject to mandatory reliability standards. Compliance with these mandatory reliability standards may subject the Ameren Companies to higher operating costs and may result in increased capital expenditures. If the Ameren Companies were found not to be in compliance with these mandatory reliability standards or other FERC statutes, rules and orders, the Ameren Companies may incur substantial monetary penalties and other sanctions, which could adversely affect their results of operations, financial position, and liquidity.
Our natural gas distribution and storage activities involve numerous risks that may result in accidents and other operating risks and costs that could materially adversely affect our results of operations, financial position, and liquidity.
Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, accidental explosions, and mechanical problems, which could cause substantial financial losses. In addition,
these risks could result in serious injury to employees and nonemployees, loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of distribution lines and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could materially adversely affect our results of operations, financial position, and liquidity.
Even though agreements have been reached with the state of Missouri and the FERC, the breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could continue to have a material adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.
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. UE settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident.
UE hashad property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance doesdid not cover some lost electric margins and penalties paid to FERC. UE expectsbelieves that the total cost for cleanup, damage, and liabilities, excluding costs to rebuild the upper reservoir, will beis approximately $205 million.$207 million, which is the amount UE paid as of December 31, 2010.
In June 2010, UE received approval from FERC to rebuildsued an insurance company that was providing UE with liability coverage on the upper reservoir at its Taum Sauk plant and is in the processdate of testing the rebuilt facility. UE expects the Taum Sauk plant to become operationalincident. In the litigation, filed in the second quarterU.S. District Court for the Eastern District of 2010. The estimated costMissouri, UE claimed the insurance company breached its duty to rebuildindemnify UE for the upper reservoir is inlosses experienced from the rangeincident. In January 2011, a federal judge ruled that the parties must first pursue alternative dispute resolution under the terms of $490 million.
Under UE’s insurance policies, all claims by or againsttheir coverage agreement. In February 2011, UE are subjectfiled an appeal of the January ruling to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the CircuitU.S. Court of St. Louis County, Missouri, seeking a declaratory judgment thatAppeals for the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized. The three insurers allege that they, along with the other policy participants, presented a rebuild design that was consistent with their insurance coverage obligations and that the insurance policies do not require these insurers to pay their share of the costs of construction associated with the design being used. These insurers have estimated a cost of approximately $214 million for their rebuild design compared to the estimated $490 million cost of the design approved by FERC and implemented by Ameren. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri, against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. AmerenEighth District, which seeks paymentresolution outside of a sum to-be-determined for all amounts covered by these policies incurred in the facility rebuild, including power replacement costs, interest, and attorneys’ fees. The insurers that are parties to the litigation represent approximately 40%, on a weighted average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million.dispute resolution process.
Until Ameren’s remaining liability insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and UE’s results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren and UE expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the
The recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 Statestate of
Missouri settlement agreement. In that settlement, UE agreed that it would not attempt to recover from rate payersratepayers costs incurred in the reconstruction, expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that were not at that time reasonably foreseeable and costs that would have been incurred absent the Taum Sauk incident. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the in-service date of the rebuilt facility. As of December 31, 2009,2010, UE had capitalized in property and plant qualifying Taum Sauk-related costs of $99$89 million that UE believes qualify for potential recovery in electric rates under the terms of the November 2007 Statestate of Missouri Settlement.settlement agreement, and those costs were included in UE’s pending electric rate increase request filed in September 2010. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC in a future rate case.MoPSC. Any amounts not recovered through insurance, in electric rates, or otherwise, could result in charges to earnings, which could be material.
Genco’s AERG’s, and EEI’sAERG’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risks.
All of Genco’s AERG’s, and EEI’sAERG’s generating facilities compete for the sale of energy and capacity in the competitive energy markets.
To the extent that electricity generated by these facilities is not under a fixed-price contract to be sold, the revenues and results of operations of these merchant subsidiaries generally depend on the prices that can be obtained for energy and capacity in Illinois and adjacent markets by Marketing Company.
Market prices for energy and capacity may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and fuel can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply,oversupply, prices might be depressed. Also, at times legislators or regulators with jurisdiction over wholesale and retail energy commodity and transportation rates may impose price limitations, bidding rules, and other mechanisms to address volatility and other issues in these markets.
For power products sold in advance, contract prices are influenced both by market conditions as well asand by the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Marketing Company’s contract portfolio may have average contract prices greater than or less than current market prices, including at the expiration of the contracts, which could significantly affect Ameren’s Genco’s, AERG’s, and EEI’sGenco’s results of operations, financial condition and liquidity.
Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
| Ÿ | current and future delivered market prices for natural gas, fuel oil, and coal, and related transportation costs; |
| Ÿ | current and forward prices for the sale of electricity; |
| Ÿ | current and future prices for emission allowances that may be required to operate the fossil fuel-fired electric generating facilities in compliance with environmental laws and permits; |
| Ÿ | the extent of additional supplies of electric energy from current competitors or new market entrants; |
| Ÿ | the regulatory and market structures developed for evolving Midwest energy markets; |
| Ÿ | changes enacted by the Illinois legislature, the ICC, the IPA, or other government agencies with respect to power procurement procedures; |
| Ÿ | the potential for reregulation of generation in some states; |
| Ÿ | future pricing for, and availability of, services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit our ability to sell energy in our markets; |
| Ÿ | the growth rate in electricity usage as a result of population changes, regional economic conditions, and the implementation of energy-efficiency programs; |
| Ÿ | climate conditions in the Midwest market and major natural disasters; and |
| Ÿ | environmental laws and regulations. |
UE’s ownership and operation of a nuclear generating facility creates business, financial, and waste disposal risks.
UE’s ownership of the Callaway nuclear plant subjects it to the risks of nuclear generation, which include the following:
| Ÿ | potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; |
| Ÿ | the lack of a permanent waste storage site; |
| Ÿ | limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the Callaway nuclear plant or other U.S. nuclear operations; |
| Ÿ | uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate; |
| Ÿ | public and governmental concerns over the adequacy of security at nuclear power plants; |
| Ÿ | uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE’s facility operating license for the Callaway nuclear plant expires in 2024); |
| Ÿ | limited availability of fuel supply; and |
| Ÿ | costly and extended outages for scheduled or unscheduled maintenance and refueling. |
The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear
generation facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated from time to time by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position, and liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit. An incident at a nuclear facility anywhere in the world also could cause the NRC to impose additional conditions or requirements on the industry, which could increase costs and result in additional capital expenditures.
Our energy risk management strategies may not be effective in managing fuel and electricity procurement and pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings and cash flows.
We are exposed to changes in market prices for natural gas, fuel, electricity, emission allowances, and transmission congestion. Prices for natural gas, fuel, electricity, and emission allowances may fluctuate substantially over relatively short periods of time, and at other times experienceexhibit sustained increases or decreases, and expose us to commodity price risk. We use short-term and long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk or that they will not result in net liabilities because of future volatility in these markets.
Although we routinely enter into contracts to hedge our exposure to the risks of demand and changes in commodity prices, we do not hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, and liquidity.
Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.
Like other electric and natural gas utilities and other merchant electric generators, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could
result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs for repair, which could have a material adverse effect on our results of operations, financial position, and liquidity.
Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.
We use short-term and long-term debt as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including requirements related to future environmental compliance. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with near-term regulatory lag, we expect to continue to rely on short-term and long-term debt financing. Ameren intends to replace or extend its credit facility agreements during 2010. The inability to raise debt or equity capital on favorable terms, or at all, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control, such as thea recession or extreme volatility and disruption in global debt or equity capital and credit markets, that occurred in 2008 and continued into 2009, may create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity or credit markets, including theour ability to draw on our bank credit facilities. 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, which could have a material adverse effect on our results of operations, financial position, and liquidity. Certain of the Ameren Companies rely, in part, on Ameren for access to capital. Circumstances that limit Ameren’s access to capital, including those relating to its other subsidiaries, could impair its ability to provide those Ameren Companies with needed capital.
Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.
Ameren is a holding company; therefore, its primary assets are the common stock of its subsidiaries. As a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s ability to service its debt obligations is also dependent upon the earnings of operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under intercompany indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations and cash flows and other items affecting retained earnings. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of intercompany borrowing arrangements) to Ameren. Certain of the Ameren Companies’ financing agreements and articles of incorporation, in addition to certain statutory and regulatory requirements, may impose restrictions on the ability of such Ameren Companies to transfer funds to Ameren in the form of cash dividends, loans or advances.
Failure to retain and attract key officers and other skilled professional and technical employees could have an adverse effect on our operations.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. A significant portion of our work force is nearing retirement, including many employees with specialized skills such as maintaining and servicing our electric and natural gas infrastructure and operating our generating units. Our inability to retain and recruit qualified employees could adversely affect our results of operations.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS. |
None.
| ITEM 2. | PROPERTIES. |
For information on our principal properties, see the generating facilities table below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for any discussion of planned additions, replacements or transfers. See also Note 5 – Long-term Debt and Equity Financings, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 20102011 peak summer electrical demand:
| Primary Fuel Source | Plant | Location | Net Kilowatt Capability(a) | |||||
Ameren Missouri | ||||||||
Coal | Labadie | Franklin County, Mo. | 2,401,000 | |||||
| Rush Island | Jefferson County, Mo. | 1,222,000 | ||||||
| Sioux | St. Charles County, Mo. | 968,000 | ||||||
| Meramec | St. Louis County, Mo. | 832,000 | ||||||
Total coal | 5,423,000 | |||||||
Nuclear | Callaway | Callaway County, Mo. | 1,194,000 | |||||
Hydroelectric | Osage | Lakeside, Mo. | 240,000 | |||||
| Keokuk | Keokuk, Ia. | 136,000 | ||||||
Total hydroelectric | 376,000 | |||||||
Pumped-storage | Taum Sauk | Reynolds County, Mo. | 450,000 | |||||
Oil (CTs) | Meramec | St. Louis County, Mo. | 58,000 | |||||
| Fairgrounds | Jefferson City, Mo. | 54,000 | ||||||
| Mexico | Mexico, Mo. | 53,000 | ||||||
| Moberly | Moberly, Mo. | 53,000 | ||||||
| Moreau | Jefferson City, Mo. | 53,000 | ||||||
| Howard Bend | St. Louis County, Mo. | 39,000 | ||||||
| Venice | Venice, Ill. | ( | ) | |||||
Total oil | 310,000 | |||||||
Natural gas (CTs) | Audrain | Audrain County, Mo. | 592,000 | |||||
| Venice | Venice, Ill. | 487,000 | ||||||
| Goose Creek | Piatt County, Ill. | 426,000 | ||||||
| Pinckneyville | Pinckneyville, Ill. | 312,000 | ||||||
| Raccoon Creek | Clay County, Ill. | 300,000 | ||||||
| Kinmundy | Kinmundy, Ill. | 206,000 | ||||||
| Peno Creek(c)(d) | Bowling Green, Mo. | 188,000 | ||||||
| Meramec | St. Louis County, Mo. | 48,000 | ||||||
| Viaduct | Cape Girardeau, Mo. | 25,000 | ||||||
| Kirksville | Kirksville, Mo. | 13,000 | ||||||
Total natural gas | 2,597,000 | |||||||
Total | ||||||||
| 10,350,000 | |||||||
Merchant Generation: | ||||||||
Genco: | ||||||||
Coal | Newton | Newton, Ill. | 1,186,000 | |||||
| Joppa Generating Station (EEI) | Joppa, Ill. | 1,002,000 | ||||||
| Coffeen | Coffeen, Ill. | 895,000 | ||||||
| Meredosia | Meredosia, Ill. | 203,000 | ||||||
| Hutsonville | Hutsonville, Ill. | 151,000 | ||||||
Total coal | 3,437,000 | |||||||
Oil | Meredosia | Meredosia, Ill. | 166,000 | |||||
| Hutsonville (Diesel) | Hutsonville, Ill. | 3,000 | ||||||
Total oil | 169,000 | |||||||
Natural gas (CTs) | Grand Tower | Grand Tower, Ill. | 511,000 | |||||
| Elgin | Elgin, Ill. | 468,000 | ||||||
| Gibson City | Gibson City, Ill. | 230,000 | ||||||
| Joppa 7B | Joppa, Ill. | 162,000 | ||||||
| Columbia | Columbia, Mo. | 108,000 | ||||||
| Joppa (EEI) | Joppa, Ill. | 74,000 | ||||||
Total natural gas | 1,553,000 | |||||||
Total Genco | 5,159,000 | |||||||
| ||||||||
Coal | E.D. Edwards | Bartonville, Ill. | 650,000 | |||||
| Duck Creek | Canton, Ill. | 410,000 | ||||||
Total | ||||||||
| ||||||||
Medina Valley: | ||||||||
Natural gas | Medina Valley | Mossville, Ill. | 44,000 | |||||
Total Merchant Generation | 6,263,000 | |||||||
Total Ameren | 16,613,000 | |||||||
| (a) |
| (b) | This facility is |
| (c) |
| There are economic development lease arrangements applicable to these CTs. |
| In June 2010, Genco |
The following table presents electric and natural gas utility-related properties for UE CIPS, CILCO and IPAIC as of December 31, 2009:2010:
| UE | CIPS | CILCO | IP | |||||||||
Circuit miles of electric | 2,942 | 2,306 | 331 | 1,869 | ||||||||
Circuit miles of electric | 33,012 | 14,929 | 8,926 | 21,639 | ||||||||
Circuit miles of electric | 22 | % | 12 | % | 26 | % | 13 | % | ||||
Miles of natural gas | 3,259 | 5,359 | 3,915 | 8,818 | ||||||||
Propane-air plants | 1 | 1 | - | - | ||||||||
Underground gas storage | - | 3 | 2 | 7 | ||||||||
Billion cubic feet of total | - | 2 | 8 | 15 |
| UE | AIC | |||||||
Circuit miles of electric transmission lines | 2,944 | 4,535 | ||||||
Circuit miles of electric distribution lines | 33,031 | 45,531 | ||||||
Circuit miles of electric distribution lines underground | 22 | % | 15 | % | ||||
Miles of natural gas transmission and distribution mains | 3,268 | 18,128 | ||||||
Propane-air plants | 1 | - | ||||||
Underground gas storage fields | - | 12 | ||||||
Billion cubic feet of total working capacity of underground gas storage fields | - | 25 | ||||||
Our other properties include office buildings, warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all principal plants and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bonds and credit facility indebtedness and to certain permitted liens and judgment liens). The exceptions are as follows:
| Ÿ | A portion of UE’s Osage plant reservoir, certain facilities at UE’s Sioux plant, most of UE’s Peno Creek and Audrain CT facilities, Genco’s Columbia CT facility, Medina Valley’s generating facility, certain substations, and most transmission and distribution lines and gas mains are situated on lands occupied under leases, easements, franchises, licenses, or permits. |
The United States or the state of Missouri may own or may have paramount rights to certain lands lying in the |
bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which certain of UE’s generating and other properties are located. |
| Ÿ | The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of UE’s Keokuk plant is located. |
Substantially all of the properties and plant of UE CIPS, CILCO and IPAIC are subject to the first liens of the indentures securing their mortgage bonds.
UE has conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city through 2022. Under the terms of this capital lease, UE is responsible for all operation and maintenance for the facility. Ownership of the facility will transfer to UE at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
UE operates a CT facility located in Audrain County, Missouri. UE has rights and obligations as lessee of the CT facility under a long-term lease with Audrain County. The lease term will expire on December 1, 2023. Under the terms of this capital lease, UE is responsible for all operation and maintenance for the facility. Ownership of the facility will transfer to UE at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
| ITEM 3. | 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.
In July 2009, Caterpillar Inc., in conjunction with other industrial customers as a coalition, intervened in the 2009 rate cases filed by CILCO and IP with the ICC to modify its electric and natural gas delivery service rates. Douglas R. Oberhelman is an executive officer of Caterpillar Inc. and a member of the board of directors of Ameren.
Mr. Oberhelman did not participate in Ameren Corporation’s board and committee deliberations relating to these matters.
For additional information on Material legal and administrative proceedings, see Rates and Regulation under Item 1, Business, and Item 1A, Risk Factors, above. See also Liquidity and Capital Resources and Regulatory Matterswhich are discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, and Note 15 – CommitmentsCommitment and Contingencies under Partpart II, Item 8, of this report.report and incorporated herein by reference, include the following:
appeal of the MoPSC January 2009 and May 2010 electric rate orders; |
| Ÿ | an electric rate case proceeding for UE pending before the MoPSC; |
| Ÿ | the MoPSC staff’s FAC prudence review pending before the MoPSC; |
| Ÿ | appeal of the MoPSC rules implementing the Missouri renewable energy portfolio requirement; |
| Ÿ | appeal of certain aspects of the ICC’s 2010 rate orders; |
| Ÿ | electric and natural gas rate proceedings for AIC pending before the ICC; |
| Ÿ | the EPA’s Clean Air Act-related litigation filed against UE and NSR investigations at Genco and AERG; |
| Ÿ | remediation matters associated with MGP and waste disposal sites of the Ameren Companies; |
| Ÿ | litigation associated with the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility; and |
| Ÿ | asbestos-related litigation associated with Ameren, UE, AIC and Genco. |
| [REMOVED AND RESERVED]. |
There were no matters submitted to a vote of security holders during the fourth quarter of 2009 with respect to any of the Ameren Companies.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, as of December 31, 2010, (except as otherwise noted) are listed below, along with their ages as of December 31, 2009,2010, all positions and offices held with the Ameren Companies, tenure as officer, and business background for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.
AMEREN CORPORATION:
| Name | Age | Positions and Offices Held | ||
| 63 | |||
| President and Chief Executive Officer, and Director | |||
| Voss joined UE in 1969. He was elected senior vice president of UE, CIPS, and Ameren Services in 1999, of Genco in 2001, of CILCO in 2003, and of IP in 2004. In 2003, Voss was elected president of Genco; he relinquished his presidency of this company in 2004. In 2006, he was elected executive vice president of UE, CIPS, CILCO and IP. In 2007, Voss was elected chairman, president, and chief executive officer of UE. He relinquished his positions at CIPS, CILCO and IP in 2007. In 2009, Voss was elected president and chief executive officer of Ameren; at that time, he relinquished his other positions. In 2010, the Ameren board of directors elected Voss to the position of chairman of the board. He has been a member of the Ameren board since 2009. | ||||
Martin J. Lyons, Jr. | Senior Vice President and Chief Financial Officer | |||
| Lyons joined Ameren, UE, CIPS, Genco, and Ameren Services in 2001 as controller. He was elected controller of CILCO in 2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCO, and Ameren Services in 2003 and vice president and controller of IP in 2004. In 2007, his | ||||
| Senior Vice President and General Counsel (Effective March 2, 2011) | |||
Jerre E. Birdsong | Vice President and Treasurer | |||
| Birdsong joined UE in 1977 and was elected treasurer of UE in 1993. He was elected treasurer of Ameren, CIPS, and Ameren Services in 1997 and of Genco in 2000. In addition to being treasurer, in 2001 he was elected vice president at Ameren, UE, CIPS, Ameren Services and | ||||
SUBSIDIARIES:
| Name | Age | Positions and Offices Held | ||
Warner L. Baxter | Chairman, President and Chief Executive Officer (UE) | |||
| Baxter joined UE in 1995. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in 2001 and of CILCO in 2003. Baxter was elected to the | ||||
| Chairman, President and Chief Executive Officer | |||
| Borkowski joined UE in 1981. She left the company for a period of time before rejoining Ameren in 2005. Borkowski has led Ameren’s transmission operations since 2005 as vice president, transmission, of Ameren Services. In 2010, Borkowski was elected president and | ||||
Scott A. Cisel | 57 | Chairman, President and Chief Executive Officer (AIC) | ||
| Cisel joined CILCO in 1975. He was named senior vice president and leader of CILCO’s Sales and Marketing Business Unit in 2001. Cisel assumed the | ||||
Daniel F. Cole | Chairman, President and Chief Executive Officer (Ameren Services) | |||
| Cole joined UE in 1976. He was elected senior vice president of UE and Ameren Services in 1999 and of CIPS in 2001. He was elected president of Genco in 2001; he relinquished that position in 2003. He was elected senior vice president of CILCO in 2003 and of IP in 2004. In 2009, Cole was elected chairman, president and chief executive officer of Ameren | ||||
Karen C. Foss | Senior Vice President (Ameren Services) | |||
| Foss joined UE in 2007 as vice president | ||||
Adam C. Heflin | Senior Vice President and Chief Nuclear Officer (UE) | |||
| Heflin joined UE in 2005 as vice president of nuclear operations and was elected senior vice president and chief nuclear officer of UE in 2008. | ||||
Richard J. Mark | Senior Vice President (UE) | |||
| Mark joined Ameren Services in 2002 as vice president of customer service. In 2003, he was elected vice president of governmental policy and consumer affairs at Ameren Services, with responsibility for government affairs, economic development and community relations for Ameren’s operating utility companies. He was elected senior vice president, | ||||
Michael L. Moehn | Senior Vice President (Ameren Services) | |||
| Moehn joined Ameren Services in 2000. He was named director of Ameren Services’ corporate modeling and transaction support in 2001 and elected vice president of business services for | ||||
| ||||
Charles D. Naslund | ||||
| Naslund joined UE in 1974. He was elected vice president of power operations at UE in 1999, vice president of Ameren Services in 2000 and vice president of nuclear operations at UE in 2004. He relinquished his position at Ameren Services in 2001. Naslund was elected senior vice president and chief nuclear officer at UE in 2005. In 2008, he was elected chairman, president and chief executive officer of Resources Company and chairman and president of Genco. Naslund relinquished his | ||||
| Name | Age | Positions and Offices Held | ||
Andrew M. Serri | President and Chief Executive Officer (Marketing Company) | |||
| Serri joined Marketing Company as vice president of sales and marketing in 2000. He was elected vice president of marketing and trading of Ameren Services in 2004, before being elected president and chief executive officer of Marketing Company that same year. He relinquished his position at Ameren Services in 2007. | ||||
Steven R. Sullivan | 50 | Chairman, President and Chief Executive Officer (Resources Company) and Chairman and President (Genco) (Effective March 2, 2011) | ||
| Sullivan joined Ameren, UE, CIPS and Ameren Services in 1998 as vice president, general counsel and secretary. He added those positions at Genco in 2000. In 2003, Sullivan was elected vice president, general counsel and secretary of CILCO. He was elected to his present positions of senior vice president, general counsel and secretary of Ameren, UE, CIPS, Genco, CILCO and Ameren Services in 2003 and of IP in 2004. With the AIC Merger in 2010, Sullivan remained senior vice president, general counsel and secretary at AIC. Effective March 2, 2011, Sullivan will assume the positions of chairman, president and chief executive officer of Resources Company and chairman and president of Genco and relinquish his positions of senior vice president and general counsel of Ameren, UE, AIC, Genco and Ameren Services. Sullivan remains secretary of Ameren, UE, AIC, Genco and Ameren Services. | ||||
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the officers. Except for Karen C. Foss, and Adam C. Heflin, all of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
| ITEM 5. | MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. |
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 69,88166,808 on January 29, 2010.31, 2011. The following table presents the price ranges, closing prices, and dividends paiddeclared per Ameren common share for each quarter during 20092010 and 2008.2009.
| High | Low | Close | Dividends Paid | High | Low | Close | Dividends Declared | |||||||||||||||||||||
AEE 2010 Quarter Ended: | ||||||||||||||||||||||||||||
March 31 | $ | 28.27 | $ | 24.14 | $ | 26.08 | 38 1/2 | ¢ | ||||||||||||||||||||
June 30 | 26.92 | 23.09 | 23.77 | 38 1/2 | ||||||||||||||||||||||||
September 30 | 28.99 | 23.45 | 28.40 | 38 1/2 | ||||||||||||||||||||||||
December 31 | 29.89 | 27.65 | 28.19 | 38 1/2 | ||||||||||||||||||||||||
AEE 2009 Quarter Ended: | ||||||||||||||||||||||||||||
March 31 | $ | 35.35 | $ | 19.51 | $ | 23.19 | 38 1/2 | ¢ | $ | 35.35 | $ | 19.51 | $ | 23.19 | 38 1/2 | ¢ | ||||||||||||
June 30 | 25.25 | 21.75 | 24.89 | 38 1/2 | 25.25 | 21.75 | 24.89 | 38 1/2 | ||||||||||||||||||||
September 30 | 27.66 | 23.09 | 25.28 | 38 1/2 | 27.66 | 23.09 | 25.28 | 38 1/2 | ||||||||||||||||||||
December 31 | 28.67 | 23.78 | 27.95 | 38 1/2 | 28.67 | 23.78 | 27.95 | 38 1/2 | ||||||||||||||||||||
AEE 2008 Quarter Ended: | ||||||||||||||||||||||||||||
March 31 | $ | 54.29 | $ | 40.92 | $ | 44.04 | 63 1/2 | ¢ | ||||||||||||||||||||
June 30 | 48.39 | 41.34 | 42.23 | 63 1/2 | ||||||||||||||||||||||||
September 30 | 43.16 | 38.49 | 39.03 | 63 1/2 | ||||||||||||||||||||||||
December 31 | 39.15 | 25.51 | 33.26 | 63 1/2 | ||||||||||||||||||||||||
There is no trading market for the common stock of UE, CIPS, Genco, CILCO or IP.AIC and Genco. Ameren holds all outstanding common stock of UE CIPS and IP;AIC; Resources Company holds all outstanding common stock of Genco; and CILCORP holds all outstanding common stock of CILCO.Genco.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries during 20092010 and 2008:2009:
| (In millions) | 2009 | 2008 | 2010 Quarter Ended | 2009 Quarter Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Quarter Ended | Quarter Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Registrant | December 31 | September 30 | June 30 | March 31 | December 31 | September 30 | June 30 | March 31 | December 31 | September 30 | June 30 | March 31 | December 31 | September 30 | June 30 | March 31 | ||||||||||||||||||||||||||||||||||||||||
UE | $ | 5 | $ | 71 | $ | 47 | $ | 52 | $ | 71 | $ | 88 | $ | 28 | $ | 77 | $ | 59 | $ | 60 | $ | 58 | $ | 58 | $ | 5 | $ | 71 | $ | 47 | $ | 52 | ||||||||||||||||||||||||
CIPS | 35 | 12 | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||||||||||||||||||
AIC | 33 | 33 | 34 | 33 | 86 | 12 | - | - | ||||||||||||||||||||||||||||||||||||||||||||||||
Genco | - | - | - | - | 17 | - | 60 | 24 | - | - | - | - | - | - | 20 | 23 | ||||||||||||||||||||||||||||||||||||||||
CILCO | 20 | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||||||||||||||||||
IP | 31 | - | - | - | 15 | 15 | 15 | 15 | ||||||||||||||||||||||||||||||||||||||||||||||||
Nonregistrants | - | - | 35 | 30 | 32 | 30 | 30 | 17 | - | - | - | - | - | - | 15 | 7 | ||||||||||||||||||||||||||||||||||||||||
Ameren | $ | 91 | $ | 83 | $ | 82 | $ | 82 | $ | 135 | $ | 133 | $ | 133 | $ | 133 | $ | 92 | $ | 93 | $ | 92 | $ | 91 | $ | 91 | $ | 83 | $ | 82 | $ | 82 | ||||||||||||||||||||||||
On February 12, 2010,9, 2011, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 38.5 cents per share. The common share dividend is payable March 31, 2010,2011, to stockholders of record on March 10, 2010.9, 2011.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.
Purchase of Equity Securities
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) | (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 Plans or Programs | |||||
October 1 – October 31, 2009 | - | $ | - | - | - | ||||
November 1 – November 30, 2009 | 2,368 | 25.77 | - | - | |||||
December 1 – December 31, 2009 | 5,928 | 27.95 | - | - | |||||
Total | 8,296 | $ | 27.33 | - | - | ||||
| Period | (a) Total Number of Shares (or Units) | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) May Yet Be Purchased Under the Plans or Programs | ||||||||||||
October 1 – October 31, 2010 | 948 | $ | 29.23 | - | - | |||||||||||
November 1 – November 30, 2010 | - | - | - | - | ||||||||||||
December 1 – December 31, 2010 | - | - | - | - | ||||||||||||
Total | 948 | $ | 29.23 | - | - | |||||||||||
| (a) |
NoneThe following table presents AIC’s purchases of the other registrantsequity securities reportable under Item 703 of Regulation S-K:
| Period | (a) Total Number of Shares (or Units) | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) May Yet Be Purchased Under the Plans or Programs | ||||||||||||
October 1 – October 31, 2010 | - | $ | - | - | - | |||||||||||
November 1 – November 30, 2010 | 68 | 73.66 | - | - | ||||||||||||
December 1 – December 31, 2010 | - | - | - | - | ||||||||||||
Total | 68 | $ | 73.66 | - | - | |||||||||||
| (a) | The shares of CIPS preferred stock were purchased by AIC as a result of CIPS’ preferred stockholders exercising their dissenters’ rights under Illinois law. |
UE and Genco did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 20092010 to December 31, 2009.2010.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 2009.2010. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI Index), which comprises most investor-owned electric utilities in the United States. The comparison assumes that $100 was invested on December 31, 2004,2005, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
| December 31, | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 | ||||||||||||||||||||||||||||||
Ameren | $ | 100 | $ | 107.26 | $ | 118.11 | $ | 125.12 | $ | 81.84 | $ | 73.08 | $ | 100 | $ | 110.11 | $ | 116.65 | $ | 76.30 | $ | 68.13 | $ | 72.80 | ||||||||||||||||||
S&P 500 Index | 100 | 104.91 | 121.48 | 128.14 | 80.73 | 102.09 | 100 | 115.79 | 122.15 | 76.95 | 97.31 | 111.97 | ||||||||||||||||||||||||||||||
EEI Index | 100 | 116.05 | 140.14 | 163.35 | 121.04 | 134.01 | 100 | 120.76 | 140.76 | 104.30 | 115.47 | 123.60 | ||||||||||||||||||||||||||||||
Ameren management cautions that the stock price performance shown in the graph above should not be considered indicative of potential future stock price performance.
| ITEM 6. | SELECTED FINANCIAL DATA. |
For the years ended December 31, (In millions, except per share amounts) | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||
Ameren: | ||||||||||||||||
Operating revenues(a) | $ | 7,090 | $ | 7,839 | $ | 7,562 | $ | 6,895 | $ | 6,780 | ||||||
Operating income(a) | 1,416 | 1,362 | 1,359 | 1,188 | 1,284 | |||||||||||
Net income attributable to Ameren Corporation(a) | 612 | 605 | 618 | 547 | 606 | (b) | ||||||||||
Common stock dividends | 338 | 534 | 527 | 522 | 511 | |||||||||||
Earnings per share – basic and diluted(a) | 2.78 | 2.88 | 2.98 | 2.66 | 3.02 | (b) | ||||||||||
Common stock dividends per share | 1.54 | 2.54 | 2.54 | 2.54 | 2.54 | |||||||||||
As of December 31: | ||||||||||||||||
Total assets | $ | 23,790 | $ | 22,671 | $ | 20,752 | $ | 19,662 | $ | 18,171 | ||||||
Long-term debt, excluding current maturities | 7,113 | 6,554 | 5,689 | 5,285 | 5,354 | |||||||||||
Preferred stock subject to mandatory redemption | - | - | 16 | 17 | 19 | |||||||||||
Total Ameren Corporation stockholders’ equity | 7,853 | 6,963 | 6,752 | 6,583 | 6,364 | |||||||||||
UE: | ||||||||||||||||
Operating revenues | $ | 2,874 | $ | 2,960 | $ | 2,961 | $ | 2,823 | $ | 2,889 | ||||||
Operating income | 566 | 514 | 590 | 620 | 640 | |||||||||||
Net income available to common stockholder | 259 | 245 | 336 | 343 | 346 | |||||||||||
Dividends to parent | 175 | 264 | 267 | 249 | 280 | |||||||||||
As of December 31: | ||||||||||||||||
Total assets | $ | 12,301 | $ | 11,529 | $ | 10,903 | $ | 10,290 | $ | 9,277 | ||||||
Long-term debt, excluding current maturities | 4,018 | 3,673 | 3,208 | 2,934 | 2,698 | |||||||||||
Total stockholders’ equity | 4,057 | 3,562 | 3,601 | 3,153 | 3,016 | |||||||||||
CIPS: | ||||||||||||||||
Operating revenues | $ | 869 | $ | 982 | $ | 1,005 | $ | 954 | $ | 934 | ||||||
Operating income | 68 | 42 | 49 | 69 | 85 | |||||||||||
Net income available to common stockholder | 26 | 12 | 14 | 35 | 41 | |||||||||||
Dividends to parent | 47 | - | 40 | 50 | 35 | |||||||||||
As of December 31: | ||||||||||||||||
Total assets | $ | 1,965 | $ | 1,920 | $ | 1,866 | $ | 1,861 | $ | 1,784 | ||||||
Long-term debt, excluding current maturities | 421 | 421 | 456 | 471 | 410 | |||||||||||
Total stockholders’ equity | 574 | 529 | 517 | 543 | 569 | |||||||||||
Genco: | ||||||||||||||||
Operating revenues | $ | 850 | $ | 908 | $ | 876 | $ | 992 | $ | 1,038 | ||||||
Operating income | 310 | 330 | 258 | 131 | 257 | |||||||||||
Net income | 155 | 175 | 125 | 49 | 97 | (b) | ||||||||||
Dividends to parent | - | 101 | 113 | 113 | 88 | |||||||||||
As of December 31: | ||||||||||||||||
Total assets | $ | 2,535 | $ | 2,244 | $ | 1,968 | $ | 1,850 | $ | 1,811 | ||||||
Long-term debt, excluding current maturities | 823 | 774 | 474 | 474 | 474 | |||||||||||
Subordinated intercompany notes (current and long-term) | 45 | 87 | 126 | 163 | 197 | |||||||||||
Total stockholder’s equity | 862 | 695 | 648 | 563 | 444 | |||||||||||
CILCO: | ||||||||||||||||
Operating revenues | $ | 1,082 | $ | 1,147 | $ | 1,011 | $ | 747 | $ | 742 | ||||||
Operating income | 252 | 132 | 143 | 78 | 63 | |||||||||||
Net income available to common stockholder | 134 | 68 | 74 | 45 | 24 | (b) | ||||||||||
Dividends to parent | 20 | - | - | 65 | 20 | |||||||||||
As of December 31: | ||||||||||||||||
Total assets | $ | 2,382 | $ | 2,296 | $ | 1,867 | $ | 1,656 | $ | 1,557 | ||||||
Long-term debt, excluding current maturities | 279 | 279 | 148 | 148 | 122 | |||||||||||
Preferred stock subject to mandatory redemption | - | - | 16 | 17 | 19 | |||||||||||
Total stockholders’ equity | 855 | 684 | 622 | 535 | 562 | |||||||||||
IP: | ||||||||||||||||
Operating revenues | $ | 1,504 | $ | 1,696 | $ | 1,646 | $ | 1,694 | $ | 1,653 | ||||||
Operating income | 230 | 103 | 109 | 141 | 202 | |||||||||||
Net income available to common stockholder | 77 | 3 | 24 | 55 | 95 | |||||||||||
Dividends to parent | 31 | 60 | 61 | - | 76 | |||||||||||
As of December 31: | ||||||||||||||||
Total assets | $ | 3,942 | $ | 3,770 | $ | 3,331 | $ | 3,227 | $ | 3,056 | ||||||
Long-term debt, excluding current maturities | 1,147 | 1,150 | 1,014 | 772 | 704 | |||||||||||
Long-term debt to IP SPT, excluding current maturities | - | - | - | 92 | 184 | |||||||||||
Total stockholders’ equity | 1,451 | 1,251 | 1,308 | 1,346 | 1,287 | |||||||||||
For the years ended December 31, (In millions, except per share amounts) Ameren: Operating revenues(a) Operating income(a)(b) Net income attributable to Ameren Corporation(a) Common stock dividends Earnings per share – basic and diluted(a) Common stock dividends per share As of December 31: Total assets Long-term debt, excluding current maturities Preferred stock subject to mandatory redemption Total Ameren Corporation stockholders’ equity UE: Operating revenues Operating income Net income available to common stockholder Dividends to parent As of December 31: Total assets Long-term debt, excluding current maturities Total stockholders’ equity AIC: Operating revenues Operating income Income from continuing operations Net income available to common stockholder Dividends to parent As of December 31: Total assets(c) Long-term debt, excluding current maturities Preferred stock subject to mandatory redemption Total stockholders’ equity Genco: Operating revenues Operating income(b) Net income (loss) attributable to Ameren Energy Generating Company Dividends to parent As of December 31: Total assets Long-term debt, excluding current maturities Subordinated intercompany notes (current) Total Ameren Energy Generating Company stockholder’s equity 2010 2009 2008 2007 2006 $ 7,638 $ 7,135 $ 7,869 $ 7,562 $ 6,895 916 1,416 1,362 1,359 1,188 139 612 605 618 547 368 338 534 527 522 0.58 2.78 2.88 2.98 2.66 1.54 1.54 2.54 2.54 2.54 $ 23,515 $ 23,702 $ 22,671 $ 20,752 $ 19,662 6,853 7,111 6,554 5,689 5,285 - - - 16 17 7,730 7,856 6,963 6,752 6,583 $ 3,197 $ 2,874 $ 2,960 $ 2,961 $ 2,823 711 566 514 590 620 364 259 245 336 343 235 175 264 267 249 $ 12,504 $ 12,219 $ 11,529 $ 10,903 $ 10,290 3,949 4,018 3,673 3,208 2,934 4,153 4,057 3,562 3,601 3,153 $ 3,014 $ 2,984 $ 3,508 $ 3,380 $ 3,353 498 363 191 195 272 212 133 41 56 124 248 241 87 114 137 133 98 60 101 115 $ 7,406 $ 8,298 $ 8,023 $ 7,101 $ 6,778 1,657 1,847 1,850 1,618 1,368 - - - 16 17 2,576 3,072 2,655 2,635 2,612 $ 1,126 $ 1,148 $ 1,422 $ 1,298 $ 1,359 62 324 551 468 346 (39 ) 160 286 230 150 - 43 221 199 223 $ 2,611 $ 2,920 $ 2,592 $ 2,288 $ 2,150 824 823 774 474 474 - 176 145 172 206 998 1,004 868 857 740
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) |
| (c) | Includes total assets from |
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
Ameren Executive Summary
Operations
During 2010, disciplined cost management, strong customer sales and rate relief allowed Ameren to overcome the financial impact of weak wholesale power prices and higher fuel and related transportation costs. Ameren also returned its newly rebuilt Taum Sauk pumped-storage hydroelectric facility to service; installed major environmental controls at two coal-fired plants; simplified its corporate structure by merging its Illinois delivery utilities into a single company and by moving AERG under Resources Company, where Ameren’s other Merchant Generation assets reside; launched plans for growing its transmission business; and improved its safety and customer satisfaction performance.
In 2010, UE and AIC were authorized to increase rates. UE obtained approval from the MoPSC in May 2010 to increase electric rates by $230 million annually and then in February 2011 to increase natural gas rates by $9 million annually. These rate increases have been necessary to recover the cost of infrastructure investments, higher fuel costs, and other operating expenses. In November 2010, AIC received an order on rehearing from the ICC on issues arising from the ICC’s amended order of May 2010. The rehearing order authorized an additional $25 million annual rate increase, bringing the total annual revenue increase to $40 million.
Ongoing litigation exists surrounding appeals of certain aspects of UE’s two most recent electric rate orders. In February 2011, the Missouri Office of Public Counsel (MoOPC) made a filing with the MoPSC in which the MoOPC argued that a December 20, 2010 stay, granted by the Circuit Court of Cole County, Missouri (Circuit Court), of UE’s 2010 electric rate increase, as it applies to four industrial customers, should apply to all UE customers. UE disagrees with the MoOPC’s argument. On December 20, 2010, the Circuit Court found that four industrial customers appealing UE’s 2010 electric rate increase could pay the portions of their bills, representing increases from previously approved levels, into the Circuit Court’s registry pending resolution of these appeals. This effectively stayed the rate increases for those parties. UE disagrees with the Circuit Court’s ruling granting these industrial customers a stay. At this time, UE does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 Missouri electric rate orders are probable of refund to UE’s customers.
UE and AIC also have pending rate cases. In September 2010, UE filed for a $263 million annual electric rate increase. On February 8, 2011, other parties filed their initial testimony. The staff of the MoPSC recommended a rate increase of $45 million to $99 million. A key reason that the staff’s recommendation is considerably lower than
UE’s request is the staff’s use of a return on equity range of 8.25% to 9.25%, compared to UE’s request of 10.9%. While UE strongly disagrees with elements of the MoPSC’s staff and other parties’ initial recommendations, this case is still in its early stages with a decision not expected until July 2011. On February 18, 2011, AIC filed an electric and natural gas delivery rate case with the ICC requesting a $111 million aggregate increase in annual revenues. This request is based on a future test year ending December 31, 2012, with an ICC decision expected in January 2012. The use of a future test year is designed to better match AIC’s 2012 rate levels to its expected 2012 costs, reducing regulatory lag and providing an improved opportunity to earn a fair return on investment. In addition to these regulatory developments in Ameren’s state jurisdictions, Ameren is awaiting action from FERC on its August 2010 filing for pre-approval of supportive rate treatment for its proposed Grand Rivers regional electric transmission projects.
2011 could be a pivotal year in environmental regulation. The EPA is scheduled to finalize its proposed CATR, which is aimed at reducing emissions of SO2 and NOx. Further, the EPA is scheduled to propose requirements for retrofitting power plants with MACT to reduce hazardous air pollutants such as mercury and acid gases, cooling water standards, and rules for reducing greenhouse gas emissions. These rules are expected to impose additional costs that could be substantial to Ameren and, therefore, its customers. Ameren is continually evaluating these changing environmental standards for their impact on its power plants and is focused on meeting these requirements in the most cost effective manner possible.
Ameren remains focused on earning fair returns on investments at its rate-regulated utilities by seeking consistent, constructive regulatory outcomes, including mechanisms that reduce regulatory lag, like the use of a future test year in AIC’s pending electric and natural gas rate case filing. Further, Ameren continues to focus on disciplined cost management, including aligning its spending with the level of rates authorized by its regulators. In 2010, Ameren’s rate-regulated utilities milder weathernarrowed the gap between their core earnings and the economic slowdown led to a 3% decrease in kilowatthour sales to residentialtheir allowed returns on equity by almost three percent and commercial customers in 2009, compared with 2008. However, this sales decline was smaller, an estimated 1%,by more than one percent on a weather-normalized basis. The weak economy also ledprojected 2011 return levels are expected to a decline in kilowatthour sales by Ameren’sbe below what is currently authorized and what Ameren considers appropriate. Ameren believes its pending rate cases, cost control efforts and its ongoing work to improve its regulatory frameworks will allow its rate-regulated utilities to their industrial customers. These sales declined 11% in 2009, compared with 2008, excludingfurther narrow the impact of reduced sales to Noranda’s smelter plant in New Madrid, Missouri. Noranda’s plant sustained damage because of a power interruption on non-Ameren-owned power lines during a severe ice storm in January 2009. As a result, the smelter’s load was sharply reduced but has been rising steadily as repairs have been made to the smelter plant’s production lines, with full production expected to be reached in the second quarter of 2010. Electric sales to industrial customers, including Noranda, declined 17% in 2009, compared with 2008.gap between earned and allowed returns.
For several years, Ameren’s rate-regulated utility businesses have been earning returns on investment that are well below their authorized levels, in part, due to regulatory lag. Ameren is focused on improving earnings to levels that represent fair returns on its rate-regulated investments. Ameren has rate cases pending in both its Illinois and Missouri jurisdictions. Ameren is seeking revenue levels that reflect the significant investments it has made in electric and gas utility infrastructure to improve reliability. Ameren is also seeking recovery of higher financing costs and, in Missouri, rising net fuel costs. The Ameren Illinois Utilities are currently requesting a $130 million aggregate annual increase in base electric and natural gas delivery rates. The staff of the ICC currently supports a $46 million annual revenue increase. The staff’s lower revenue amount reflects its lower recommended return on equity of 10.1% compared to the Ameren Illinois Utilities’ request of 11.5%, on a rate base weighted basis, and use of a lower pension and benefits expense level, among other things. In February 2010, administrative law judges issued a consolidated proposed order, which included a recommended revenue increase for electric delivery service for the Ameren Illinois Utilities of $66 million in the aggregate (CIPS – $26 million increase, CILCO – $6 million increase, and IP - $34 million increase) and a recommended revenue net decrease for natural gas delivery service of $10 million in the aggregate (CIPS – $1 million increase, CILCO – $6 million decrease, and IP - - $5 million decrease). The ICC is not bound by the proposed order issued by the administrative law judges. New rates should be effective by early May 2010.
UE filed a request with the MoPSC in July 2009 for an annual electric service rate increase of $402 million. More than half of the request was for anticipated higher net fuel costs. These increased net fuel costs would have been eligible for recovery through the FAC absent this filing. The MoPSC staff, in its direct testimony in the rate case, recommended an annual electric service rate increase of $218 million to $251 million, with approximately $214 million of this related to higher net fuel costs. The staff’s lower revenue amount reflects its lower recommended return on equity range of 9.0% to 9.7%, which was lower than UE’s initial request of 11.5%. The staff’s revenue amount also incorporated lower depreciation, plant maintenance and financing cost levels, as well as other adjustments. The staff testimony reflects continuation of the FAC and the pension and postretirement benefit cost trackers and a modified environmental cost recovery mechanism. Other parties filed testimony in the rate case, including a group of large industrial customers and the Office of Public Counsel. The Missouri Office of Public Counsel recommended a return on equity of 10.2%. The large industrial customers recommended a rate increase of $139 million, which included a $181 million increase related to net fuel costs. Their lower revenue requirement reflects their lower recommended return on equity of 10%, the use of significantly lower depreciation rates and plant maintenance expenses, as well as lower financing costs, among other things. The large industrial customers’ testimony reflects continuation of the FAC, as well as a modified approach for the accounting and recovery of environmental costs. In February 2010, UE filed its rebuttal testimony in this rate case, which included, among other things, a modification of its recommended return on equity to 10.8%. It is anticipated that certain major changes to revenues, expenses, rate base, and capital structure will be trued-up through January 31, 2010, in a March 2010 UE update. A MoPSC order is expected by late May 2010 with new rates expected to be effective in late June 2010.
Current lower power prices are very much linked to weak economic conditions. Weak economic conditions have reduced the demand for power and other energy commodities. Ameren believes that when the economy recovers, these prices should rise. In the meantime, Ameren continues to look for opportunities to prudently reduce operating and capital spending in the Merchant Generation business, as well as protect and enhance margins. Ameren’s Merchant Generation business output is significantly hedged over the next few years. Such hedging protects credit quality and reduces earnings and cash flow volatility. In addition, Ameren continues to focus on providing value-added electricity products to the market.
Leveraging Ameren’s competitive merchant generating assets, Marketing Company has a track record of enhancing margins through sales to wholesale and retail customers. To strengthen Merchant Generation’s ability to successfully weather current lower power prices, Ameren has reduced plannedaggressively manage operating and capital spending, improving the cash flow outlook for the Merchant Generation business. Ameren continues to evaluate Merchant Generation’s spending plans in lightcosts so that this business remains stable during this period of changing technologies,low power prices and delivered fuel costs in orderwell-positioned to ensure that the lowestbenefit from an eventual expected power price recovery. In 2010, Ameren’s Merchant Generation business further lowered its cost options are identified in terms of both capital and ongoing operating costs.structure to enhance its long-term competitiveness.
Earnings
Ameren reported net income of $139 million, or 58 cents per share, for 2010 compared with net income of $612 million, or $2.78 per share, for 2009 compared with net income of $605 million, or $2.88 per share, in 2008. Factors2009. The main factor contributing to the 10 cent decline in earnings in 2010 compared with 2009 was noncash goodwill and other asset impairment charges of $522 million, or $2.19 per share, recorded in 2009 compared with 2008 included lower electricity and natural gas sales2010 related to Ameren’s Merchant Generation business. These charges reflected a decline in the value of Ameren’s rate-regulated businesses and lower margins in its Merchant Generation business, principally as a result of weak economic conditions, mildersustained lower power prices and the potential enactment of more stringent environmental regulations. Ameren’s earnings were also lower in 2010, compared with 2009, weather and, in the Missouri Regulated business, the impactbecause of reduced sales to Noranda. Higher depreciation and interest expense, the absence in 2009 of the benefit of a lump-sum payment from a coal supplier for higher fuel costs in 2009Merchant Generation margins, as a result of a premature mine closurelower realized power prices and contract termination,higher fuel and an increased average number of common shares outstanding also affected comparative results.related transportation costs, and higher depreciation and amortization expense. Offsetting factors included higher electricity sales, which benefited from warmer summer weather, new utility rates in Missouri and Illinois, lower financing costs, and Missouri, favorable unrealized MTM activity on derivatives, and lower operations and maintenance expenses due, in part, to the absence of a refueling and maintenance outage at the Callaway nuclear plant in 2009.disciplined cost management.
Liquidity
As a resultCash flows from operations of turmoil in the$1.8 billion were used to pay dividends to common stockholders of $368 million and to fund capital and credit markets in 2008 and 2009, we sought to improve our liquidity position. We replaced and extended the expirationexpenditures of our credit facilities and sought to reduce our reliance on borrowings from these credit facilities, increase cash balances and increase the equity content of our capitalization. We also sought to eliminate debt at CILCORP as a step in simplifying our organizational structure. In addition, Ameren also reduced planned spending, headcount and capital investment across the company to mitigate the negative impact on sales of a weak economy and related power prices.$1.0 billion. At December 31, 2009,2010, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $1.9 billion, which was $0.6 billion more than it hadequivalent to the amount of available liquidity at the end of 2008. Cash flows from operations of $2.0 billion in 2009 at Ameren, along with other funds, were used to pay dividends to common shareholders of $338 million and to fund capital expenditures of $1.7 billion.December 31, 2009.
Capital Spending
DuringCapital expenditures decreased $673 million in 2010 compared with 2009. The reduction was a result of fewer planned expenditures for the distribution system and power plant improvements, less expenditures required to repair severe storm damage, and the completion of power plant scrubber projects in the Merchant Generation business during 2009 Ameren was able to significantly defer or reduce plannedand early 2010.
From 2011 through 2015, cumulative capital spending including spending for environmental compliance, compared with previous plans.
Between 2010 and 2017, Ameren expects that certain Ameren Companies will be requiredis projected to make cumulative investments ofrange between $1.6$6.4 billion and $1.9 billion$8.2 billion. Much of this spending is at Ameren’s rate-regulated utilities, including $265 million at ATX to retrofit theirexpand its electric transmission assets. This five-year plan also includes significant investments in environmental projects, including the cost of installing scrubbers for two units of Genco’s Newton plant and for two units of a UE plant.
In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco, that operate coal-fired power plants with pollution control equipment in compliance with existing emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and higher ongoing operating expenses. Approximately 20%plants. Significant new rules already proposed or promulgated within the past year include the regulation of this investment is expected to be in Ameren’s Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers, but subject to prudency reviews.
Initiatives to limit greenhouse gas emissions and to address global climate change are subject to active consideration in the U.S. Congress. Although we cannot predict the date of enactment or the requirements of any future climate change legislation or regulations, we believe it is possible that some form of federal legislation or regulations to control emissions of greenhouse gases will become law during President Obama’s administration. Potential impacts from the climate change legislation could vary depending upon proposed COemissions; revised ambient air quality standards for SO2 and NOx emissions increasing the
stringency of the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO2 and NOx emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act, that could require significant capital expenditures such as new water intake structures or cooling towers at our power plants; NSPS and emission limits,guidelines for greenhouse gas emissions applicable to new and existing electric generating units; and a MACT standard for the control of hazardous air pollutants, such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of those limits,these future regulations are unknown, the methodcombined effects of distributing allowances, the degree to which offsets are allowednew and available, and provisions for cost containment measures. Future federal and state legislation orproposed environmental regulations that mandate limits on the emission of greenhouse gases wouldmay result in significant increases in capital expenditures over the next five to eight years for Ameren, UE and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI and other similarly-situated electric power generators to close some coal-fired facilities, and it could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s (through AERG) and EEI’s results of operations, financial position, or liquidity.Genco.
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, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for a detailed description of our principal subsidiaries.
| Ÿ | UE operates a rate-regulated electric generation, transmission and distribution business, and a |
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| Ÿ | Genco operates a merchant electric generation business in Illinois and Missouri. Genco has an 80% ownership interest in EEI. |
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger, pursuant to the terms of the agreement, dated as of April 13, 2010. Upon consummation of the AIC Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The AIC Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in AIC included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. AIC accounted for the AERG distribution as a spinoff. AIC transferred AERG to Ameren based on AERG’s carrying value. AIC determined that the operating results of AERG qualified for discontinued operations presentation; therefore, AIC has segregated AERG’s operating results and presented them separately as discontinued operations for all periods prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operations remained classified as continuing operations. See Note 16 – Corporate Reorganization and Discontinued Operations under Part II, Item 8, for additional information. Ameren has various other subsidiaries responsible for the marketing of power, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. Effective January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior-period financial statements to be retrospectively combined for all periods presented. Consequently, Genco’s prior-period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco. Ameren and Genco consolidate EEI for financial reporting purposes. See Note 14 – Related Party Transactions under Part II, Item 8, for additional information. |
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The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are expressed in millions, unless otherwise indicated.
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 year.outstanding.
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. Merchant 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 service businesses, purchased power cost recovery mechanisms for our Illinois electric delivery service businesses, and a FAC for our Missouri electric utility business. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, 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.Illinois. 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 and the level of purchased power
costs, operatingoperations and administrativemaintenance costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Earnings Summary
Net income attributable to Ameren Corporation was $139 million, or $0.58 per share, for 2010, $612 million, or $2.78 per share, for 2009, and $605 million, or $2.88 per share, for 2008,2008.
2010 versus 2009
Net income attributable to Ameren Corporation decreased $473 million and $618 million, or $2.98its earnings per share for 2007.decreased $2.20 in 2010 compared with 2009. Net income attributable to Ameren Corporation increased in the Ameren Missouri and Ameren Illinois segments by $105 million and $81 million, respectively, in 2010 compared with 2009, while net income attributable to Ameren Corporation in the Merchant Generation segment decreased by $656 million in 2010 compared with 2009.
Compared with 2009 earnings per share, 2010 earnings were negatively affected by:
| Ÿ | the 2010 impairment of goodwill, intangible assets, and long-lived assets within the Merchant Generation segment due to the sustained decline in market prices for electricity, industry market multiples becoming observable at lower levels than previously estimated, and potentially more stringent environmental regulations ($2.19 per share); |
| Ÿ | lower realized electric margins in the Merchant Generation segment largely due to lower realized revenue per megawatthour sold and higher fuel and related transportation costs (79 cents per share). This amount excludes the unfavorable impacts of net unrealized MTM activity on nonqualifying power hedges discussed below. See Outlook for expected trends in future coal, transportation and power prices; |
| Ÿ | higher dilution (23 cents per share) caused by an increase in the average number of common shares outstanding, largely because of a September 2009 common stock issuance, the proceeds of which were used to make investments in Ameren’s rate-regulated utilities. The impact of dilution was offset by higher earned returns on investments at Ameren’s rate-regulated utilities and lower financing costs; |
| Ÿ | costs associated with the Callaway nuclear plant’s scheduled refueling and maintenance outage in 2010. There was no Callaway refueling and maintenance outage in 2009 (12 cents per share); |
| Ÿ | increased depreciation and amortization expenses, primarily due to capital additions placed in-service at the Merchant Generation segment in late 2009 and early 2010, excluding the impacts at UE of the May 2010 MoPSC electric rate order discussed below (9 cents per share); |
| Ÿ | a reduced gain between years from net unrealized MTM activity on nonqualifying power hedges and from changes in the market value of investments used to support Ameren’s deferred compensation plans (6 cents per share); and |
| Ÿ | the impact of a federal tax change resulting from a U.S. health care reform bill that was enacted in 2010 (6 cents per share). |
Compared with 2009 earnings per share, 2010 earnings were favorably affected by:
| Ÿ | the impact of weather conditions on energy demand (estimated at 40 cents per share); |
| Ÿ | higher UE electric rates pursuant to the MoPSC 2009 and 2010 electric rate orders effective March 1, 2009, and June 21, 2010, respectively, offset by the adoption of the life span depreciation methodology and increased regulatory asset amortization as directed by the MoPSC 2010 electric rate order (27 cents per share); |
| Ÿ | the favorable impact on electric and natural gas margins in our rate-regulated businesses from higher weather-normalized sales volumes (exclusive of higher sales to Noranda discussed below), largely due to |
improved economic conditions and higher wholesale sales margins at UE because of additional customers and higher-priced wholesale sales contracts, among other things (20 cents per share); |
| Ÿ | increased UE sales to Noranda as its smelter plant gradually returned to full capacity by the end of the first quarter of 2010 after a January 2009 severe ice storm significantly reduced the plant’s capacity (11 cents per share); |
| Ÿ | a reduction in financing expenses caused primarily by an increase in the allowance for funds used during construction at UE for the installation of two scrubbers at its Sioux plant (10 cents per share); |
| Ÿ | higher AIC electric and natural gas net delivery rates pursuant to the ICC 2010 rate orders, which became effective in May and November 2010 (9 cents per share); and |
| Ÿ | reduced charges in 2010 relating to workforce reductions through voluntary and involuntary separation programs (4 cents per share). |
The cents per share information presented above is based on average shares outstanding in 2009.
2009 versus 2008
Net income attributable to Ameren Corporation increased $7 million and its earnings per share decreased 10 cents in 2009 compared with 2008. Net income attributable to Ameren Corporation increased in the Ameren Illinois Regulated and Ameren Missouri Regulated segments by $92 million and $25 million, respectively, in 2009 compared with 2008, while net income attributable to Ameren Corporation in the Merchant Generation segment decreased by $105 million in 2009 compared with 2008.
Compared with 2008 earnings per share, 2009 earnings were negatively affected by:
| Ÿ | higher dilution and financing costs caused by an increase in the average number of common shares outstanding, largely because of a September 2009 common stock issuance (31 cents per share); |
| Ÿ | the impact on electric and natural gas margins in our rate-regulated businesses of higher net fuel costs at UE resulting from higher coal and related transportation costs, and lower sales prices for excess power, and lower demand (exclusive of weather impacts), among other things (30 cents per share); |
| Ÿ | the absence in 2009 of the benefit 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 2009 due to the premature closure of an Illinois mine and contract termination (18 cents per share); |
| Ÿ | the impact of milder weather conditions on energy demand (estimated at 15 cents per share); |
| Ÿ | increased depreciation and amortization expenses primarily because of capital additions at UE and at the Merchant Generation segment and additional |
amortization of UE’s regulatory assets as a result of the MoPSC’s January 2009 electric rate order (12 cents per share); |
| Ÿ | reduced sales to Noranda |
| Ÿ | the absence in 2009 of a MoPSC rate order establishing two separate regulatory assets for previously incurred storm and MISO related costs (11 cents per share); |
| Ÿ | increased expense related to |
| Ÿ | increased taxes other than income taxes, primarily because of higher property taxes (6 cents per share); |
| Ÿ | lower realized electric margins in the Merchant Generation segment largely due to lower sales volumes and higher fuel and related transportation costs (5 cents per share); and |
| Ÿ | increased distribution system reliability expenditures (5 cents per share). |
Compared with 2008 earnings per share, 2009 earnings were favorably affected by:
| Ÿ | higher AIC electric and natural gas delivery |
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| Ÿ | higher UE electric rates |
| Ÿ | favorable net unrealized MTM activity on derivatives and from changes in the market value of investments used to support Ameren’s deferred compensation plans (21 cents per share); |
| Ÿ | decreased plant operations and maintenance expense because less work was undertaken as a result of cost-containment initiatives in response to weak economic conditions (15 cents per share); |
| Ÿ | the absence in 2009 of a Callaway nuclear plant refueling and maintenance outage (9 cents per share); |
| Ÿ | the absence in 2009 of asset impairment charges recorded to adjust the carrying value of |
| Ÿ | the reduced impact in 2009 of the electric rate relief and customer assistance programs provided to certain |
The cents per share information presented above is based on average shares outstanding in 2008.
Net income attributable toFor additional details regarding the Ameren Corporation decreased $13 millionCompanies’ results of operations, including explanations of Margins, Other Operations and its earnings per share decreased 10 cents in 2008 compared with 2007. Net income attributable to Ameren Corporation increased inMaintenance Expenses, Goodwill and Other Impairment Losses, Depreciation and Amortization, Taxes Other Than Income Taxes, Interest Charges, and Income Taxes, see the Merchant Generation segment by $71 million in 2008 compared with 2007, while net income attributable to Ameren Corporation in the Missouri Regulated and Illinois Regulated segments decreased by $47 million and $15 million, respectively. Other net income decreased $22 million in 2008 compared with 2007, primarily because of net unrealized MTM losses on nonqualifying hedges mainly related to fuel-related transactions and reduced interest and dividend income.major headings below.
Compared with 2007 earnings, 2008 earnings were negatively affected by:
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Compared with 2007 earnings, 2008 earnings were favorably affected by:
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The cents per share information presented above is based on average shares outstanding in 2007.
Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCOAIC and IP.Genco. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the years ended December 31, 2010, 2009 2008 and 2007:2008:
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||||
Net income (loss): | ||||||||||||||||||||||
UE(a) | $ | 259 | $ | 245 | $ | 336 | $ | 364 | $ | 259 | $ | 245 | ||||||||||
CIPS | 26 | 12 | 14 | |||||||||||||||||||
AIC(b) | 248 | 241 | 87 | |||||||||||||||||||
Genco | 155 | 175 | 125 | (39 | ) | 160 | 286 | |||||||||||||||
CILCO | 134 | 68 | 74 | |||||||||||||||||||
IP | 77 | 3 | 24 | |||||||||||||||||||
Other(b) | (39 | ) | 102 | 45 | ||||||||||||||||||
Other(c) | (434 | ) | (48 | ) | (13 | ) | ||||||||||||||||
Net income attributable to Ameren Corporation | $ | 612 | $ | 605 | $ | 618 | $ | 139 | $ | 612 | $ | 605 | ||||||||||
| (a) | Includes earnings from a 40% interest in EEI through February 29, 2008. |
| (b) | Includes AERG for all periods prior to October 1, 2010, when AIC distributed AERG stock to Ameren. |
| (c) | Includes earnings from other merchant generation |
Below is a table of income statement components by segment for the years ended December 31, 2010, 2009, 2008 and 2007:2008:
| 2010 | Ameren Missouri | Ameren Illinois | Merchant Generation | Other / Eliminations | Total | |||||||||||||||||||||||||||||||||||
Electric margins | $ | 2,233 | $ | 1,096 | $ | 780 | $ | (17 | ) | $ | 4,092 | |||||||||||||||||||||||||||||
Natural gas margins | 75 | 375 | - | (2 | ) | 448 | ||||||||||||||||||||||||||||||||||
Other revenues | 1 | - | - | (1 | ) | - | ||||||||||||||||||||||||||||||||||
Other operations and maintenance | (931 | ) | (635 | ) | (287 | ) | 32 | (1,821 | ) | |||||||||||||||||||||||||||||||
Goodwill and other impairment losses | - | - | (589 | ) | - | (589 | ) | |||||||||||||||||||||||||||||||||
Depreciation and amortization | (382 | ) | (210 | ) | (146 | ) | (27 | ) | (765 | ) | ||||||||||||||||||||||||||||||
Taxes other than income taxes | (285 | ) | (128 | ) | (26 | ) | (10 | ) | (449 | ) | ||||||||||||||||||||||||||||||
Other income and (expenses) | 70 | (6 | ) | 1 | (8 | ) | 57 | |||||||||||||||||||||||||||||||||
Interest charges | (213 | ) | (143 | ) | (133 | ) | (8 | ) | (497 | ) | ||||||||||||||||||||||||||||||
Income (taxes) benefit | (199 | ) | (137 | ) | (6 | ) | 17 | (325 | ) | |||||||||||||||||||||||||||||||
Net income (loss) | 369 | 212 | (406 | ) | (24 | ) | 151 | |||||||||||||||||||||||||||||||||
Noncontrolling interest and preferred dividends | (5 | ) | (4 | ) | (3 | ) | - | (12 | ) | |||||||||||||||||||||||||||||||
Net income (loss) attributable to Ameren Corporation | $ | 364 | $ | 208 | $ | (409 | ) | $ | (24 | ) | $ | 139 | ||||||||||||||||||||||||||||
| 2009 | Missouri Regulated | Illinois Regulated | Merchant Generation | Other / Eliminations | Total | |||||||||||||||||||||||||||||||||||
Electric margins | $ | 1,983 | $ | 886 | $ | 1,012 | $ | (22 | ) | $ | 3,859 | $ | 1,983 | $ | 917 | $ | 1,012 | $ | (22 | ) | $ | 3,890 | ||||||||||||||||||
Natural gas margins | 73 | 359 | - | - | 432 | 73 | 373 | - | - | 446 | ||||||||||||||||||||||||||||||
Other revenues | 4 | 4 | - | (8 | ) | - | 4 | 4 | - | (8 | ) | - | ||||||||||||||||||||||||||||
Other operations and maintenance | (880 | ) | (550 | ) | (340 | ) | 32 | (1,738 | ) | (880 | ) | (590 | ) | (333 | ) | 35 | (1,768 | ) | ||||||||||||||||||||||
Goodwill and other impairment losses | - | - | (7 | ) | - | (7 | ) | |||||||||||||||||||||||||||||||||
Depreciation and amortization | (357 | ) | (216 | ) | (126 | ) | (26 | ) | (725 | ) | (357 | ) | (216 | ) | (126 | ) | (26 | ) | (725 | ) | ||||||||||||||||||||
Taxes other than income taxes | (257 | ) | (125 | ) | (28 | ) | (2 | ) | (412 | ) | (257 | ) | (125 | ) | (28 | ) | (10 | ) | (420 | ) | ||||||||||||||||||||
Other income and (expenses) | 56 | 2 | 1 | (11 | ) | 48 | 56 | 2 | 1 | (11 | ) | 48 | ||||||||||||||||||||||||||||
Interest charges | (229 | ) | (153 | ) | (119 | ) | (7 | ) | (508 | ) | (229 | ) | (153 | ) | (119 | ) | (7 | ) | (508 | ) | ||||||||||||||||||||
Income (taxes) benefit | (128 | ) | (77 | ) | (151 | ) | 24 | (332 | ) | (128 | ) | (79 | ) | (151 | ) | 26 | (332 | ) | ||||||||||||||||||||||
Net income (loss) | 265 | 130 | 249 | (20 | ) | 624 | 265 | 133 | 249 | (23 | ) | 624 | ||||||||||||||||||||||||||||
Noncontrolling interest and preferred dividends | (6 | ) | (6 | ) | (2 | ) | 2 | (12 | ) | (6 | ) | (6 | ) | (2 | ) | 2 | (12 | ) | ||||||||||||||||||||||
Net income (loss) attributable to Ameren Corporation | $ | 259 | $ | 124 | $ | 247 | $ | (18 | ) | $ | 612 | $ | 259 | $ | 127 | $ | 247 | $ | (21 | ) | $ | 612 | ||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||
Electric margins | $ | 1,924 | $ | 817 | $ | 1,188 | $ | (47 | ) | $ | 3,882 | $ | 1,924 | $ | 837 | $ | 1,188 | $ | (47 | ) | $ | 3,902 | ||||||||||||||||||
Natural gas margins | 78 | 342 | - | (5 | ) | 415 | 78 | 351 | - | (4 | ) | 425 | ||||||||||||||||||||||||||||
Other revenues | 3 | - | - | (3 | ) | - | 3 | 1 | - | (4 | ) | - | ||||||||||||||||||||||||||||
Other operations and maintenance | (922 | ) | (627 | ) | (356 | ) | 48 | (1,857 | ) | (922 | ) | (653 | ) | (342 | ) | 55 | (1,862 | ) | ||||||||||||||||||||||
Goodwill and other impairment losses | - | - | (14 | ) | - | (14 | ) | |||||||||||||||||||||||||||||||||
Depreciation and amortization | (329 | ) | (219 | ) | (109 | ) | (28 | ) | (685 | ) | (329 | ) | (219 | ) | (109 | ) | (28 | ) | (685 | ) | ||||||||||||||||||||
Taxes other than income taxes | (240 | ) | (126 | ) | (26 | ) | (1 | ) | (393 | ) | (240 | ) | (126 | ) | (26 | ) | (12 | ) | (404 | ) | ||||||||||||||||||||
Other income and (expenses) | 53 | 11 | - | (15 | ) | 49 | 53 | 11 | - | (15 | ) | 49 | ||||||||||||||||||||||||||||
Interest charges | (193 | ) | (144 | ) | (99 | ) | (4 | ) | (440 | ) | (193 | ) | (145 | ) | (99 | ) | (3 | ) | (440 | ) | ||||||||||||||||||||
Income (taxes) benefit | (134 | ) | (16 | ) | (217 | ) | 40 | (327 | ) | (134 | ) | (16 | ) | (217 | ) | 40 | (327 | ) | ||||||||||||||||||||||
Net income (loss) | 240 | 38 | 381 | (15 | ) | 644 | 240 | 41 | 381 | (18 | ) | 644 | ||||||||||||||||||||||||||||
Noncontrolling interest and preferred dividends | (6 | ) | (6 | ) | (29 | ) | 2 | (39 | ) | (6 | ) | (6 | ) | (29 | ) | 2 | (39 | ) | ||||||||||||||||||||||
Net income (loss) attributable to Ameren Corporation | $ | 234 | $ | 32 | $ | 352 | $ | (13 | ) | $ | 605 | $ | 234 | $ | 35 | $ | 352 | $ | (16 | ) | $ | 605 | ||||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||||||
Electric margins | $ | 1,984 | $ | 759 | $ | 1,037 | $ | (51 | ) | $ | 3,729 | |||||||||||||||||||||||||||||
Natural gas margins | 70 | 317 | - | (8 | ) | 379 | ||||||||||||||||||||||||||||||||||
Other revenues | 2 | 3 | - | (5 | ) | - | ||||||||||||||||||||||||||||||||||
Other operations and maintenance | (900 | ) | (550 | ) | (313 | ) | 76 | (1,687 | ) | |||||||||||||||||||||||||||||||
Depreciation and amortization | (333 | ) | (217 | ) | (105 | ) | (26 | ) | (681 | ) | ||||||||||||||||||||||||||||||
Taxes other than income taxes | (234 | ) | (121 | ) | (25 | ) | (1 | ) | (381 | ) | ||||||||||||||||||||||||||||||
Other income and (expenses) | 35 | 20 | 3 | (8 | ) | 50 | ||||||||||||||||||||||||||||||||||
Interest charges | (194 | ) | (132 | ) | (107 | ) | 10 | (423 | ) | |||||||||||||||||||||||||||||||
Income (taxes) benefit | (143 | ) | (25 | ) | (182 | ) | 20 | (330 | ) | |||||||||||||||||||||||||||||||
Net income | 287 | 54 | 308 | 7 | 656 | |||||||||||||||||||||||||||||||||||
Noncontrolling interest and preferred dividends | (6 | ) | (7 | ) | (27 | ) | 2 | (38 | ) | |||||||||||||||||||||||||||||||
Net income attributable to Ameren Corporation | $ | 281 | $ | 47 | $ | 281 | $ | 9 | $ | 618 | ||||||||||||||||||||||||||||||
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2010, 2009, 2008, and 2007.2008. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural 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 they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
| 2009 versus 2008 | Ameren(a) | UE | CIPS | Genco | CILCO | IP | ||||||||||||||||||||||||||||||||||
| 2010 versus 2009 | Ameren(a) | UE | AIC | Genco | ||||||||||||||||||||||||||||||||||||
Electric revenue change: | ||||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate) | $ | (47 | ) | $ | (33 | ) | $ | (3 | ) | $ | - | $ | (4 | ) | $ | (7 | ) | |||||||||||||||||||||||
Effect of weather (estimate)(b) | $ | 174 | $ | 134 | $ | 40 | $ | - | ||||||||||||||||||||||||||||||||
Regulated rates: | ||||||||||||||||||||||||||||||||||||||||
Changes in base rates | 229 | 141 | 17 | - | (2 | ) | 73 | 203 | 162 | 41 | - | |||||||||||||||||||||||||||||
Noranda sales | (50 | ) | (50 | ) | - | - | - | - | 54 | 54 | - | - | ||||||||||||||||||||||||||||
Illinois pass-through power supply costs | (338 | ) | - | (89 | ) | (104 | ) | (145 | ) | 220 | - | (83 | ) | - | ||||||||||||||||||||||||||
Energy efficiency programs and environmental remediation cost riders | 29 | - | 29 | - | ||||||||||||||||||||||||||||||||||||
Bad debt rider | 14 | - | 14 | - | ||||||||||||||||||||||||||||||||||||
Transmission services | 49 | 7 | 42 | - | ||||||||||||||||||||||||||||||||||||
Recovery of FAC net under-recovery | 60 | 60 | - | - | ||||||||||||||||||||||||||||||||||||
Sales price changes, including hedge effect | 115 | - | - | 136 | 60 | - | (243 | ) | - | - | (81 | ) | ||||||||||||||||||||||||||||
Off-system revenues | (89 | ) | (89 | ) | - | - | - | - | (102 | ) | (102 | ) | - | - | ||||||||||||||||||||||||||
2007 Illinois Electric Settlement Agreement, net of reimbursement | 15 | - | 2 | 7 | 4 | 2 | 23 | - | 10 | 10 | ||||||||||||||||||||||||||||||
Supply Cost Adjustment factor | 7 | - | 2 | - | 1 | 4 | ||||||||||||||||||||||||||||||||||
Net unrealized MTM losses | (110 | ) | - | - | - | - | - | |||||||||||||||||||||||||||||||||
Generation output, load and other | (190 | ) | (25 | ) | (7 | ) | (201 | ) | 3 | (6 | ) | |||||||||||||||||||||||||||||
Net unrealized MTM gains (losses) | 49 | - | - | (1 | ) | |||||||||||||||||||||||||||||||||||
Sales (excluding impact of abnormal weather) and other | 51 | 15 | 3 | 50 | ||||||||||||||||||||||||||||||||||||
Total electric revenue change | $ | (458 | ) | $ | (56 | ) | $ | (78 | ) | $ | (58 | ) | $ | (42 | ) | $ | (79 | ) | $ | 581 | $ | 330 | $ | 96 | $ | (22 | ) | |||||||||||||
Fuel and purchased power change: | ||||||||||||||||||||||||||||||||||||||||
Fuel: | ||||||||||||||||||||||||||||||||||||||||
Generation and other | $ | 126 | $ | 21 | $ | - | $ | 79 | $ | 2 | $ | - | ||||||||||||||||||||||||||||
Net unrealized MTM gains | 118 | 58 | - | 33 | 7 | - | ||||||||||||||||||||||||||||||||||
Price | (83 | ) | - | - | (46 | ) | (3 | ) | - | |||||||||||||||||||||||||||||||
Coal contract settlement | (27 | ) | - | - | (27 | ) | - | - | ||||||||||||||||||||||||||||||||
Production volume and other | $ | (138 | ) | $ | (91 | ) | $ | - | $ | (38 | ) | |||||||||||||||||||||||||||||
FAC net under-recovery | 138 | 138 | - | - | ||||||||||||||||||||||||||||||||||||
Recovery of FAC net under-recovery | (60 | ) | (60 | ) | - | - | ||||||||||||||||||||||||||||||||||
Net unrealized MTM losses | (51 | ) | (29 | ) | - | (18 | ) | |||||||||||||||||||||||||||||||||
Price – Merchant Generation | (71 | ) | - | - | (51 | ) | ||||||||||||||||||||||||||||||||||
Purchased power | (25 | ) | 48 | - | - | 18 | - | 23 | (38 | ) | - | 11 | ||||||||||||||||||||||||||||
Illinois pass-through power supply costs | 338 | - | 89 | - | 104 | 145 | (220 | ) | - | 83 | - | |||||||||||||||||||||||||||||
FERC-ordered MISO resettlements | (12 | ) | (12 | ) | - | - | - | - | ||||||||||||||||||||||||||||||||
Total fuel and purchased power change | $ | 435 | $ | 115 | $ | 89 | $ | 39 | $ | 128 | $ | 145 | $ | (379 | ) | $ | (80 | ) | $ | 83 | $ | (96 | ) | |||||||||||||||||
Net change in electric margins | $ | (23 | ) | $ | 59 | $ | 11 | $ | (19 | ) | $ | 86 | $ | 66 | $ | 202 | $ | 250 | $ | 179 | $ | (118 | ) | |||||||||||||||||
Natural gas margins change: | ||||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate) | $ | (7 | ) | $ | (1 | ) | $ | (1 | ) | $ | - | $ | (1 | ) | $ | (4 | ) | |||||||||||||||||||||||
Changes in base rates | 34 | - | 7 | - | (6 | ) | 33 | |||||||||||||||||||||||||||||||||
Absence of capitalization of nonrecoverable gas costs | (5 | ) | - | (1 | ) | - | - | (4 | ) | |||||||||||||||||||||||||||||||
Net unrealized 2008 MTM losses | 12 | - | - | - | 12 | - | ||||||||||||||||||||||||||||||||||
Other | (17 | ) | (4 | ) | (4 | ) | - | (8 | ) | (2 | ) | |||||||||||||||||||||||||||||
Effect of weather (estimate)(b) | $ | 1 | $ | - | $ | 1 | $ | - | ||||||||||||||||||||||||||||||||
Bad debt rider | 15 | - | 15 | - | ||||||||||||||||||||||||||||||||||||
Rate decrease | (11 | ) | - | (11 | ) | - | ||||||||||||||||||||||||||||||||||
Energy efficiency programs and environmental remediation cost riders | 1 | - | 1 | - | ||||||||||||||||||||||||||||||||||||
Net unrealized MTM losses | (6 | ) | - | (6 | ) | - | ||||||||||||||||||||||||||||||||||
Sales (excluding impact of abnormal weather) and other | 2 | 2 | 2 | - | ||||||||||||||||||||||||||||||||||||
Net change in natural gas margins | $ | 17 | $ | (5 | ) | $ | 1 | $ | - | $ | (3 | ) | $ | 23 | $ | 2 | $ | 2 | $ | 2 | $ | - | ||||||||||||||||||
| 2008 versus 2007 | Ameren(a) | UE | CIPS | Genco | CILCO | IP | ||||||||||||||||||||||||||||||||||
| 2009 versus 2008 | Ameren(a) | UE | AIC | Genco | ||||||||||||||||||||||||||||||||||||
Electric revenue change: | ||||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate) | $ | (59 | ) | $ | (36 | ) | $ | (6 | ) | $ | - | $ | (4 | ) | $ | (13 | ) | |||||||||||||||||||||||
Effect of weather (estimate)(b) | $ | (47 | ) | $ | (33 | ) | $ | (14 | ) | $ | - | |||||||||||||||||||||||||||||
Regulated rates: | ||||||||||||||||||||||||||||||||||||||||
Changes in base rates | 43 | 16 | 5 | - | - | 22 | 229 | 141 | 88 | - | ||||||||||||||||||||||||||||||
Noranda sales | (50 | ) | (50 | ) | - | - | ||||||||||||||||||||||||||||||||||
Illinois pass-through power supply costs | (91 | ) | - | (58 | ) | - | 15 | (48 | ) | (338 | ) | - | (338 | ) | - | |||||||||||||||||||||||||
Energy efficiency programs and environmental remediation cost riders | 11 | - | 11 | - | ||||||||||||||||||||||||||||||||||||
Sales price changes, including hedge effect | 106 | - | - | 45 | 18 | - | 57 | - | - | (48 | ) | |||||||||||||||||||||||||||||
Off-system revenues, excluding estimated weather impact of $53 million | (42 | ) | (47 | ) | - | - | - | - | ||||||||||||||||||||||||||||||||
2007 Illinois Electric Settlement Agreement, net of reimbursement | 35 | - | 6 | 13 | 9 | 7 | ||||||||||||||||||||||||||||||||||
FERC-ordered MISO resettlements | (17 | ) | - | - | (12 | ) | (4 | ) | - | |||||||||||||||||||||||||||||||
Supply Cost Adjustment factor | (2 | ) | - | (2 | ) | - | 5 | (5 | ) | |||||||||||||||||||||||||||||||
Net unrealized MTM gains | 81 | 8 | - | - | - | - | ||||||||||||||||||||||||||||||||||
Generation output, load and other | 30 | 29 | 3 | (14 | ) | 51 | 4 | |||||||||||||||||||||||||||||||||
Off-system revenues | (89 | ) | (89 | ) | - | - | ||||||||||||||||||||||||||||||||||
2007 Illinois Electric Settlement Agreement | 15 | - | 5 | 7 | ||||||||||||||||||||||||||||||||||||
Net unrealized MTM (losses) gains | (110 | ) | - | - | 2 | |||||||||||||||||||||||||||||||||||
Sales (excluding impact of abnormal weather) and other | (125 | ) | (25 | ) | (29 | ) | (235 | ) | ||||||||||||||||||||||||||||||||
Total electric revenue change | $ | 84 | $ | (30 | ) | $ | (52 | ) | $ | 32 | $ | 90 | $ | (33 | ) | $ | (447 | ) | $ | (56 | ) | $ | (277 | ) | $ | (274 | ) | |||||||||||||
Fuel and purchased power change: | ||||||||||||||||||||||||||||||||||||||||
Fuel: | ||||||||||||||||||||||||||||||||||||||||
Generation and other | $ | 33 | $ | 31 | $ | - | $ | 31 | $ | (32 | ) | $ | - | |||||||||||||||||||||||||||
Net unrealized MTM losses | (75 | ) | (39 | ) | - | (18 | ) | (3 | ) | - | ||||||||||||||||||||||||||||||
Price | (93 | ) | (56 | ) | - | (13 | ) | (15 | ) | - | ||||||||||||||||||||||||||||||
Coal contract settlement for 2009 | 27 | - | - | 27 | - | - | ||||||||||||||||||||||||||||||||||
Production volume and other | $ | 88 | $ | (17 | ) | $ | 1 | $ | 93 | |||||||||||||||||||||||||||||||
FAC net under-recovery, net of collections | 38 | 38 | - | - | ||||||||||||||||||||||||||||||||||||
Net unrealized MTM gains | 118 | 58 | - | 48 | ||||||||||||||||||||||||||||||||||||
Price – Merchant Generation | (83 | ) | - | - | (80 | ) | ||||||||||||||||||||||||||||||||||
Coal contract settlement | (27 | ) | - | - | (27 | ) | ||||||||||||||||||||||||||||||||||
Purchased power | 39 | 9 | - | 23 | - | - | (25 | ) | 48 | 18 | 25 | |||||||||||||||||||||||||||||
Illinois pass-through power supply costs | 91 | - | 58 | - | (15 | ) | 48 | 338 | - | 338 | - | |||||||||||||||||||||||||||||
FERC-ordered MISO resettlements | 47 | 23 | 8 | - | 4 | 12 | (12 | ) | (12 | ) | - | - | ||||||||||||||||||||||||||||
Total fuel and purchased power change | $ | 69 | $ | (32 | ) | $ | 66 | $ | 50 | $ | (61 | ) | $ | 60 | $ | 435 | $ | 115 | $ | 357 | $ | 59 | ||||||||||||||||||
Net change in electric margins | $ | 153 | $ | (62 | ) | $ | 14 | $ | 82 | $ | 29 | $ | 27 | $ | (12 | ) | $ | 59 | $ | 80 | $ | (215 | ) | |||||||||||||||||
Natural gas margins change: | ||||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate) | $ | 12 | $ | 2 | $ | 2 | $ | - | $ | 2 | $ | 6 | ||||||||||||||||||||||||||||
Effect of weather (estimate)(b) | $ | (7 | ) | $ | (1 | ) | $ | (6 | ) | $ | - | |||||||||||||||||||||||||||||
Changes in base rates | 7 | 3 | 1 | - | (5 | ) | 8 | 34 | - | 34 | - | |||||||||||||||||||||||||||||
Capitalization of nonrecoverable gas costs | 9 | - | 2 | - | - | 7 | ||||||||||||||||||||||||||||||||||
Net unrealized MTM losses | (6 | ) | - | - | - | (6 | ) | - | ||||||||||||||||||||||||||||||||
Other | 14 | 3 | 2 | - | 8 | (3 | ) | |||||||||||||||||||||||||||||||||
Absence of capitalization of nonrecoverable gas costs | (5 | ) | - | (5 | ) | - | ||||||||||||||||||||||||||||||||||
Energy efficiency programs and environmental remediation cost riders | 4 | - | 4 | - | ||||||||||||||||||||||||||||||||||||
Net unrealized 2008 MTM losses | 12 | - | 12 | - | ||||||||||||||||||||||||||||||||||||
Sales (excluding impact of abnormal weather) and other | (17 | ) | (4 | ) | (17 | ) | - | |||||||||||||||||||||||||||||||||
Net change in natural gas margins | $ | 36 | $ | 8 | $ | 7 | $ | - | $ | (1 | ) | $ | 18 | $ | 21 | $ | (5 | ) | $ | 22 | $ | - | ||||||||||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | Represents the estimated margin impact resulting from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared to the prior year based on temperature readings from the National Oceanic and Atmospheric Administration. |
2010 versus 2009
Ameren Corporation
Ameren’s electric margins increased by $202 million, or 5%, in 2010 compared with 2009. The following items had a favorable impact on Ameren’s electric margins:
| Ÿ | Favorable weather conditions, as evidenced by a 52% increase in cooling degree-days, which increased revenues by $174 million. |
| Ÿ | Higher electric rates at UE, effective March 1, 2009, and June 21, 2010, which increased margins by $162 million. |
| Ÿ | Increased UE sales to Noranda in 2010 as its smelter plant gradually returned to full capacity in March 2010 after a January 2009 severe storm significantly reduced the plant’s capacity, which increased revenues by $54 million. |
| Ÿ | Higher transmission revenues primarily associated with higher FERC-regulated transmission rates. Higher rates were due, in part, to a significant increase in transmission assets placed into service at AIC during 2009, higher equity levels as a result of Ameren’s |
capital contributions to AIC in 2009, and mild 2009 weather, which increased margins by $49 million. |
| Ÿ | Higher electric rates at AIC, effective in early May 2010, as well as the adjustment of residential electric delivery rates effective October 1, 2009, to recover the full increase of IP’s 2008 ICC rate order, which increased margins by $41 million. |
| Ÿ | Net unrealized MTM activity at the Merchant Generation segment (primarily at Marketing Company), primarily related to nonqualifying power hedges, which increased margins by $49 million. |
| Ÿ | Recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms at AIC, which increased margins by $29 million. See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency program costs and environmental remediation costs. |
| Ÿ | Excluding the impact of UE’s increased sales to Noranda and the estimated impact of abnormal weather, rate-regulated retail sales volumes increased |
by 3% largely due to improved economic conditions, which increased margins by $25 million. |
| Ÿ | A reduction in the impact of the 2007 Illinois Electric Settlement Agreement, which increased margins by $23 million. |
| Ÿ | Recovery of prior years’ bad debt expense through the Illinois bad debt rider at AIC effective March 2010, which increased revenues by $14 million. See Operations and Maintenance in this section for additional information on a related offsetting increase in bad debt expense. |
The following items had an unfavorable impact on Ameren’s electric margins for 2010 compared with 2009:
| Ÿ | Reductions in higher-margin sales at the Merchant Generation segment resulting from the expiration of the 2006 auction power supply agreements on May 31, 2010, and lower market prices resulting in fewer opportunities for economic power sales, which decreased margins by $243 million. |
| Ÿ | A $93 million increase in UE’s net base fuel expense, which is substantially recovered from its customers, through higher sales volume associated with favorable weather in 2010 compared with 2009 and higher rates. Net base fuel expense is the sum of fuel—production volume and other ($91 million), purchased power ($38 million), and off-system sales ($102 million) offset by the FAC net under-recovery ($138 million). |
| Ÿ | 14% higher fuel prices in the Merchant Generation segment primarily due to higher commodity and transportation costs associated with new supply contracts, which decreased margins $71 million. |
| Ÿ | In the first quarter of 2009, the reversal of previously unrealized losses related to regulatory assets resulted in the recognition of a $29 million net MTM gain on energy and fuel-related contracts at UE. After the implementation of UE’s FAC on March 1, 2009, UE’s net MTM gains or losses no longer impact electric margins. Net unrealized MTM activity at the Merchant Generation segment on fuel-related transactions, primarily associated with financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, which reduced margins by $20 million. |
Ameren’s Illinois pass-through power supply costs reflect lower power prices and the expiration of intercompany power supply agreements between AIC and Marketing Company. AIC purchased power from Marketing Company from January 1, 2007, through May 31, 2010, under power supply agreements entered into following a 2006 Illinois power procurement auction. The purchases and sales under these agreements were eliminated in consolidation for Ameren’s financial statements. Subsequent to the expiration of these agreements in May 2010, Marketing Company’s power sales and AIC’s power purchases have primarily been made with nonaffiliated parties. As a result, Ameren’s consolidated revenues increased by a net $220 million in 2010 compared with
2009. These revenues were offset by a corresponding $220 million net increase in purchased power costs.
Ameren’s natural gas margins increased $2 million, or less than 1%, in 2010 compared with 2009. The following items had a favorable impact on Ameren’s natural gas margins:
| Ÿ | Recovery of prior years’ bad debt expense through the Illinois bad debt rider at AIC effective March 2010, which increased revenues by $15 million. See Operations and Maintenance in this section for additional information on a related offsetting increase in bad debt expense. |
| Ÿ | Favorable higher-margin customer mix that was mitigated by a 2% decrease in sales volumes, which increased margins by $2 million. |
The following items had an unfavorable impact on Ameren’s natural gas margins in 2010 compared with 2009:
| Ÿ | Lower natural gas rates effective early May 2010 at AIC, which reduced margins by $11 million. |
| Ÿ | The absence of net unrealized MTM gains in 2010 of $6 million on natural gas swaps. |
Ameren Missouri (UE)
UE has a FAC cost recovery mechanism that allows UE to recover, through customer rates, 95% of changes in fuel-production volume and other costs and purchased power costs, net of off-system revenues, including MISO costs and revenues, greater or less than the amount set in base rates, without a traditional rate proceeding.
UE’s electric margins increased $250 million, or 13%, in 2010 compared with 2009. The following items had a favorable impact on UE’s electric margins:
| Ÿ | Higher electric rates, effective March 1, 2009, and June 21, 2010, which increased margins $162 million. |
| Ÿ | Favorable weather conditions, as evidenced by a 44% increase in cooling degree-days, which increased revenues by $134 million. |
| Ÿ | Increased sales to Noranda in 2010 as its smelter plant gradually returned to full capacity in March 2010 after a January 2009 severe storm significantly reduced the plant’s capacity, which increased electric revenues by $54 million. |
| Ÿ | Taum Sauk’s return to service. Although Taum Sauk was not available to generate electricity for off-system revenues during 2009, UE had included $19 million in the calculation of the FAC as if Taum Sauk had generated off-system revenues. Upon Taum Sauk’s return to service in April 2010, UE’s margins have increased since the adjustment factor was eliminated from the FAC calculation, which increased margins by $12 million. |
| Ÿ | Excluding the impact of increased sales to Noranda and the estimated impact of abnormal weather, rate-regulated retail sales volumes increased by less than 1%, largely due to improved economic conditions, which increased margins by $9 million. |
The following items had an unfavorable effect on UE’s electric margins in 2010 compared with 2009:
| Ÿ | A $93 million increase in net base fuel expense, which is substantially recovered from its customers, as a result of higher sales volume associated with favorable weather in 2010 compared with 2009 and higher rates. Net base fuel expense is the sum of fuel – production volume and other ($91 million), purchased power ($38 million), and off-system sales ($102 million) offset by the FAC net under-recovery ($138 million). |
| Ÿ | The reversal of previously unrealized losses to regulatory assets, which resulted in the recognition of a $29 million net MTM gain on energy and fuel-related contracts in the first quarter of 2009. This benefit did not reoccur in 2010. After the implementation of the FAC on March 1, 2009, net MTM gains or losses no longer affect electric margins. See Note 7– Derivative Financial Instruments under Part II, Item 8, of this report for additional information. |
UE’s natural gas margins increased by $2 million, or 3%, in 2010 compared with 2009 because of a 2% increase in sales volumes, largely due to improved economic conditions.
Ameren Illinois (AIC)
AIC has a cost recovery mechanism for power purchased on behalf of its customers. These pass-through power costs do not affect margins; however, the electric revenues and offsetting purchased power costs may fluctuate, primarily because of customer switching and usage. See below for explanations of electric and natural gas margin variances for the Ameren Illinois segment.
AIC’s electric margins increased by $179 million, or 20%, in 2010 compared with 2009. The following items had a favorable impact on electric margins:
| Ÿ | Higher transmission revenues primarily associated with higher FERC-regulated transmission rates. Higher rates were due, in part, to an increase in transmission assets placed into service during 2009, higher equity levels resulting from Ameren’s capital contributions to IP in 2009, and mild 2009 weather, which increased margins by $42 million. |
| Ÿ | Higher delivery service rates, effective in early May 2010, as well as the adjustment of residential electric delivery rates effective October 1, 2009, at IP to recover the full increase of the 2008 ICC rate order, which increased margins by $41 million. |
| Ÿ | Favorable weather conditions, as evidenced by a 65% increase in cooling degree-days, which increased revenues by $40 million. |
| Ÿ | Recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms, which increased margins by $29 million. See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency program costs and environmental remediation costs. |
| Ÿ | Recovery of prior years’ bad debt expense under the Illinois bad debt rider effective March 2010, which increased revenues by $14 million. See Operations and Maintenance in this section for additional information on a related offsetting increase in bad debt expense. |
| Ÿ | A reduction in the impact of the 2007 Illinois Electric Settlement Agreement, which increased margins by $10 million. |
AIC’s natural gas margins increased by $2 million, or 1%, in 2010 compared with 2009. The following items had a favorable impact on natural gas margins:
| Ÿ | Recovery of prior years’ bad debt expense under the Illinois bad debt rider, effective March 2010, which increased revenues by $15 million. See Operations and Maintenance in this section for additional information on a related offsetting increase in bad debt expense. |
| Ÿ | A higher-margin customer mix that was mitigated by a 3% decrease in sales volumes, which increased margins by $2 million. |
The following items had an unfavorable impact on AIC’s natural gas margins in 2010 compared with 2009:
| Ÿ | Lower natural gas rates effective early May 2010, which reduced margins by $11 million. |
| Ÿ | The absence of net unrealized MTM gains in 2010 of $6 million on natural gas swaps, as occurred in 2009. |
Merchant Generation
Merchant Generation’s electric margins decreased by $232 million, or 23%, in 2010 compared with 2009. See below for explanations of electric margin variances for the Merchant Generation segment.
Genco
Genco’s electric margins decreased by $118 million, or 18%, in 2010 compared with 2009. The following items had an unfavorable impact on electric margins:
| Ÿ | Lower revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. There was a smaller pool of money to allocate because of reductions in higher-margin sales, resulting from the expiration of older long-term contracts and because of lower market prices. The lower market prices associated with the Genco PSA were mitigated by higher market prices associated with EEI’s power supply agreement with Marketing Company (EEI PSA). The net impact of lower market prices under both power supply agreements reduced electric revenues by $81 million. In accordance with the Genco PSA, Genco was also allocated a lower percentage of revenues from the pool because of lower reimbursable expenses and lower generation relative to AERG. |
| Ÿ | 14% higher fuel prices in 2010 compared with 2009, primarily due to higher commodity and transportation costs associated with new supply contracts, which reduced margins by $51 million. |
| Ÿ | Net unrealized MTM activity on fuel-related transactions primarily associated with financial instruments acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts, which reduced margins by $18 million. |
The following items had a favorable impact on Genco’s electric margins in 2010 compared with 2009:
| Ÿ | A reduction in the impact of the 2007 Illinois Electric Settlement Agreement, which increased margins by $10 million. |
| Ÿ | Increased power plant utilization, primarily due to more economic sales opportunities and a reduction in transmission constraints, which previously limited the period in which power could be sold. In addition, one of Genco’s coal-fired power plants experienced a transformer fire in September 2009, which put two units out of service for a period of time in 2009. The higher production volume contributed to the $50 million increase in electric revenues, which was mitigated by higher production volume costs of $38 million. Genco’s baseload coal-fired generating plants’ average capacity factor increased to 71% in 2010, compared with 67% in 2009, and Genco’s equivalent availability factor increased to 88% in 2010, compared with 82% in 2009. |
Other Merchant Generation
Electric margins from Ameren’s other Merchant Generation operations, primarily AERG and Marketing Company, decreased by $114 million, or 32%, in 2010. Other Merchant Generation electric margins were unfavorably affected, compared with 2009, by:
| Ÿ | Lower revenues allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company. There was a smaller pool of money to allocate because of reductions in higher-margin sales resulting from the expiration of older long-term contracts and because of lower market prices. These items reduced electric margins by $109 million. However, in accordance with the AERG PSA, AERG was allocated a greater percentage of revenues from the pool because of higher reimbursable expenses and higher generation relative to Genco. |
| Ÿ | 19% higher fuel prices at AERG in 2010 compared with 2009, primarily due to higher commodity and transportation costs associated with new supply contracts, which reduced margins by $20 million. |
The following items had a favorable impact on the electric margins of other Merchant Generation operations for 2010 compared with 2009:
| Ÿ | Net unrealized MTM activity at Marketing Company improved margins by $50 million primarily because of nonqualifying power hedges. |
| Ÿ | A reduction in the impact of the 2007 Illinois Electric Settlement Agreement at AERG, which increased margins by $4 million. |
| Ÿ | Increased power plant utilization at AERG, primarily due to more opportunities for economic sales and a reduction in plant outages. The higher production volume increased electric revenues by $37 million, which was partially offset by higher production volume costs of $16 million. AERG’s baseload coal-fired generating plants’ average capacity factor increased to 75% in 2010, compared with 69% in 2009, while AERG’s equivalent availability factor increased to 85% in 2010, compared with 78% in 2009. |
2009 versus 2008
Ameren
Ameren’s electric margins decreased by $23$12 million, or less than 1%, in 2009 compared with 2008. The following items had an unfavorable impact on Ameren’s electric margins:
| Ÿ |
|
Net unrealized MTM activity in the Merchant Generation segment |
| Ÿ | Higher fuel expense at Genco as a result of its June 2008 |
| lump-sum payment of $60 million for the early termination of a coal supply contract. This payment compensated Genco, in total, for higher fuel costs it incurred throughout 2008 ($33 million) and 2009 ($27 million). Because the entire settlement was recorded in earnings in 2008, Ameren’s recorded earnings in |
2009 were |
| Ÿ | Excluding the impact of the June 2008 settlement agreement, 5% higher fuel prices in the Merchant Generation segment. |
| Ÿ | Reduced sales by UE to Noranda, due to an extended severe storm-related outage, which lowered electric revenues by $50 million in 2009. |
| Ÿ | Unfavorable weather conditions, as evidenced by a 7% reduction in cooling degree-days, which decreased |
| Ÿ | Excluding the impact of UE’s reduced sales to Noranda |
| Ÿ | Higher net fuel expense at UE of $20 million resulting from lower off-system revenues and higher production volume and other, offset in part by lower purchased power and FAC under-recovery. |
| Ÿ | Decreased power plant utilization in the Merchant Generation segment, primarily because of lower market prices, which resulted in fewer opportunities for economic sales, and transmission congestion, which limited the period when power could be sold. The lower production volume contributed to the $125 million decrease in electric revenues, which was mitigated by |
lower production volume costs of $88 million. Merchant Generation’s baseload, coal-fired generating plants’ equivalent availability factors were 81% in 2009, |
compared with 85% in |
The following items had a favorable impact on Ameren’s electric margins for 2009 compared with 2008:
| Ÿ | Higher electric rates at UE, effective March 1, 2009, which increased margins by $141 million, and higher rates at |
| Ÿ | Net unrealized MTM activity at UE |
| Ÿ | Net unrealized MTM activity improved margins by $55 million at the Merchant Generation segment |
| Ÿ | The repricing of wholesale and retail electric power supply agreements and financial swaps that settled at higher margins at Merchant Generation. |
| Ÿ |
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| Ÿ |
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| Ÿ | A $15 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement. |
| Ÿ | Higher Callaway nuclear plant availability due to the absence of a 30-day planned maintenance outage, which occurred in |
Ameren’s natural gas margins increased by $17$21 million, or 4%5%, in 2009 compared with 2008. The following items had a favorable impact on Ameren’s natural gas margins:
| Ÿ |
|
| Ÿ | The absence of net unrealized MTM losses at |
| Ÿ | Recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms at AIC, which increased margins by $4 million. See Operations and Maintenance in this section for information on |
The following items had an unfavorable impact on Ameren’s natural gas margins in 2009 compared with 2008:
| Ÿ | 7% lower sales volumes, excluding the estimated impact of abnormal weather, largely a result of the economic slowdown, and lower realized prices related to a contract with a large industrial customer in 2009, which decreased margins by $17 million. |
| Ÿ | Unfavorable weather conditions, as evidenced by an 8% reduction in heating degree-days, which decreased margins by $7 million. |
|
| Ÿ | The absence of the capitalization of nonrecoverable purchased gas costs in accordance with the September 2008 ICC gas rate order, which resulted in a one-time increase in margins of $5 million in 2008. |
Ameren Missouri Regulated (UE)
UE has a FAC cost recovery mechanism that allows UE to recover, through customer rates, 95% of changes in fuel-production volume and other costs and purchased power costs, net of off-system revenues, including MISO costs and revenues, greater or less than the amount set in base rates, without a traditional rate proceeding.
UE’s electric margins increased $59 million, or 3%, in 2009 compared with 2008. The following items had a favorable impact on UE’s electric margins:
| Ÿ | Higher electric rates, effective March 1, 2009, which increased margins by $141 million. |
| Ÿ | Net unrealized MTM activity |
| Ÿ |
|
| Ÿ | Higher Callaway nuclear plant availability due to the absence of a 30-day planned maintenance outage, which occurred in |
The following items had an unfavorable impact on UE’s electric margins in 2009 compared with 2008:
| Ÿ |
|
Reduced sales to Noranda, due to an extended severe storm-related outage, which lowered electric revenues by $50 million. |
| Ÿ | Unfavorable weather conditions, as indicated by a 13% reduction in cooling degree-days during the third quarter of 2009, which is UE’s peak cooling period, and a mild winter, which decreased |
| Ÿ | Excluding the impact of reduced sales to Noranda |
| Ÿ | A $20 million increase in net fuel expense resulting from lower off-system revenues and higher production volume and other, offset in part by lower purchased power and FAC under-recovery. |
| Ÿ | The absence in 2009 of the benefits from a MoPSC order that directed the recording in 2008 of a regulatory asset related to previously incurred costs for a 2007 FERC order, which decreased margins by $12 million. |
UE’s natural gas margins decreased by $5 million, or 6%, in 2009 compared with 2008, primarily because of an 8% decrease in weather-normalized sales volumes in 2009.
Ameren Illinois Regulated(AIC)
Illinois Regulated’s electric margins increased by $69 million, or 8%, in 2009 compared with 2008. Illinois Regulated’s natural gas margins increased by $17 million, or 5%, in 2009 compared with 2008. The Ameren Illinois
Utilities haveAIC has a cost recovery mechanism for power purchased on behalf of theirits customers. These pass-through power costs do not affect margins; however, the electric revenues and offsetting purchased power costs may fluctuate, primarily because of customer switching and usage. See below for explanations of electric and natural gas margin variances for the Ameren Illinois Regulated segment.
CIPS
CIPS’AIC’s electric margins increased by $11$80 million, or 4%10%, in 2009 compared with 2008. The following items had a favorable impact on electric margins:
| Ÿ | Higher electric delivery service rates, effective October 1, 2008, which increased margins by |
| Ÿ |
|
| Ÿ | A |
AIC’s electric margins were unfavorably affected in 2009 compared with 2008 by the following items:
| Ÿ | 5% lower sales volumes excluding the estimated impact of abnormal weather, primarily in the lower-margin industrial customer sector, largely as a result of the economic slowdown, which decreased margins by $15 million. |
| Ÿ | Unfavorable weather conditions, as evidenced by a 13% reduction in cooling degree-days, which decreased revenues by $14 million. |
AIC’s natural gas margins increased by $22 million, or 6%, in 2009 compared with 2008. The following items had a favorable impact on natural gas margins:
| Ÿ | Higher net natural gas delivery service rates, effective October 1, 2008, which increased margins by $34 million. |
| Ÿ | The absence of net unrealized MTM losses on natural gas swaps that improved margins by $12 million in 2009. |
| Ÿ | Recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms, which increased margins by $4 million. See Operations and Maintenance in this section for information on a related offsetting increase in energy efficiency program costs and environmental remediation costs. |
The following items had an unfavorable impact on CIPS’ electricAIC’s natural gas margins in 2009 compared with 2008:
| Ÿ |
|
| Ÿ | Unfavorable weather conditions, as evidenced by a 7% reduction in |
CIPS’ natural gas margins increased by $1 million, or 1%, in 2009 compared with 2008. This was primarily due to higher gas delivery service rates, effective October 1, 2008, which increased margins by $7 million.
The following items had an unfavorable impact on CIPS’ natural gas margins in 2009 compared with 2008:
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| Ÿ | The absence of the capitalization of nonrecoverable purchased gas costs in accordance with the September 2008 ICC gas rate order, which resulted in a one-time increase in margins of |
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margins by segment to CILCO’s total change in electric margins for 2009 compared with 2008:
| 2009 versus 2008 | ||||
CILCO (Illinois Regulated) | $ | (8 | ) | |
CILCO (AERG) | 94 | |||
Total change in electric margins | $ | 86 | ||
CILCO’s (Illinois Regulated) electric margins decreased by $8 million, or 5%, in 2009 compared with 2008. The following items had an unfavorable impact on electric margins:
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CILCO’s (Illinois Regulated) electric margins were favorably affected in 2009 compared with 2008 by:
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See Merchant Generation below for an explanation of CILCO’s (AERG) electric margins in 2009 compared with 2008.
CILCO’s (Illinois Regulated) natural gas margins decreased by $3 million, or 3%, in 2009 compared with 2008. CILCO’s natural gas margins were unfavorably affected by:
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CILCO’s natural gas margins were favorably affected in 2009 compared with 2008 by the absence of net unrealized MTM losses of $12 million in 2009 on natural gas swaps.
IP
IP’s electric margins increased by $66 million, or 16%, in 2009 compared with 2008. The following items had a favorable impact on electric margins:
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IP’s electric margins were unfavorably affected in 2009 compared to 2008 by:
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IP’s natural gas margins increased by $23 million, or 14%, in 2009 compared with 2008. This was primarily due to higher gas delivery service rates, effective October 1, 2008, which increased margins by $33 million.
The following items had an unfavorable impact on IP’s natural gas margins in 2009 compared with 2008:
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Merchant Generation
Merchant Generation’s electric margins decreased by $176 million, or 15%, in 2009 compared with 2008. See below for explanations of electric margin variances for the Merchant Generation segment.
Genco
Genco’s electric margins decreased by $19$215 million, or 3%25%, in 2009 compared with 2008. The following items had an unfavorable impact on electric margins:
| Ÿ | Decreased power plant utilization, primarily due to lower market prices, which resulted in fewer opportunities for economic sales, and transmission congestion, which limited the period when power could be sold. In addition, one of Genco’s coal-fired power plants experienced a transformer fire in September 2009, which put two units out of service for a |
| Ÿ | Lower revenues associated with EEI’s power supply agreement with Marketing Company driven primarily by lower market prices, which decreased revenues by $191 million. |
| Ÿ | Lower revenues allocated to Genco under |
| Ÿ | Higher fuel expense as a result of Genco’s June 2008 |
Genco’s recorded earnings in 2009 were |
| Ÿ | Excluding the impact of the June 2008 settlement agreement, |
Genco’s electric margins were favorably affected in 2009 compared with 2008 by:by the following items:
| Ÿ | Net unrealized MTM activity |
| Ÿ |
|
A $7 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement. |
CILCO (AERG)Other Merchant Generation
AERG’sElectric margins from Ameren’s other Merchant Generation operations, primarily AERG and Marketing Company, increased by $39 million, or 13%, in 2009. Other Merchant Generation electric margins increased by $94 million, or 43%, in 2009were favorably affected, compared with 2008. The following items had a favorable impact on electric margins:2008, by:
| Ÿ | Higher revenues allocated to AERG under |
| Ÿ | Net unrealized MTM activity |
| Ÿ |
|
| Ÿ | A $3 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement. |
Other Merchant Generation
Electric margins from Ameren’s other Merchant Generation operations, primarily EEI and Marketing Company, decreased by $251 million, or 66%, in 2009. Other Merchant Generation electric margins were unfavorably affected,reduced by $112 million in 2009 compared with 2008 by:
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2008 versus 2007
Ameren
Ameren’s electric margins increased by $153 million, or 4%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s electric margins:
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The following items had an unfavorable impact on Ameren’s electric margins in 2008 compared with 2007:
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Ameren’s natural gas margins increased by $36 million, or 9%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s natural gas margins:
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Missouri Regulated (UE)
UE’s electric margins decreased $62 million, or 3%, in 2008 compared with 2007. The following items had an unfavorable impact on UE’s electric margins:
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The following items had a favorable impact on electric margins in 2008 compared with 2007:
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UE’s natural gas margins increased by $8 million, or 11%, in 2008 compared with 2007. The following items had a favorable impact on natural gas margins:
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Illinois Regulated
Illinois Regulated’s electric margins increased by $58 million, or 8%, and natural gas margins increased by $25 million, or 8%, in 2008 compared with 2007. The Ameren Illinois Utilities have a cost recovery mechanism for power purchased on behalf of their customers. These pass-through power costs do not affect margins; however, the electric revenues and offsetting purchased power costs fluctuate primarily because of customer switching and usage. See below for explanations of electric and natural gas margins variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margins increased by $14 million, or 6%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:
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These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, which decreased electric margins by $6 million.
CIPS’ natural gas margins increased by $7 million, or 10%, in 2008 compared with 2007. The following items had a favorable impact on natural gas margins:
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CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margins by segment to CILCO’s total change in electric margins for 2008 compared with 2007:
| 2008 versus 2007 | |||
CILCO (Illinois Regulated) | $ | 17 | |
CILCO (AERG) | 12 | ||
Total change in electric margins | $ | 29 | |
CILCO’s (Illinois Regulated) electric margins increased by $17 million, or 14%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:
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These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 28% reduction in cooling degree-days, which decreased margins by $4 million.
See Merchant Generation below for an explanation of CILCO’s (AERG) electric margins in 2008 compared with 2007.
CILCO’s (Illinois Regulated) natural gas margins decreased $1 million, or 1%, in 2008 compared with 2007. The following items had an unfavorable impact on gas margins:
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The following items had a favorable impact on gas margins in 2008 compared with 2007:
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IP
IP’s electric margins increased by $27 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:
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These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 34% reduction in cooling degree-days, which decreased margins by $13 million.
IP’s natural gas margins increased by $18 million, or 12%, in 2008 compared with 2007. The following items had a favorable impact on natural gas margins:
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These favorable variances were partially offset by a 4% decrease in weather-normalized sales volumes, which decreased margins by $3 million.
Merchant Generation
Merchant Generation’s electric margins increased by $151 million, or 15%, in 2008 compared with 2007. Merchant Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 76% and 85%, respectively, in 2008 compared with 74% and 81%, respectively, in 2007. See below for explanations of electric margins variances for the Merchant Generation segment.
Genco
Genco’s electric margins increased by $82 million, or 16%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:
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The following items had an unfavorable impact on electric margins in 2008 compared with 2007:
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CILCO (AERG)
AERG’s electric margins increased by $12 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:
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The following items had an unfavorable impact on electric margins in 2008 compared with 2007:
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Other Merchant Generation
Electric margins from Ameren’s other Merchant Generation operations, primarily from EEI and Marketing Company, increased by $57 million, or 18%, in 2008. Other Merchant Generation electric margins were unfavorably affected compared with 2007 by:
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Other Merchant Generation electric margins were favorably affected by market price fluctuations during 2008, which resulted in nonaffiliated MTM gains on energy transactions of $73 million, primarily related to nonqualifying hedges of changes in market prices for electricity.power hedges.
Other Operations and Maintenance Expenses
20092010 versus 20082009
Ameren Corporation
Other operations and maintenance expenses decreased $119increased $53 million in 20092010 compared with 2008 because of several factors. Coal-fired plant2009.
The following items increased other operations and maintenance expenses between periods:
| Ÿ | Increased plant maintenance and labor costs of $39 million associated with a refueling and maintenance outage at the Callaway nuclear plant and an increase of $16 million for other scheduled coal-fired plant outages, the installation of scrubbers at UE’s Sioux plant, and other maintenance work. There was no Callaway nuclear plant refueling and maintenance outage in 2009. |
| Ÿ | A $46 million increase in bad debt expense. The July 2009 capitalization and recovery of prior years’ bad debt expense under the Illinois bad debt rate |
| adjustment mechanism (net of a related donation for customer assistance programs) reduced bad debt expense in 2009. Additionally, bad debt expense increased in 2010, because of amortization of regulatory assets set up in conjunction with the Illinois bad debt rate adjustment mechanism in 2009. Amortization expense associated with these regulatory assets was offset by increased revenues through collection from customers, with no overall impact on net income. |
| Ÿ | Increased AIC energy efficiency program costs and environmental remediation costs of $30 million. Energy efficiency program costs are allowed to be recovered from customers under the 2007 Illinois Electric Settlement Agreement; environmental remediation costs associated with MGPs are recoverable from customers through Illinois environmental adjustment rate riders. Accordingly, these costs are offset by increased revenues, with no overall impact on net income. See Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for additional information. |
| Ÿ | An unfavorable change of $7 million in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans. |
The following items reduced other operations and maintenance expenses between periods:
| Ÿ | The absence in 2010 of major storms, such as had occurred in 2009, which resulted in a $27 million |
reduction in other operations and maintenance expenses. |
| Ÿ | Severance costs of $17 million for employee separation programs recognized in 2009, as compared with $4 million in 2010. |
| Ÿ | A May 2010 MoPSC electric rate order, which resulted in UE recording regulatory assets in 2010 related to employee severance costs and storm costs incurred in 2009, which decreased expenses by $11 million. |
| Ÿ | A reduction in labor costs of $10 million, primarily because of staff reductions. |
| Ÿ | Items that unfavorably affected Ameren in 2009 that did not recur in 2010: a $5 million penalty incurred for the termination of a heavy forgings contract associated with efforts to build a new nuclear unit at UE’s Callaway nuclear plant and a $5 million write-off of Ameren’s investment in a supply acquisition partnership. |
| Ÿ | A gain on the sale of property interests at Genco recognized in 2010. |
Variations in other operations and maintenance expenses in Ameren’s business segments and for the Ameren Companies between 2010 and 2009 were as follows:
Ameren Missouri (UE)
Other operations and maintenance expenses increased $51 million in 2010. Plant maintenance and labor costs were reduced by $48increased $39 million and bad debt expenses were lower by $44 million, because of elevated levels of bad debt expense in 2008 as a result of the transition to higher market-based ratesCallaway nuclear plant refueling and maintenance outage and $34 million for other scheduled coal-fired plant outages, the installation of scrubbers at the Ameren Illinois UtilitiesUE’s Sioux plant, and the impactother maintenance work and plant-related costs. Additionally, other operations and maintenance expenses increased because of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs) discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8 of this report. A favorablean unfavorable change of $37$4 million in unrealized net MTM adjustments between periods resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans and the absencehigher bad debt expense of a Callaway
nuclear plant refueling$5 million, primarily due to higher customer billings resulting from rate increases and maintenance outage in 2009, as compared with costs of $30 million in 2008, also reduced operations and maintenance expenses. Additionally, asset impairment charges were lower by $7 million between years.
weather conditions. Reducing the benefitunfavorable impact of these items was an increasethe absence of $24 millionmajor storms, such as had occurred in labor costs and the recognition of $17 million for employee severance costs2009, which resulted in 2009. In 2008,a decrease in other operations and maintenance expenses of $13 million. Other operations and maintenance expenses were also reduced by a MoPSC accounting orderthe recording of regulatory assets in 2010 related to employee severance costs and storm costs incurred in 2007,2009, and by the absence of severance costs for employee separation programs and the absence of the forgings contract penalty recognized in 2009, as discussed above.
Ameren Illinois (AIC)
Other operations and maintenance expenses increased $45 million in 2010, primarily because of a $40 million increase in bad debt expense resulting from the July 2009 capitalization and recovery of prior years’ bad debt expense under the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs), which resulteddecreased bad debt expense in UE2009, and the
amortization in 2010 of regulatory assets set up in conjunction with the Illinois bad debt rate adjustment mechanism in 2009. Energy efficiency program costs and environmental remediation costs increased by $30 million, as discussed above. Reducing the unfavorable impact of these items were the absence of major storms in 2010, as compared with storm costs of $16 million in 2009, and a $9 million reduction of employee benefit costs due, in part, to the absence of severance costs in 2010 such as AIC had incurred in 2009.
Merchant Generation
Other operations and maintenance expenses decreased $46 million in the Merchant Generation segment, primarily because of variations at Genco, as discussed below. Additionally, other operations and maintenance expenses decreased at AERG, primarily because of lower labor costs due to staff reductions, and reduced severance costs due to employee separation programs that were implemented in 2009.
Genco
Other operations and maintenance expenses decreased $35 million. Plant maintenance costs were lower by $16 million due to the retirement in 2009 of two generation units at Genco’s Meredosia plant and other reductions in required maintenance work between years. Additionally,
other operations and maintenance costs were lower due to a $7 million reduction in employee benefit costs, due, in part, to reduced severance costs because of employee separation programs in 2009, a $5 million decline in labor costs resulting from staff reductions, and a property sale gain in 2010.
2009 versus 2008
Ameren Corporation
Other operations and maintenance expenses decreased $94 million in 2009 compared with 2008.
The following items reduced other operations and maintenance expenses between periods:
| Ÿ | Coal-fired plant maintenance costs were lower by $48 million, primarily because less work was undertaken as a result of cost-containment initiatives in response to weak economic conditions. |
| Ÿ | Bad debt expense was lower by $44 million because of the impact of the implementation of the Illinois bad debt rate adjustment mechanism in 2009, as discussed above. Additionally, bad debt expense in 2008 was at an elevated level as a result of the transition to higher market-based rates at AIC. |
| Ÿ | A favorable change of $37 million in unrealized net MTM adjustments between periods resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans. |
| Ÿ | The absence of a Callaway nuclear plant refueling and maintenance outage in 2009, as compared with costs of $30 million in 2008. |
The following items increased other operations and maintenance expenses between periods:
| Ÿ | In 2008, other operations and maintenance expenses were reduced by a MoPSC accounting order related to storm costs incurred in 2007, which resulted in UE’s recording of a regulatory asset of $25 million; no similar item occurred in 2009. |
| Ÿ | An increase of $24 million in labor costs due to wage increases and higher staff levels during most of 2009. |
| Ÿ | The recognition of $17 million for employee severance costs in 2009. |
| Ÿ | AIC’s energy efficiency program costs and environmental remediation costs increased by $15 million. |
Variations in other operations and maintenance expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.follows:
Ameren Missouri Regulated (UE)
Other operations and maintenance expenses decreased $42 million.million in 2009. This was primarily because of a $32 million reduction in coal-fired plant maintenance costs due to reduced outages in 2009, as less work was undertaken as a result of cost containment initiatives in
response to weak economic conditions, and because of the absence of a Callaway nuclear plant refueling and maintenance outage in 2009, as compared with costs of $30 million in 2008. A favorable change of $19 million in unrealized net MTM adjustments between periods, which resulted from changes in the market value of investments used to support Ameren’s deferred compensation plans, and a $14 million decline in employee benefit costs also resulted in decreased expenses between years. In addition to these items, employee benefit costs were lower by $14 million, primarily due to reduced expenses between years associated with the pension and postretirement benefit costs tracker allowed by the MoPSC, partially offset by increased expense due to changes in actuarial assumptions.
Reducing the benefit of these items was a $21 million increase in labor costs because of wage increases and higher staff levels during most of the year, the recognition of $8 million in employee severance costs in 2009, and the absence of the MoPSC storm cost accounting order of $25 million that occurred in 2008, as described above. In addition to these items, storm repair expenditures were higher in 2009 as a result of a severe ice storm at the beginning of the year.
Ameren Illinois Regulated(AIC)
Other operations and maintenance expenses decreased $77$63 million in the Illinois Regulated segment, as discussed below.
CIPS
Other operations and maintenance expenses decreased $15 million,2009, primarily because of a $10$39 million reduction in bad debt expense, because of elevated levels of bad debt expense in 2008 anddue to the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs), and elevated levels of bad debt expense in 2008, as discussed above, and a favorable change in unrealized net MTM adjustments between periods resulting from changes in the
market value of investments used to support Ameren’s deferred compensation plans.
CILCO (Illinois Regulated)
Other operations and maintenance expenses increased $63 million, primarily because of Partially offsetting these favorable items were higher labor and employee benefit costs. These increases were primarily a result of work performed on behalf of CIPS and IP as discussed below.
At the beginning of 2009, approximately 570 employees were transferred from Ameren Services to CILCO (Illinois Regulated), which resulted in an increase in other operations and maintenance expenses at CILCO (Illinois Regulated) in 2009. These CILCO (Illinois Regulated) employees also provide support services to CIPS and IP. CILCO (Illinois Regulated) records reimbursements from CIPS and IP for work performed by its employees on their behalf as Operating Revenues – Support Services – Affiliates on its statement of income, which increased $70 million in 2009 compared with 2008. Intercompany revenue and expenses associated with these transactions are eliminated in consolidation within the Illinois Regulated segment. See Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information on CILCO (Illinois Regulated) support services.
Reducing the unfavorable effect of the above items was a reduction in bad debt expense, because of elevated levels of bad debt expense in 2008 and the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs).
IP
IP’s other operations and maintenance expenses decreased $43 million, primarily because of a $25 million reduction in bad debt expense, because of elevated levels of bad debt expense in 2008 and the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs), a $6 million decrease in distribution system reliability expenditures, including reduced stormenergy efficiency program costs and a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.environmental remediation costs.
Merchant Generation
Other operations and maintenance expenses decreased $16$9 million in 2009 in the Merchant Generation segment, as discussed below.
Genco
primarily because of lower plant maintenance expenses at AERG. Genco’s other operations and maintenance expenses were comparable between years, as higher employee severance costs were mitigated by lower plant maintenance costs. The reductions in plant maintenance costs at AERG and expensesGenco were a result of cost containment initiatives in response to weak economic conditions.
Goodwill and Other Impairment Losses
In 2010, Ameren and Genco recognized fornoncash pretax impairment charges of $589 million (including Genco’s impairment charges) and $170 million, respectively, related to goodwill, long-lived assets, and emission allowances within the Merchant Generation segment. In 2009, asset impairment charges of $7 million and $6 million were recorded at Ameren and Genco, respectively, primarily because of the termination of a rail line extension project were reduced by lower plant maintenance costs.
CILCO (AERG)
Other operationsat a subsidiary of Genco and maintenance expenses decreased $22 million, primarily because of a $9 million reduction in plant maintenance costs and an $11 million reduction in asset impairment charges between years.
EEI
EEI’s other operations and maintenance expenses increased $10 million, primarily because of higher plant maintenance costs.
2008 versus 2007
Ameren
Ameren’s other operations and maintenance expenses increased $170 million in 2008 compared with 2007. Labor costs increased by $52 million and plant maintenance expenditures at coal-fired plants were higher by $43 million due to outages. A $30 million increase in distribution system reliability expenditures and a $10 million increase in information technology costs also resulted in higher expenses. An unfavorable change of $22 million in unrealized net MTM adjustments resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans reduced expenses between years. Bad debt expense increased by $10 million, primarily because of the transition to higher market-based rates at the Ameren Illinois Utilities. Additionally, in the first quarter of 2007, a $15 million accrual established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan was reversed because the plan was terminated. There was no similar item in 2008.
Other operations and maintenance expenses also increased in 2008 by $14 million, because of asset impairment charges recorded during the fourth quarter of 2008 to adjust the carrying value of CILCO’s (through AERG)an office building owned by Genco to its estimated fair value. In 2008, Ameren recognized asset impairment charges of $14 million to adjust the carrying value of AERG’s Indian Trails and Sterling Avenue generation facilities to their estimated fair values asvalues. See Note 17 – Goodwill and Other Asset Impairments to our financial statements under Part lI, Item 8, of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails cogeneration facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT based on the expected net proceeds to be generated from the sale of the facility in 2009. Because most of the Sterling Avenue asset carrying value was recorded at CILCORP, as a result of adjustments made during purchase accounting, the write-down of the carrying value of the Sterling Avenue CT did not result in an impairment loss at CILCO (AERG).
Reducing the unfavorable effect of these items was a reduction of $10 million in employee benefit costs, due to changes in actuarial estimates, and an $18 million decrease in storm expenditures, primarily in UE’s service territory. Additionally, costs associated with the Callaway nuclear plant refueling and maintenance outage in 2008 were $5 million lower than thosethis report for the refueling in 2007. Other operations and maintenance expenses were further reduced in 2008 by the MoPSC accounting order related to 2007 storms, as discussed above.additional information.
Variations in other operations and maintenance expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated (UE)
UE’s other operations and maintenance expenses were higher by $22 million, primarily because of a $37 million increase in labor costs and a $29 million increase in plant maintenance expenditures at coal-fired plants. An unfavorable
change in unrealized net MTM adjustments resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans and a $16 million increase in distribution system reliability expenditures also resulted in incremental expenses.
Reducing the impact of these items were the effect of the MoPSC accounting order discussed above, a decrease in injuries and damages expenses between years, and the reduced impact of the Callaway nuclear plant refueling and maintenance outage in 2008 compared with the refueling in 2007. Storm repair expenditures also decreased by $31 million, further reducing other operations and maintenance expenses.
Illinois Regulated
Other operations and maintenance expenses increased $77 million in the Illinois Regulated segment, as discussed below.
CIPS
Other operations and maintenance expenses increased $24 million. The increase was primarily because of an $11 million increase in distribution system reliability expenditures, including storm costs, along with increased labor costs and bad debt expense. Additionally, in the first quarter of 2007, CIPS reversed an accrual of $4 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. There was no similar item in 2008.
CILCO (Illinois Regulated)
Other operations and maintenance expenses were higher by $8 million, primarily because of a $5 million increase in storm costs in 2008. Additionally, in the first quarter of 2007, CILCO (Illinois Regulated) reversed an accrual of $3 million established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions. There was no similar item in 2008. Lower employee benefit costs reduced the effect of these unfavorable items.
IP
Other operations and maintenance expenses increased $47 million, due, in part, to a $17 million increase in distribution system reliability expenditures, including storm costs. Labor costs and bad debt expense increased by $6 million each, and unrealized net MTM adjustments resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans also increased other operations and maintenance expenses between years. Additionally, in the first quarter of 2007, IP reversed an $8 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions. There was no similar item in 2008. Reducing the unfavorable effect of these items was a reduction in employee benefit costs.
Merchant Generation
Other operations and maintenance expenses increased $43 million in the Merchant Generation segment, as discussed below.
Genco
Other operations and maintenance expenses increased $12 million at Genco. Plant maintenance costs were higher by $9 million, due to scheduled outages, and labor costs increased by $5 million. Genco paid $3 million to the IPA in 2007 as part of the 2007 Illinois Electric Settlement Agreement. There was no similar item in 2008.
CILCO (AERG)
Other operations and maintenance expenses increased $25 million at CILCO (AERG), primarily because of a $12 million impairment charge recorded in 2008 related to the Indian Trails cogeneration plant discussed above. Plant maintenance costs increased by $7 million, due to scheduled outages, and labor costs increased by $3 million. CILCO (AERG) paid $1.5 million to the IPA in 2007 as part of the 2007 Illinois Electric Settlement Agreement. There was no similar item in 2008.
EEI
Other operations and maintenance expenses were comparable in 2008 and 2007.
Depreciation and Amortization
2010 versus 2009
Ameren Corporation
Ameren’s depreciation and amortization expenses increased $40 million in 2010, as compared with 2009, because of items noted below at the Ameren Companies.
Variations in depreciation and amortization expenses in Ameren’s business segments and for the Ameren Companies between 2010 and 2009 were as follows.
Ameren Missouri (UE)
Depreciation and amortization expenses increased $25 million in 2010, primarily because of capital additions and an increase in UE’s annual depreciation rate due largely to the adoption of the life span depreciation methodology as a result of the 2010 MoPSC electric rate order.
Ameren Illinois (AIC)
Depreciation and amortization expenses decreased $6 million in 2010, primarily because of a reduction in amortization of regulatory assets. An ICC rate order in April
2010 extended the amortization period of the IP integration-related regulatory asset. See Note 2 – Rate and Regulatory Matters to our financial statements under Part lI, Item 8, of this report for additional information.
Merchant Generation
Depreciation and amortization expenses increased $20 million in the Merchant Generation segment, primarily because of variations at Genco, as discussed below.
Genco
Depreciation and amortization expenses increased $17 million in 2010, primarily because of capital additions and increased depreciation rates resulting from depreciation studies performed in 2009.
2009 versus 2008
Ameren Corporation
Ameren’s depreciation and amortization expenses increased $40 million in 2009, as compared with 2008, because of items noted below at the Ameren Companies.
Variations in depreciation and amortization expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Ameren Missouri Regulated (UE)
Depreciation and amortization expenses increased $28 million in 2009, primarily because of capital additions and amortization of regulatory assets that resulted from UE’s electric rate caseorder in 2009.
Ameren Illinois Regulated(AIC)
Depreciation and amortization expenses were comparable between years in the Illinois Regulated segment. As part of the consolidated electric and natural gas rate order issued by the ICC in September 2008, the ICC changed plant asset useful lives, effective October 1, 2008. This resulted in reductions in depreciation expense at CIPS and CILCO (Illinois Regulated) and an increase in depreciation expense at IP. Capital additions partially offset the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further
increased depreciation and amortization expenses at IP. The net effect of the above items was an $18 million reduction in depreciation and amortization expenses at CILCO (Illinois Regulated) and a $14 million increase at IP. Depreciation and amortization expenses at CIPS were comparable between years.
Merchant Generation
Depreciation and amortization expenses increased $17 million in the Merchant Generation segment, primarily because of capital additions at CILCO (AERG)AERG and $3variations at Genco, as discussed below.
Genco
Genco’s depreciation and amortization expenses increased $6 million, primarily because of expense recorded by Genco in the third quarter of 2009 for the retirement of two generation units at its Meredosia power plant. Depreciation and amortization expenses were comparable at EEI between years.
2008Taxes Other Than Income Taxes
2010 versus 20072009
Ameren Corporation
Ameren’s depreciation and amortization expenses were comparable between periods. Increases in depreciation expense, resulting from capital additions in 2008, were mitigated by a reduction in expenseTaxes other than income taxes increased $29 million, because of changes initems noted below at the useful lives of plant assets resulting from rate orders in 2007 in Missouri and 2008 in Illinois, as discussed below.Ameren Companies.
Variations in depreciation and amortization expensestaxes other than income taxes in Ameren’s and CILCO’s business segments and for the Ameren Companies between 20082010 and 20072009 were as follows.follows:
Ameren Missouri Regulated (UE)
Depreciation and amortization expenses decreased $4Taxes other than income taxes increased $28 million, primarily because of the extensionhigher gross receipts taxes as a result of UE’s nuclearincreased sales, and coal-fired plants’ useful lives for purposesbecause of calculating depreciation expenseincreased property taxes due to higher assessed tax rates in conjunction with a MoPSC electric rate order effective June 2007. Reducing the benefit of this item was an increase in capital additions in 2008.Missouri.
Ameren Illinois Regulated(AIC)
Depreciation and amortization expensesTaxes other than income taxes were comparable in 2008 and 2007 in the Illinois Regulated segment. The effect of the consolidated electric and natural gas rate order issued by the ICC in 2008, as noted above, resulted in reductions in depreciation expense at CIPS and CILCO (Illinois Regulated) and an increase in depreciation expense at IP. Capital additions partially offset the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further increased depreciation and amortization expenses at IP.between years.
Merchant Generation
Depreciation and amortization expenses increased $4 million inTaxes other than income taxes were comparable between periods at the Merchant Generation segment. Depreciationsegment and amortization expenses increased $8 million at CILCO (AERG) because of capital additions in 2008. Genco’s depreciation and amortization expenses decreased $4 million, primarily because of extended useful lives resulting from a depreciation study completed in September 2007, partially
mitigated by capital additions. EEI’s depreciation and amortization expenses were comparable between years.
Taxes Other Than Income TaxesGenco.
2009 versus 2008
Ameren Corporation
Ameren’s taxes other than income taxes increased $19$16 million in 2009, primarily because of higher property and payroll taxes.
Variations in taxes other than income taxes in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Ameren Missouri Regulated (UE)
Taxes other than income taxes increased $17 million in 2009, primarily because of higher property taxes.
Ameren Illinois Regulated(AIC)
Taxes other than income taxes were comparable in 2009 and 2008 in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated), and IP.between years.
Merchant Generation
Taxes other than income taxes were comparable between years inat the Merchant Generation segment and at Genco, CILCO (AERG)Genco.
Other Income and EEI.Expenses
20082010 versus 20072009
Ameren Corporation
Ameren’s taxes other thanMiscellaneous income, taxesnet of expenses, increased $12$9 million primarilyin 2010, because of higher property taxes and higher gross receipts taxes. Increases in property taxes were reduced by invested capital electricity distribution tax credits initems noted below at the Illinois Regulated segment. These credits were related to payments made in a previous year.Ameren Companies.
Variations in taxes other than income taxesand expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 20082010 and 20072009 were as follows.follows:
Ameren Missouri Regulated (UE)
UE’s taxes other thanMiscellaneous income, taxesnet of expenses, increased $6$14 million in 2010, primarily because of higher property taxes.allowance for equity funds used during construction associated with a project to install scrubbers at UE’s Sioux plant, reduced, in part, by increased charitable contributions.
Ameren Illinois Regulated(AIC)
Taxes other thanAIC had net miscellaneous expense of $6 million in 2010, compared with net miscellaneous income taxes increasedof $2 million in 2009. Interest income decreased $5 million in the Illinois Regulated segment, primarily2010 compared with 2009 because of higher excise taxes at CIPS, CILCO (Illinois Regulated), and IP. Property taxes were comparable between years as increases in 2008 were mitigated by the favorable impact of the invested capital electricity distribution tax credits discussed above.CIPS’ note receivable from Genco matured on May 1, 2010.
Merchant Generation
Taxes other thanOther income taxesand expenses were comparable in 2008 and 2007 inbetween years at the Merchant Generation segment and for Genco, CILCO (AERG) and EEI.
Other Income and Expensesat Genco.
2009 versus 2008
Ameren Corporation
Other income and expenses were comparable in 2009 and 2008. Miscellaneous expenses decreased as expenses associated with energy efficiency and customer assistance programs under the 2007 Illinois Electric Settlement Agreement were lower in 2009. However, miscellaneous income declined because of reduced interest income, partially offset by increased allowance for equity funds used during construction.
Variations in other income and expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.follows:
Ameren Missouri Regulated (UE)
Other income and expenses were comparable between periods.years.
Ameren Illinois Regulated(AIC)
OtherMiscellaneous income, andnet of expenses, decreased $9 million, in the Illinois Regulated segment, and decreased at both CIPS and IP, primarily because of lower interest income. DecreasedReduced expenses associated with energy efficiency and customer assistance programs under the 2007 Illinois Electric Settlement Agreement mitigated this decrease. Other income and expenses at CILCO (Illinois Regulated) were comparable in 2009 and 2008.
Merchant Generation
Other income and expenses were comparable between years inat the Merchant Generation segment and at Genco, CILCO (AERG) and EEI.Genco.
2008 versus 2007
Ameren
Other income and expenses were comparable in 2008 and 2007. Miscellaneous income increased $5 million, primarily because of an increase at UE in allowance for funds used during construction, reduced by lower interest income. Miscellaneous expense increased $6 million, primarily because of increased expenses associated with contributions to social programs.
Variations in other income and expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated (UE)
Miscellaneous income increased $24 million, primarily because of an increase in allowance for funds used during construction. This increase resulted from higher rates and increased construction work in progress balances. Miscellaneous expense was comparable between years.
Illinois Regulated
Other income and expenses decreased $9 million in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, primarily because of lower interest income.
Merchant Generation
Other income and expenses in the Merchant Generation segment and at Genco, CILCO (AERG) and EEI were comparable in 2008 and 2007.
Interest Charges
2010 versus 2009
Ameren Corporation
Interest charges decreased $11 million in 2010, because of items noted below at the Ameren Companies. The decreases below were mitigated by additional interest charges resulting from the issuance of $425 million of senior notes by Ameren in May 2009.
Variations in interest charges in Ameren’s business segments and for the Ameren Companies between 2010 and 2009 were as follows.
Ameren Missouri (UE)
Interest charges decreased $16 million in 2010. Interest charges were reduced by $10 million because of a
May 2010 MoPSC electric rate order, which resulted in UE recording a regulatory asset for recovery of bank credit facility fees incurred in 2009. Additionally, interest charges were reduced by an increase in allowance for borrowed funds used during construction associated with a project to install scrubbers at UE’s Sioux plant. Partially reducing the above benefits was an increase in interest charges associated with the issuance of $350 million of senior secured notes in March 2009.
Ameren Illinois (AIC)
Interest charges decreased $10 million in 2010, primarily because of the maturity of $250 million of first mortgage bonds in June 2009.
Merchant Generation
Interest charges increased $14 million in 2010 in the Merchant Generation segment and $17 million at Genco, primarily because of the issuance of $250 million of senior unsecured notes at Genco in November 2009.
2009 versus 2008
Ameren Corporation
Ameren’s interest charges increased $68 million in 2009, because of items noted below at the Ameren Companies and because of the issuance of $425 million of senior notes at Ameren in May 2009.
Variations in interest charges in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.follows:
Ameren Missouri Regulated (UE)
Interest charges increased $36 million in 2009, primarily because of the issuance of $350 million, $450 million, and $250 million of senior secured notes in March 2009, June 2008, and April 2008, respectively. The amortization of fees related to new credit facilities entered into in the second quarter of 2009 also increased interest charges. The majority of the fees related to the new credit facilities are being amortized over a two-year period. Additionally, a reversal in interest charges previously accrued on uncertain tax positions due to favorable income tax settlements in 2008, with no similar item in 2009, had a negative impact on 2009. The maturity of $148 million of first mortgage bonds in May 2008 and refinancing of auction-rate environmental improvement revenue bonds in 2008, along with a reduction of short-term borrowings, mitigated the impact of the above items.
Ameren Illinois Regulated(AIC)
Interest charges increased $9 million in the Illinois Regulated segment because of the amortization of fees related to a new credit facility entered into in the second quarter of 2009 and as a result of matters as discussed below.
CIPS
Interest charges were comparable in 2009 and 2008.
CILCO (Illinois Regulated)
Interest charges increased $8 million in 2009, primarily because of the issuance of senior secured notes of $150 million at CILCO in December 2008 at a higher rate than the short-term borrowings it refinanced.
IP
Interest charges were comparable between years.refinanced, and because of the amortization of fees related to a credit facility entered into in the second quarter of 2009. Increased interest charges resulting from the issuance at IP of senior secured notes of $400 million and $337 million in October 2008 and
April 2008, respectively, waswere mitigated as the proceeds of these issuances were used to refinance auction-rate pollution control revenue refunding bonds, which bore default rates ranging from 12% to 18%, and to reduce short-term borrowings.
Merchant Generation
Interest charges increased $20 million in 2009 in the Merchant Generation segment, primarily because of items discussed below. Additionally, CILCORP parent company recordedincreased intercompany borrowings at AERG and amortization of fees related to new credit facilities entered into in the second quarter of 2009 and had2009. Additionally, interest charges increased intercompany borrowings.because of variations at Genco, as discussed below.
Genco
Interest charges increased $4$6 million primarilyin 2009, because of the issuance of $300 million of senior unsecured notes in April 2008.
CILCO (AERG)
Interest charges increased $12 million, primarily because of increased intercompany borrowings.
EEI
Interest charges were comparable between years.
2008 versus 2007
Ameren
Interest charges increased $17 million. Long-term debt issuances, net of maturities and redemptions, and the cost of refinancing auction-rate environmental improvement and pollution control revenue refunding bonds resulted in increased interest expense in 2008. These increases were reduced by income tax settlements in 2008.
Variations in interest charges in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated (UE)
Interest charges were comparable between periods. Interest charges associated with the issuance of senior secured notes of $450 million, $250 million, and $425 million in June 2008, April 2008, and June 2007, respectively, was
mitigated by a reduction in short-term borrowings, which were reduced with proceeds from the senior secured notes financings. The proceeds from these senior secured notes financings were also used to refinance auction-rate environmental improvement revenue refunding bonds, and to fund the maturity of $148 million of first mortgage bonds, and to reduce short-term borrowings. Additionally, interest charges were reduced by $8 million because of a reversal of interest charges previously accrued on uncertain tax positions as a result of income tax settlements in 2008.
Illinois Regulated
Interest charges increased $12 million in the Illinois Regulated segment, as discussed below.
CIPS
Interest charges decreased $7 million, primarily because of reduced short-term borrowings and a $3 million reduction from a reversal of interest charges previously accrued on uncertain tax positions as a result of an income tax settlement.
CILCO (Illinois Regulated)
Interest charges were comparable in 2008 and 2007.
IP
Interest charges increased $22 million, primarily because of the issuance of $400 million, $337 million, and $250 million of senior secured notes at IP in October 2008, April 2008, and November 2007, respectively. The $337 million senior secured notes were issued to refinance auction-rate pollution control revenue refunding bonds, while proceeds from the other debt issuances were used to reduce short-term borrowings.
Merchant Generation
Interest charges decreased $8 million in the Merchant Generation segment, as discussed below.
Genco
Interest charges were comparable between periods. Increased interest charges resulting from the issuance of $300 million of senior unsecured notes in April 2008 was mitigated by a corresponding reduction in short-term borrowings. Additionally, interest charges were reduced by $3 million as a result of an income tax settlement.
CILCO (AERG)
Interest charges decreased $4 million at CILCO (AERG), primarily because of reduced short-term borrowings.
EEI
Interest charges were comparable in 2008 and 2007.
Income Taxes
The following table presents effective income tax rates for the registrants and by segment for the years ended December 31, 2010, 2009, 2008, and 2007:2008:
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Ameren | 35 | % | 34 | % | 34 | % | 68 | %(a) | 35 | % | 34 | % | |||||||||
Missouri Regulated | 33 | 36 | 33 | ||||||||||||||||||
Illinois Regulated | 37 | 30 | 32 | ||||||||||||||||||
UE | 35 | 33 | 36 | ||||||||||||||||||
AIC | 39 | 37 | 28 | ||||||||||||||||||
Genco | (b | ) | 38 | 37 | |||||||||||||||||
Merchant Generation | 38 | 36 | 37 | (c | ) | 38 | 36 | ||||||||||||||
| (a) | The effective tax rate was 36% for 2010, after excluding the impact of the goodwill impairment charge, which is not deductible for income tax purposes. |
| (b) | The effective tax rate was 40% for 2010, after excluding the impact of the goodwill impairment charge, which is not deductible for income tax purposes. |
| (c) | The effective tax rate was 30% for 2010, after excluding the impact of the goodwill impairment charge, which is not deductible for income tax purposes. |
2010 versus 2009
Ameren Corporation
Ameren’s effective tax rate in 2010 was higher than 2009, primarily due to the unfavorable impact of the goodwill impairment charge recognized in 2010 at Ameren. Goodwill impairment charges are not deductible for income tax purposes. In addition, legislation was enacted in the first quarter of 2010 that resulted in retiree health care costs no longer being deductible for tax purposes to the extent an employer’s postretirement health care plan receives federal subsidies that provide retiree prescription drug benefits equivalent to Medicare prescription drug benefits. See Note 17 – Goodwill and Other Asset Impairments under Part II, Item 8, of this report for additional information on the goodwill impairment charges. Additional variations are discussed below.
Variations in effective tax rates for Ameren’s business segments and for the Ameren Companies between 2010 and 2009 were as follows.
Ameren Missouri (UE)
UE’s effective tax rate was higher, primarily because of the change in tax treatment of retiree health care costs, along with the decreased impact of favorable net amortization of property-related regulatory assets and liabilities and other permanent items on higher pretax book income.
Ameren Illinois (AIC)
The effective tax rate was higher, primarily because of the decreased impact of favorable net amortization of property-related regulatory assets and liabilities and permanent items on higher pretax book income.
Merchant Generation
The effective tax rate was lower in the Merchant Generation segment, because of items detailed below at Genco, partially offset by the impact of state tax credits related to capital investments and decreased Internal Revenue Code Section 199 production activity deductions on a pretax book loss.
Genco
The effective tax rate increased, after excluding the impact of the nondeductible goodwill impairment charge, primarily because of the change in tax treatment of retiree health care costs and changes to reserves for uncertain tax positions mitigated by the increased impact of state tax credits, Internal Revenue Code Section 199 production activity deductions and investment tax credit amortization on lower pretax book income.
2009 versus 2008
Ameren Corporation
Ameren’s effective tax rate in 2009 was higher than the effective tax rate in 2008 due tobecause of variations discussed below. Variations in effective tax rates for Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Ameren Missouri Regulated (UE)
UE’s effective tax rate was lower, primarily because of higher favorable net amortization of property-related regulatory assets and liabilities, partially mitigated by changes to reserves for uncertain tax positions.
Ameren Illinois Regulated(AIC)
The effective tax rate was higher, in the Illinois Regulated segment because of items detailed below.
CIPS
The effective tax rate increased, primarily because of the decreased impact of net amortization of property-related regulatory assets and liabilities, investment tax credit amortization, and permanent items on higher pretax book income.
CILCO (Illinois Regulated)
The effective tax rate was higher, primarily because of the decreased impact of permanent benefits, net amortization of property-related regulatory assets and liabilities, and investment tax credit amortization on higher pretax book income.
IP
The effective tax rate decreased, primarily because of the impact of permanent items on higher pretax book income, along with changes to reserves for uncertain tax positions.
Merchant Generation
The effective tax rate was higher inat the Merchant Generation segment because of items detailed below.below at Genco, along with the impact of deferred tax adjustments due to changes in state apportionment.
Genco
The effective tax rate increased, primarily because of the decreased impact of Internal Revenue Code Section 199
production activity deductions, along with changes to reserves for uncertain tax positions.
CILCO (AERG)
The effective tax rate was lower, primarily because of the increased impact of Internal Revenue Code Section 199 production activity deductions, along with changes to reserves for uncertain tax positions.
2008 versus 2007Income from Discontinued Operations, Net of Tax
Ameren Illinois (AIC)
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. AIC determined that the operating results of AERG qualified for discontinued operations presentation. We have therefore segregated AERG’s operating results and presented them separately as discontinued operations for all periods in this report. For Ameren’s effective tax rate was comparablefinancial statements, AERG’s results of operation remain classified as continuing operations. See Note 16 – Corporate Reorganization and Discontinued Operations under Part II, Item 8, of this report for additional information.
AIC’s income from discontinued operations (AERG) decreased $74 million in 2008 and 2007. Favorable impacts2010, compared with 2009. AERG’s results of state audit settlements and changesoperations were included in state apportionment were offset by unfavorable permanent items relatedAIC’s consolidated statement of income for all periods prior to company-owned life insuranceOctober 1, 2010. The inclusion of only nine months in 2010 contributed to the decrease in income from discontinued operations as well as other variations discussed below at the Ameren Companies.a decrease in electric margins caused by lower realized revenue per megawatt sold and higher fuel and related transportation costs. The decrease was partially offset by a reduction in income tax expense primarily caused by lower pretax book income.
VariationsAIC’s income from discontinued operations (AERG) increased $62 million in effective tax rates for Ameren’s and CILCO’s business segments and for the Ameren Companies between2009, compared with 2008. The increase in income from discontinued operations was caused by a $94 million increase in AERG’s electric margins during 2009, compared with 2008, and 2007 were as follows.
Missouri Regulated (UE)
The effective tax rate increased, primarily because of lower favorable net amortizationhigher revenues allocated to AERG under its power supply agreement with Marketing Company as a result of property-related regulatory assetshigher reimbursable expenses and liabilities, alonghigher generation relative to Genco in accordance with the AERG PSA. Additionally, AERG’s other operations and maintenance expenses decreased Internal Revenue Code Section 199 production activity deductions in 2008.
Illinois Regulated
The effective tax rate decreased in the Illinois Regulated segment because of items detailed below.
CIPS
The effective tax rate was lower,$22 million, primarily because of the impact of net amortization of property-related regulatory assetsa $9 million reduction in plant maintenance costs and liabilities and permanent items on lower pretaxan $11 million reduction in asset impairment charges. Factors reducing income from discontinued operations (AERG) included a $30 million increase in 2008.
CILCO (Illinois Regulated)
The effectiveincome tax rate was higher,expense primarily because of lower tax credits, lower favorable net amortization of property-related regulatory assets and liabilities, and lower favorable permanent benefits related to company-owned life insurance.
IP
The effective tax rate increased,higher pretax book income, a $12 million increase in interest charges primarily because of lower favorable netincreased intercompany borrowings, and an $11 million increase in depreciation and amortization of property-related regulatory assets and liabilities, lower tax credits, and the impact of other permanent items as well as increased reserves for uncertain tax positions on lower pretax book income in 2008.
Merchant Generation
The effective tax rate decreased in the Merchant Generation segment because of items detailed below.
Genco
The effective tax rate was lower,expenses primarily because of the increased impact of Internal Revenue Code Section 199 production activity deductions and research tax credits.
capital additions.
CILCO (AERG)
The effective tax rate increased, primarily because of the impact of Internal Revenue Code Section 199 production activity deductions.
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 a 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 natural gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE CIPS, CILCO (Illinois Regulated) and IP.AIC. For operating cash flows, Genco and AERG rely on power sales to Marketing Company which sold power through financial contracts that were part of the 2007 Illinois Electric Settlement Agreement and various power procurement processes in the non-rate-regulated Illinois market. Marketing Company also sells power through other primarily market-based contracts with wholesale and retail customers. In addition to using cash flows from operating activities, the Ameren Companies use available cash, credit facilities,facility borrowings, commercial paper issuances, money pool borrowings, or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. The use of operating cash flows and credit facility or short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at December 31, 2009, for Genco and CILCO. The Ameren Companies may reduce their credit facility or short-term borrowings with cash from operations or, discretionarilyat their discretion, with long-term borrowings or, in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and natural gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses of approximately 50% to 55% equity. WeThe Ameren Companies plan to implement ourtheir long-term financing plans for debt, equity, or equity-linked securities in order to finance ourtheir operations appropriately, meet scheduled debt maturities, and maintain financial strength and flexibility.
In 2008 and 2009, the global capital and credit markets experienced extreme volatility. See Outlook for a discussion of the implications of this volatility for our industry as a whole, including the Ameren Companies, and how we addressed these issues.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2010, 2009 2008 and 2007:2008:
Net Cash Provided By Operating Activities | Net Cash (Used In) Investing Activities | Net Cash Provided By (Used In) Financing Activities | Net Cash Provided By Operating Activities | Net Cash (Used In) Investing Activities | Net Cash Provided By (Used In) Financing Activities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||||||||||||
Ameren(a) | $ | 1,977 | $ | 1,524 | $ | 1,108 | $ | (1,789) | $ | (2,097) | $ (1,468) | $ | 342 | $ | 310 | $ | 578 | $ | 1,842 | $ | 1,977 | $ | 1,524 | $ | (1,112 | ) | $ | (1,789 | ) | $ | (2,097 | ) | $ | (807 | ) | $ | 342 | $ | 310 | ||||||||||||||||||||||||||
UE | 972 | 543 | 587 | (955) | (1,033) | (700) | 250 | 305 | 297 | 978 | 972 | 543 | (706 | ) | (955 | ) | (1,033 | ) | (337 | ) | 250 | 305 | |||||||||||||||||||||||||||||||||||||||||||
CIPS | 191 | 101 | 14 | (68) | (57) | (42) | (95 | ) | (70 | ) | 48 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
AIC | 597 | 859 | 488 | (257 | ) | (452 | ) | (577 | ) | (324 | ) | (151 | ) | 103 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Genco | 232 | 246 | 255 | (349) | (330) | (210) | 121 | 84 | (44 | ) | 280 | 253 | 421 | (29 | ) | (389 | ) | (366 | ) | (251 | ) | 139 | (54 | ) | |||||||||||||||||||||||||||||||||||||||||
CILCO | 263 | 207 | 74 | (153) | (317) | (212) | (22 | ) | 104 | 141 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
IP | 409 | 178 | 30 | (189) | (246) | (186) | (80 | ) | 112 | 162 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
2010 versus 2009
Ameren Corporation
Ameren’s cash from operating activities decreased in 2010 compared with 2009. The following items contributed to the decrease in cash from operating activities during 2010, compared with 2009:
| Ÿ | A $116 million decrease in billed revenues, net of payments to suppliers, for pass-through natural gas commodity costs primarily caused by higher-priced natural gas injected into storage during 2008 and billed to customers in 2009. |
| Ÿ | Accounts receivable and unbilled revenue balances increased by $106 million, primarily because of higher utility rates and colder December weather in 2010, compared with December 2009. |
| Ÿ | Deferred FAC costs increased $100 million as net base fuel costs incurred at UE exceeded the amounts allowed in base rates due to higher fuel costs and lower off-system sales as a result of warmer weather increasing native load demand. |
| Ÿ | Deferred budget billing balances increased by $74 million, partially as a result of warmer summer weather, which increased sales volumes over budget-billed amounts. |
| Ÿ | An overall $56 million increase in collateral posted with counterparties due, in part, to the items discussed at the subsidiaries below, offset by a $105 million reduction in collateral posted by nonregistrant subsidiaries, primarily due to changes in the market price of power. |
| Ÿ | A $53 million decrease in cash from operating activities associated with the December 2005 Taum Sauk incident, primarily as a result of reduced insurance recoveries. See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for additional Taum Sauk information. |
| Ÿ | A $39 million increase in payments related to the Callaway nuclear plant refueling and maintenance outage that occurred in 2010, but did not occur in 2009. |
| Ÿ | A $14 million increase in payments associated with major outages at coal-fired plants, primarily at UE. |
| Ÿ | A $12 million increase in property tax payments caused primarily by higher assessed tax rates in Missouri. |
| Ÿ | A $10 million one-time donation in 2010 for customer assistance programs required by the 2009 Illinois energy legislation that authorized the bad debt rate adjustment mechanism and was approved by the ICC in February 2010. |
| Ÿ | Payments for professional services, additional franchise taxes, and other administrative items necessary to complete the AIC Merger and AERG distribution totaled $8 million. |
The following items reduced the decrease in Ameren’s cash from operating activities during 2010, compared with 2009:
| Ÿ | Electric and natural gas margins, as discussed in Results of Operations, increased by $212 million, excluding impacts of MTM transactions. |
| Ÿ | Income tax refunds of $92 million in 2010, compared with income tax payments of $9 million in 2009. The refund primarily resulted from an acceleration of depreciation deductions authorized by economic stimulus legislation. |
| Ÿ | Ameren reduced its coal inventory levels, primarily at the Merchant Generation segment, in 2010. The impact of the inventory reduction is estimated to have resulted in cash savings of $69 million in 2010. |
| Ÿ | A $32 million decrease in major storm restoration costs. |
| Ÿ | Contributions to the pension and postretirement plans were $31 million lower in 2010. |
| Ÿ | A $14 million reduction in severance payments as a result of the voluntary and involuntary separation programs initiated in both years. |
UE
UE’s cash from operating activities increased in 2010 compared with 2009. The following items contributed to the increase in cash from operating activities during 2010, compared with 2009:
| Ÿ | Higher electric and natural gas margins as discussed in Results of Operations including the benefit of MoPSC-approved electric rate increases effective on March 1, 2009, and June 21, 2010, as well as favorable weather conditions. Margins increased by $281 million, excluding the impacts of MTM transactions. |
| Ÿ | A $31 million reduction in collateral posted with counterparties due in part to improved credit ratings and to changes in the market price of power and natural gas. |
| Ÿ | A $13 million decrease in major storm restoration costs. |
| Ÿ | Contributions to the pension and postretirement plans were $8 million lower in 2010. |
| Ÿ | A $5 million reduction in severance payments as a result of the voluntary and involuntary separation programs initiated in both years. |
The following items reduced the increase in UE’s cash from operating activities during 2010, compared with 2009:
| Ÿ | A $102 million decrease in income tax refunds, primarily due to higher pretax book income and a reduction in 2010 of the benefit of a change in tax treatment of electric generation plant expenditures taken in 2009. |
| Ÿ | Deferred FAC costs increased $100 million as net base fuel costs incurred at UE exceeded the amounts allowed in base rates due to higher fuel costs and lower off-system sales as a result of warmer weather increasing native load demand. |
| Ÿ | A $53 million decrease in cash from operating activities associated with the December 2005 Taum Sauk incident discussed above. |
| Ÿ | A $39 million increase in payments related to a Callaway nuclear plant refueling and maintenance outage that occurred in 2010, but did not occur in 2009. |
| Ÿ | A $24 million increase in payments associated with major outages at coal-fired plants. |
| Ÿ | A $12 million increase in property tax payments, caused primarily by higher assessed tax rates. |
AIC
AIC’s cash from operating activities associated with continuing operations decreased in 2010 compared with 2009. The following items contributed to the decrease in cash from operating activities associated with continuing operations during 2010, compared with 2009:
| Ÿ | A $192 million increase in collateral posted with counterparties due, in part, to changes in the market price of natural gas and collateral posting requirements. |
| Ÿ | Accounts receivable and unbilled revenue balances increased by $183 million, primarily because of higher utility rates and colder December weather in 2010, compared with December 2009. |
| Ÿ | A $98 million decrease in billed revenue, net of payments to suppliers, for pass-through natural gas commodity costs primarily caused by higher-priced natural gas injected into storage during 2008 and billed to customers in 2009. |
| Ÿ | Deferred budget billing balances increased by $60 million, partially as a result of warmer summer weather, which increased sales volumes over budget billed amounts. |
| Ÿ | A $10 million one-time donation in 2010 for customer assistance programs required by the 2009 Illinois legislation that authorized the bad debt rate adjustment mechanism and was approved by the ICC in February 2010. |
| Ÿ | Payments for professional services, additional franchise taxes, and other administrative items necessary to complete the AIC Merger and AERG distribution, which totaled $7 million. |
| Ÿ | In 2009, AIC received $5 million from Marketing Company for the costs of upgrades to AIC’s electric transmission system. There was no such receipt in 2010. |
The following items reduced the decrease in AIC’s cash from operating activities associated with continuing operations during 2010, compared with 2009:
| Ÿ | Electric and natural gas margins, as discussed in Results of Operations, increased by $187 million, excluding the impacts of MTM transactions. |
| Ÿ | Income tax refunds of $52 million in 2010, compared with income tax payments of $61 million in 2009. The refund primarily resulted from an acceleration of depreciation deductions authorized by economic stimulus legislation. |
| Ÿ | A $19 million decrease in major storm restoration costs. |
| Ÿ | Contributions to the pension and postretirement plans were $11 million lower in 2010. |
| Ÿ | A $6 million decrease in interest payments, primarily due to the first mortgage bond maturity in June 2009. |
AIC’s cash from operating activities associated with discontinued operations decreased in 2010 compared with 2009. AERG’s cash flows were included in AIC’s consolidated statement of cash flows for all periods prior to October 1, 2010. The inclusion of only nine months in 2010 was the primary cause of the decrease in cash flows, along with a reduction in receipts from Marketing Company under the AERG PSA primarily due to lower market prices, as discussed in Results of Operations. A decrease in income tax payments, primarily due to lower pretax book income, and an acceleration of depreciation deductions authorized by economic stimulus legislation partially offset the decrease in AERG’s operating cash flows.
Genco
Genco’s cash from operating activities increased in 2010 compared with 2009. The following items contributed to the increase in cash from operating activities during 2010, compared with 2009:
| Ÿ | A $73 million decrease in income tax payments, primarily due to lower pretax book income, deductions relating to environmental expenditures, and an acceleration of depreciation deductions authorized by economic stimulus legislation. |
| Ÿ | Reduced coal inventory levels in 2010, which are estimated to have resulted in cash savings of $50 million in 2010. |
| Ÿ | Lower labor expenditures resulting from staff reductions and fewer major outages at its coal-fired plants. |
| Ÿ | A $7 million reduction in use tax payments as Genco and EEI began claiming tax exemptions and credits for purchase transactions related to their generation operations. |
| Ÿ | Contributions to the pension plans were $6 million lower in 2010. |
The following items reduced the increase in Genco’s cash from operating activities during 2010, compared with 2009:
| Ÿ | Electric margins, as discussed in Results of Operations, decreased by $99 million, excluding impacts of MTM transactions. |
| Ÿ | A $13 million increase in interest payments, primarily due to the senior unsecured notes issued in November 2009, which required interest payments in 2010, but not in 2009. |
2009 versus 2008
Ameren Corporation
Ameren’s cash from operating activities increased in 2009 compared with 2008. Operating activities associated with the December 2005 Taum Sauk incident resulted in a $256 million increase in cash during 2009, compared with 2008. The 2009 increase was a result of a $65 million increase in insurance recoveries received as well as a $191 million reduction in cash payments compared with 2008. See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for information aboutfollowing items contributed
the Taum Sauk property insurance settlement agreement with all but three of the property insurance carriers and the related settlement payment received during 2009. Other factors contributing
to the increase in cash from operating activities during 2009, compared with 2008, included2008:
| Ÿ | A $256 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident. The increase was a result of a $65 million increase in insurance recoveries and a $191 million reduction in payments compared with 2008. During 2009, UE received a property insurance settlement payment from all but three of the property insurance carriers. See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for information about the Taum Sauk incident. |
| Ÿ | A $198 million decrease in payments for natural gas injections into storage because of lower prices. |
| Ÿ | A $97 million decrease in income tax payments primarily at UE. |
| Ÿ | The over-collected deferred budget billing balance increased by $27 million, partially caused by a reduction in commodity costs and a decrease in sales volumes compared to budgeted billed amounts. |
| Ÿ | Less cash used for operations and maintenance activities, because many plant-related projects were reduced, deferred, or cancelled and because of the absence of a Callaway nuclear plant refueling and maintenance outage in 2009. |
The following items reduced the cost of natural gas purchased for inventories because of lower prices, a $97 million decrease, net of refunds, in income tax payments primarily at UE as discussed below, and an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms. Additionally, as discussed in Results of Operations, less cash was used for operations and
maintenance activities because many plant-related projects were either reduced, deferred, or cancelled as well as the absence of a Callaway nuclear plant refueling and maintenance outage in 2009. Factors reducing the increase inAmeren’s cash from operating activities during 2009, compared with 2008, included a $682008:
| Ÿ | A $75 million increase in interest |
| Ÿ | A decrease in natural gas costs over-recovered from customers under the PGA. |
| Ÿ | A $35 million increase in pension and postretirement plan contributions. |
| Ÿ | Lower electric margins, as discussed in Results of Operations, including the absence in 2009 of the 2008 lump-sum settlement payment received by Genco from a coal mine owner for the early termination of a coal supply contract. |
| Ÿ | A $21 million decrease in customer advances for construction. |
| Ÿ | The 2009 voluntary and involuntary separation programs, which resulted in severance payments of $16 million. |
| Ÿ | An increase in annual incentive compensation payments. |
| Ÿ | An $8 million increase in cash payments for major storm restoration costs. |
UE
UE’s cash from operating activities increased in 2009 compared with 2008. The increase was primarily due to net income tax refunds of $208 million in 2009 compared with net income tax payments of $130 million in 2008, and a $256 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident, as discussed above. The significant change in income taxes is primarily a result of an acceleration of deductions due to economic stimulus legislation and a change in tax treatment of electric generation plant expenditures. Other factors contributingfollowing items contributed to the increase in cash from operating activities during 2009, compared with 2008, included2008:
| Ÿ | Income tax refunds of $208 million in 2009 compared with income tax payments of $130 million in 2008. The |
significant change in income taxes was primarily a result of an acceleration of deductions due to economic stimulus legislation and a change in tax treatment of electric generation plant expenditures. |
| Ÿ | A $256 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident, as discussed above. |
| Ÿ | A $20 million decrease in payments for natural gas injections into storage because of lower prices. |
| Ÿ | Higher electric margins as discussed in Results of Operations. |
| Ÿ | An increase in natural gas costs over-recovered from customers under the PGA. |
| Ÿ | Less cash used for operations and maintenance activities, because several plant-related projects were reduced, deferred, or cancelled and because of the absence of a Callaway nuclear plant refueling and maintenance outage in 2009. |
The following items reduced the cost of natural gas purchased for inventories because of lower prices, higher electric margins, as discussed in Results of Operations, and an increase in natural gas costs over-recovered from customers under the PGA. Additionally, as discussed in Results of Operations, less cash was used for operations and maintenance activities, because several plant-related projects were either reduced, deferred, or cancelled as well as the absence of a Callaway nuclear plant refueling and maintenance outage in 2009. Factors reducing the increase inUE’s cash from operating activities during 2009, compared with 2008, included the collection of an $85 million affiliate receivable in 2008 that did not occur in 2009, a $39 million increase in interest payments, a $16 million increase in pension and other postretirement plan contributions, a $10 million increase in energy efficiency expenditures for new customer programs, a $6 million increase in major storm restoration costs, and $6 million of employee severance payments as a result of the 2009 voluntary and involuntary separation programs.2008:
CIPS’
| Ÿ | The collection of an $85 million affiliate receivable in 2008 that did not occur in 2009. |
| Ÿ | A $39 million increase in interest payments, primarily due to the senior secured notes issued in April 2008, June 2008, and March 2009. |
| Ÿ | A $16 million increase in pension and other postretirement plan contributions. |
| Ÿ | A $10 million increase in energy efficiency expenditures for new customer programs. |
| Ÿ | A $6 million increase in major storm restoration costs. |
| Ÿ | The 2009 voluntary and involuntary separation programs, which resulted in severance payments of $6 million. |
AIC
AIC’s cash from operating activities associated with continuing operations increased in 2009 compared with 2008. The following items contributed to the increase in cash from operating activities associated with continuing operations during 2009, compared with 2008:
| Ÿ | A $178 million decrease in payments for natural gas injections into storage because of lower prices. |
| Ÿ | A $176 million net reduction in collateral posted with suppliers due in part to improved credit ratings. |
| Ÿ | Higher electric and natural gas margins as discussed in Results of Operations. |
| Ÿ | Accounts receivable and unbilled revenue balances decreased by $167 million, primarily because of milder weather and lower natural gas commodity costs. |
| Ÿ | The over-collected deferred budget billing balance increased by $44 million, partially caused by a reduction in commodity costs and a decrease in sales volumes compared to budgeted billed amounts. |
The following items reduced the increase in AIC’s cash from operating activities associated with continuing operations during 2009, compared with 2008:
| Ÿ | Income tax payments of $61 million in 2009, compared with income tax refunds of $72 million in 2008, primarily due to higher pretax book income. |
| Ÿ | A decrease in natural gas costs over-recovered from customers under the PGA. |
| Ÿ | A $21 million increase in interest payments primarily due to the senior secured notes issued in October 2008. |
| Ÿ | A $21 million reduction in customer advances for construction. |
| Ÿ | A $7 million increase in pension and other postretirement plan contributions. |
AIC’s cash from operating activities associated with discontinued operations decreased in 2009 compared with 2008. Factors contributing to the increasedecrease in cash from operating activities at AERG during 2009, compared with 2008, included a $57 million net reduction in collateral posted with suppliers due in part to improved credit ratings, a $40 million decrease in the cost of natural gas purchased for inventories because of lower prices, higher electric and natural gas margins as discussed in Results of Operations, an increase in electric costs over-recovered from customers under cost recovery mechanisms, and a $5 million decrease
in interest payments. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included net income tax payments of $24$68 million in 2009, compared with net income tax refunds of $21$8 million in 2008, a decrease in natural gas costs over-recovered from customers under the PGA, and a $5 million increase in major storm restoration costs.
Genco’s cash from operating activities decreased in 2009 compared with 2008. Factors contributingprimarily due to a decrease in cash from operating activities during 2009, compared with 2008, included lower electric margins as discussed in Results of Operations, including the 2008 lump-sum settlement payment received from a coal mine owner as well as the absence of $7 million, net of premiums, of replacement power insurance recoveries received in 2008 from an affiliate as the policy was not renewed. Other factors contributing to the decrease in cash from operating activities during 2009, compared with 2008, included a $23 million increase in income tax payments, net of refunds, a $6 million increase in interest payments, and $4 million of employee severance payments as a result of the 2009 voluntary and involuntary separation programs. Factors offsetting the decrease in cash from operating activities during 2009, compared with 2008, included reduced coal purchases in 2009 as generation levels declined and a $10 million reduction in funding required by the 2007 Illinois Electric Settlement Agreement.
CILCO’s cash from operating activities increased in 2009 compared with 2008. Factors contributing to the increase in cash from operating activities during 2009, compared with 2008, included higher electric margins as discussed in Results of Operations, a $58 million decrease in the cost of natural gas purchased for inventories because of lower prices, and a $45 million net reduction in collateral posted with suppliers due in part to improved credit ratings. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included net income tax payments of $82 million in 2009, compared with net income tax refunds of $15 million in 2008,pretax book income; increased coal purchases to build inventories at the Duck Creek generating facility as a result of switching coal blends in 2009, a $6 million increase in pension2009; and other postretirement plan contributions, a $6 million increase in interest payments, the absence of $5 million, net of premiums, of replacement power insurance recoveries received in 2008 from an affiliate, as the policy was not renewed, arenewed. Factors partially reducing the decrease in natural gas costs over-recovered from customers under the PGA, and an increase in annual incentive compensation payments.
IP’s cash from operating activities at AERG during 2009, compared with 2008, included a $98 million increase in receipts from Marketing Company under the AERG PSA, primarily because of increased generation levels relative to Genco, as discussed in Results of Operations, and a $4 million reduction in funding required by the 2007 Illinois Settlement Agreement.
Genco
Genco’s cash from operating activities decreased in 2009 compared with 2008. Factors contributingThe following items contributed to the increasedecrease in cash from operating activities during 2009, compared with 2008, included higher electric and natural gas margins as discussed in Results of Operations, an $802008:
| Ÿ | Electric margins, as discussed in Results of Operations, decreased by $265 million, excluding impacts of MTM transactions. A one-time lump-sum settlement payment was received in 2008 from a coal mine owner for early termination of a contract, which was included in electric margins in 2008 and did not recur in 2009. |
| Ÿ | A $9 million increase in interest payments, primarily due to the senior unsecured notes issued in April 2008. |
| Ÿ | The 2009 voluntary and involuntary separation programs resulted in severance payments of $4 million. |
The following items reduced the decrease in the cost of natural gas purchased for inventories because
of lower prices, a $74 million net decrease in collateral posted with suppliers due in part to improved credit ratings, an increase in electric costs over-recovered from customers under cost recovery mechanisms, and a $3 million decrease in major storm restoration costs. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase inGenco’s cash from operating activities during 2009, compared with 2008, included net income tax payments of $22 million in 2009, compared with net income tax refunds of $43 million in 2008, a decrease in natural gas cost over-recovered from customers under the PGA, a $22 million increase in interest payments, and a $15 million reduction in customer advances for construction.2008:
2008 versus 2007
Ameren’s cash from operating activities increased in 2008, compared to 2007, primarily because of higher electric and natural gas margins as discussed in Results of Operations, a $177 million decrease in income tax payments (net of refunds), and improved collections of receivables in 2008. The reduction in income tax payments was largely attributable to higher depreciation allowed for tax purposes. In 2007, receivables from the Ameren Illinois Utilities had increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential electric settlement agreement, and deterioration of collections. However, collections improved in 2008. Additionally, Ameren experienced an $87 million benefit to cash flows for 2008 as compared with 2007 because of the timing of cash receipts for MISO receivables. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared with 2007. Cash outflows in accordance with the settlement, net of reimbursements from generators, were $84 million less in 2008 than in 2007. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a discussion of the 2007 Illinois Electric Settlement Agreement. In addition, Ameren’s cash flows from operations increased in 2008 compared with 2007 because of a $40 million reduction in storm restoration costs, over-recovery under the PGAs, and a $27 million payment received by Genco in 2008 as part of a coal contract settlement for increased costs for coal and transportation that Genco expected to incur in 2009 because of the premature closure of an Illinois mine at the end of 2007. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, for information on the coal contract settlement. Factors that offset, in part, the favorable variance in cash flows from operations in 2008 were a $93 million increase in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries, an increase in natural gas inventories resulting from price increases, higher interest payments, and higher levels of collateral posted with suppliers.
At UE, cash from operating activities decreased in 2008, compared to 2007. The decrease is primarily due to a $24 million increase in net income tax payments in 2008, lower electric margins, increased system reliability expenditures as discussed in Results of Operations, and
higher levels of net collateral posted with suppliers. Also contributing to the unfavorable variance in 2008 was a $93 million increase in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries, and a $146 million net decrease in affiliate payables. Factors increasing cash from operations included a $34 million decrease in payments for storm restorations, a decrease in other operations and maintenance expenditures related to the Callaway nuclear plant refueling and maintenance outage in 2008 as compared with the 2007 refueling and maintenance outage, reduction in interest payments, and the collection in 2008 of an $85 million affiliate receivable. In addition, cash flows from operations increased in 2008 compared with 2007 because of the timing of cash receipts for MISO receivables.
At CIPS, cash from operating activities increased in 2008 compared with 2007. The increase was primarily due to net income tax refunds of $21 million in 2008, compared with net income tax payments of $44 million in 2007, an increase in gas cost over-recovery from customers under the PGA, a $7 million increase in customer advances for construction, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared with 2007. CIPS’ cash outflows from the settlement, net of reimbursements from generators, were $26 million less in 2008 than in 2007. CIPS experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the 2007 Illinois Electric Settlement Agreement compared with 2007. Partially offsetting the favorable variance in cash flow from operations was a larger increase in natural gas inventories in 2008 than in 2007, a decrease in electric costs over-recovered from customers, and higher net levels of collateral posted with suppliers.
Genco’s cash from operating activities decreased in 2008 compared with 2007 primarily due to an increase in fuel inventory and an increase in net income tax payments of $13 million. Reducing the unfavorable variance in cash flow from operations were higher electric margins, a payment from an Illinois coal mine owner for the premature closure of an Illinois mine, as discussed above, and a $6 million reduction in funding required by the 2007 Illinois Electric Settlement Agreement in 2008 compared with 2007.
CILCO’s cash from operating activities increased in 2008, compared with 2007. The increase was primarily due to net income tax refunds of $15 million in 2008 compared with net income tax payments of $35 million in 2007, higher electric margins, a reduction of coal inventory at AERG, an increase in gas cost recovered from customers under a PGA, an increase in electric cost over-recovered from customers, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a
potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared with 2007. The cash outflows related to the settlement, including AERG’s obligation, were $16 million lower in 2008 than in 2007. Partially offsetting these increases in cash from operations were a larger increase in natural gas inventories during 2008 compared with 2007, as both price and volumes increased, and higher net levels of collateral posted with suppliers.
IP’s cash from operating activities increased in 2008, compared with 2007. The increase was primarily due to net income tax refunds of $43 million in 2008, compared with net income tax payments of $18 million in 2007, increased electric and natural gas margins, an increase in gas cost recovered from customers under a PGA, an increase in electric power costs over-recovered from customers, a $7 million increase in customer advances for construction, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared to 2007. IP cash outflows related to the settlement, net of reimbursements from generators, were $35 million lower in 2008 than in 2007. IP experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the 2007 Illinois Electric Settlement Agreement compared with 2007. In addition, operating cash required for major repairs in response to 2008 storms was $8 million less than major storm repairs in 2007. Partially offsetting these increases to operating cash flows were a $10 million increase in interest payments and higher net levels of collateral posted with suppliers.
| Ÿ | A $78 million reduction in income tax payments primarily because of lower pretax book income at EEI. |
| Ÿ | Reduced coal purchases in 2009 as generation levels declined. |
Pension Funding
Ameren’s pension plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, Ameren expects to
fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2009,2010, its investment performance in 2009,2010, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $225$110 million in each of the next five years, with aggregate estimated contributions of $740$470 million. We expect UE’s, CIPS’,AIC’s, and Genco’s CILCO’s, and IP’s portion of the future funding requirements to be 66%63%, 6%,28% and 9%, 9% and 10%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. In 2009,2010, Ameren contributed $99$81 million to its pension plans. See Note 11 – Retirement Benefits under Part II, Item 8, of this report and Outlook for additional information.
Cash Flows from Investing Activities
2010 versus 2009
Ameren’s cash used in investing activities decreased by $677 million during 2010, compared with 2009. There was a $673 million decrease in capital expenditures as compared with 2009 as a result of reductions in planned capital expenditures for the distribution system and power plant improvements during 2010, a $109 million reduction in capital expenditures to repair severe storm damage, and the completion of power plant scrubber projects in the Merchant Generation segment during 2009 and early 2010. Cash flows from investing activities in 2010 also benefited from the sale of 25% of Genco’s Columbia CT facility and other properties.
UE’s cash used in investing activities decreased by $249 million during 2010, compared with 2009. There was a $264 million decrease in capital expenditures as compared with 2009 as a result of reductions in planned capital expenditures for the distribution system and power plant improvements during 2010, as well as a $74 million reduction in capital expenditures to repair severe storm damage. This cash benefit was reduced by a $10 million increase in nuclear fuel expenditures related to the timing of purchases and a $12 million net decrease in nuclear decommissioning trust fund activities.
AIC’s cash used in investing activities decreased by $195 million during 2010, compared with 2009. There was a $70 million decrease in capital expenditures compared with 2009 as a result of reductions in planned capital expenditures for the distribution system during 2010 in response to revenues granted being significantly less than requested in a rate proceeding, as well as a $35 million reduction in capital expenditures to repair severe storm damage. Similar planned capital expenditure reductions at AERG resulted in the $85 million decrease in capital expenditures of discontinued operations. Additionally, AIC’s advances to ATXI for construction under a joint ownership agreement decreased during 2010 as the project approached completion. AIC received funding for this
construction under a generator interconnection agreement related to ongoing transmission upgrade projects.
Genco’s cash used in investing activities decreased by $360 million during 2010, compared with 2009. Reductions in planned capital expenditures, as well as completion of power plant scrubber projects during 2009, resulted in a $221 million decrease in capital expenditures compared with 2009. Cash flows from investing activities in 2010 also benefited from the $18 million of proceeds Genco received from the sale of 25% of its Columbia CT facility and net repayment of money pool advances.
2009 versus 2008
Ameren used less cash for investing activities in 2009 than in 2008. Net cash used for capital expenditures decreased in 2009 as a result of efforts to reduce, defer or cancel capital expenditure programs in light of economic conditions and the completion of power plant scrubber projects in the Merchant Generation business.segment. Additionally, a $93 million decrease in nuclear fuel expenditures relateddue to timing of purchases and a $10 million decrease in emission allowance purchases, because ofdue to lower prices and lower generation levels, as well as reduced emission levels resulting from completion of plant scrubber projects in 2009, benefited cash during 2009.
UE’s cash used in investing activities decreased by $78 million during 2009, compared with 2008. Nuclear fuel expenditures decreased $93 million as a result of the timing of purchases. Cash used in investing activities in 2009 did not benefit from the receipt of $36 million in proceeds from intercompany note receivables with Ameren and one of its subsidiaries, as occurred during 2008. Capital expenditures were consistent year over year. Reductions in planned capital expenditures for distribution system and power plant improvements in 2009 were offset by increased expenditures to repair severe storm damage and $93 million of rebuilding expenditures at Taum Sauk rebuild expenditures.Sauk.
CIPS’AIC’s cash used in investing activities during 2009 increaseddecreased by $125 million compared with 2008. Capital2008, as a result of a $165 million decrease in capital expenditures increased $14of discontinued operations (AERG). The decrease in capital expenditures was driven by ongoing efforts to reduce, defer, or cancel capital expenditure programs. This cash benefit was reduced by an $20 million increase in 2009 from 2008 primarily because of increasedutility capital expenditures to repair severe storm damage.damage and by an increase in advances to ATXI for construction under a joint ownership agreement. AIC received funding for this construction under a generator interconnection agreement related to ongoing transmission upgrade projects.
Genco’s cash used in investing activities increased by $23 million in 2009 compared with 2008 because of $73 million of net money pool advances in 2009. Capital expenditures decreased $40$37 million, principally because of reduced spending related tofor power plant scrubber projects. One scrubber project was completed in November 2009, and a second scrubber project is estimated to bewas completed in 2010. Emission allowance purchases decreased $11$10 million because of
lower prices and lower generation levels, as well as reduced emission levels resulting from the completion of a plant scrubber project in 2009, which resulted in a benefit to cash in 2009.
CILCO’s cash used in investing activities decreased in 2009, compared with 2008, as a result of a $165 million decrease in capital expenditures, primarily because of the completion of a power plant scrubber project in March 2009 and other reductions in capital expenditures at AERG.
IP’s cash used in investing activities decreased in 2009 compared with 2008, primarily as a result of money pool activity. During 2009, IP received a net repayment of $44 million in money pool advances compared with $44 million of net contributions during 2008. Partially offsetting this benefit to cash was an increase in advances to AITC for construction under a joint ownership agreement. IP received funding for this construction under a generator interconnection agreement related to on-going transmission upgrade projects.
2008 versus 2007
Ameren used more cash for investing activities in 2008, than in 2007. Net cash used for capital expenditures increased in 2008 as a result of power plant scrubber projects, upgrades at various power plants, and reliability improvements of the transmission and distribution system. Additionally, increased purchases and higher prices resulted in a $105 million increase in nuclear fuel expenditures.
UE’s cash used in investing activities increased during 2008, compared with 2007. Nuclear fuel expenditures increased $105 million resulting from increased purchases for future refueling outages at its Callaway nuclear plant and higher prices. In addition, capital expenditures increased $249 million. This increase was a result of increased spending related to a power plant scrubber project, reliability improvements of the transmission and distribution system, and various plant upgrades. This increase was partially offset by UE’s receipt of $36 million in proceeds from intercompany note receivables with Ameren, and one of its subsidiaries.
CIPS’ cash used in investing activities during 2008 increased, compared with 2007. Capital expenditures increased $17 million in 2008 from 2007, primarily because of reliability improvements to the transmission and distribution system. During both years, this was offset by cash received from payments on an intercompany note receivable from Genco.
Genco’s cash used in investing activities increased in 2008 compared with 2007. Capital expenditures increased $126 million, principally because of a power plant scrubber project. This increase was offset, in part, by a $7 million decrease in emission allowance purchases.
CILCO’s cash used in investing activities increased in 2008, compared with 2007. Cash used in investing activities increased as a result of a $65 million increase in capital expenditures, primarily because of a power plant scrubber project and plant upgrades at AERG. The receipt of net repayments of money pool advances in 2007 compared to 2008 also increased cash flows used in investing activities in 2008.
IP’s cash used in investing activities increased in 2008 compared with 2007. Capital expenditures increased by $8 million in 2008 from 2007, primarily because of reliability improvements to the transmission and distribution system. Net money pool advances increased by $44 million in 2008 compared with 2007.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2010, 2009, 2008, and 2007:2008:
| Capital Expenditures | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||
Ameren(a) | $ | 1,704 | $ | 1,896 | $ | 1,381 | $ | 1,031 | $ | 1,704 | $ | 1,896 | |||||||||
UE | 872 | 874 | 625 | 608 | 872 | 874 | |||||||||||||||
CIPS | 110 | 96 | 79 | ||||||||||||||||||
AIC | 286 | 356 | 345 | ||||||||||||||||||
Genco | 277 | 317 | 191 | 95 | 316 | 353 | |||||||||||||||
CILCO (Illinois Regulated) | 63 | 61 | 64 | ||||||||||||||||||
CILCO (AERG) | 91 | 258 | 190 | ||||||||||||||||||
IP | 186 | 186 | 178 | ||||||||||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
Ameren’s 20092010 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $173$130 million toward two scrubbers at its Sioux power plant, which were completed in 2010. At Genco, there was a scrubber at one of its power plants and $93 million toward the Taum Sauk rebuild, and it incurred storm-related expenditures of $78 million. CIPS, CILCO and IP incurred storm-related expenditurescash outlay of $29 million $3 million, and $5 million, respectively. At Genco and AERG, there were cash outlays of $169 million and $38 million, respectively, for power plant scrubber projects. The scrubbers are necessary to comply with environmental regulations. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE CIPS, CILCO and IPAIC, as well as to fund various plant upgrades.
Ameren’s 2009 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $173 million toward two scrubbers at its Sioux power plant, and $93 million toward the Taum Sauk rebuild, and it incurred storm-related expenditures of $78 million. AIC incurred storm-related expenditures of $38 million. At Genco, there was a cash outlay of $169 million for power plant scrubber projects. The scrubbers are necessary to comply with environmental regulations. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE and AIC as well as various plant upgrades.
Ameren’s 2008 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $149 million toward a scrubber at one of its power plants, and incurred storm-related expenditures of $12 million. CIPS and IPAIC incurred storm-related expenditures of $7 million and $8 million, respectively.$18 million. At Genco, and AERG, there werewas a cash outlaysoutlay of $205 million and $137 million, respectively, for power plant scrubber projects. The scrubbers are necessary to comply with environmental regulations. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE CIPS, CILCO, and IPAIC as well as various plant upgrades.
Ameren’s 2007 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $101 million toward a scrubber at one of its power plants, and incurred storm-related expenditures of $56 million. IP incurred storm-related expenditures of $24 million. At Genco and AERG, there were cash outlays of $102 million and $76 million, respectively, for power plant scrubber projects. In conjunction with the scrubber project, AERG also made expenditures for a power plant boiler upgrade of $45 million. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP as well as various plant upgrades.
The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 20102011 through 2014,2015, including construction expenditures, capitalized interest for the Merchant Generation business,
allowance for funds used during construction for our rate-regulated utility business, and estimated expenditures for compliance with known and existing environmental standards:regulations:
| 2010 | 2011 – 2014 | Total | |||||||||||||
UE | $ | 695 | $ | 2,565 - | $ | 3,465 | $ | 3,260 - | $ | 4,160 | |||||
CIPS | 95 | 340 - | 460 | 435 - | 555 | ||||||||||
Genco | 110 | 690 - | 930 | 800 - | 1,040 | ||||||||||
CILCO (Illinois Regulated) | 60 | 250 - | 340 | 310 - | 400 | ||||||||||
CILCO (AERG) | 5 | 130 - | 175 | 135 - | 180 | ||||||||||
IP | 175 | 670 - | 910 | 845 - | 1,085 | ||||||||||
EEI | 10 | 330 - | 450 | 340 - | 460 | ||||||||||
Other | 50 | 125 - | 170 | 175 - | 220 | ||||||||||
Ameren(a) | $ | 1,200 | $ | 5,100 - | $ | 6,900 | $ | 6,300 - | $ | 8,100 | |||||
| 2011 | 2012 - 2015 | Total | ||||||||||||||||||
UE | $ | 685 | $ | 2,500 - | $ | 3,400 | $ | 3,185 - | $ | 4,085 | ||||||||||
AIC | 310 | 1,550 - | 2,050 | 1,860 - | 2,360 | |||||||||||||||
Genco | 180 | 600 - | 850 | 780 - | 1,030 | |||||||||||||||
Other | 75 | 450 - | 600 | 525 - | 675 | |||||||||||||||
Ameren(a) | $ | 1,250 | $ | 5,100 - | $ | 6,900 | $ | 6,350 - | $ | 8,150 | ||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
UE’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with environmental regulations discussed below. CIPS’, CILCO’s (Illinois Regulated), and IP’sAIC’s estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments. Genco’s estimated capital expenditures are primarily for compliance with environmental regulations and upgrades to existing coal and gas-fired generating facilities. CILCO’s (AERG) estimate includes capital expenditures primarily for compliance with environmental regulations at its generating facilities.facilities discussed below.
We continually review our generation portfolio and expected power needs. As a result, we could modify our plan 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 or power 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.
Environmental Capital Expenditures
Ameren, UE Genco, AERG and EEIGenco will incur significant costs in future years to comply with existing and known federal EPA and state regulations regarding SO2, NOx, and mercury emissions from coal-fired power plants.
In May 2005,addition to existing laws and regulations governing our facilities, the EPA issuedis developing numerous new environmental regulations with respect tothat will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco, that operate coal-fired power plants. Significant new rules already proposed or promulgated within the past year include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, which include Missouri and Illinois, where our generating facilities are located, andthat increase the Districtstringency of Columbia to participate in cap-and-trade programs to reduce annual SO2emissions, annual NOx emissions, andthe existing ozone season NOx emissions. The cap-and-trade program for both annual and
ozone season NOx emissions went into effect on January 1, 2009. The SO2emissions cap-and-trade program is scheduled to take effect in 2010.
In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method it used to remove electric generating units from the list of sources subject to the MACT requirements under the Clean Air Act. In February 2009, the U.S. Supreme Court denied a petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions and other hazardous air pollutants, such as acid gases. In a consent order, the EPA agreed to propose the regulation by March 2011 and to finalize the regulation by November 2011. Compliance is expected to be required in 2015. We cannot predict at this time the estimated capital or operating costs for compliance with such future environmental rules.
In July 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Interstate Rule. The court ruled that the regulation contained several fatal flaws, including a regional cap-and-trade program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008,standard; the EPA, as well as several environmental groups, a group representing the electric utility industry, and the National Mining Association, all filed petitions for rehearing with the U.S. CourtCATR, which would require further reduction of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed its July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and remanded the rule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals’ July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA, at which point the Illinois and Missouri rules may be subject to change. The EPA has stated that it expects to issue a new proposed version of the Clean Air Interstate Rule in 2010 and a final version in 2011.
The state of Missouri has adopted rules to implement the federal Clean Air Interstate Rule for regulating SO2 and NOx emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our power plants; NSPS and
emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units. The rulesunits; and a MACT standard for the control of hazardous air pollutants such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are aunknown, the combined effect of the new and proposed environmental regulations may result in significant part of Missouri’s plancapital expenditures and/or increased operating costs over the next five to attain existing ambient standardseight years for ozoneAmeren, UE and fine particulates, as well as meeting the federal Clean Air Visibility Rule. The rulesGenco. Actions required to ensure that our facilities and operations are expected to reduce NOxemissions by 30%in compliance with environmental laws and SO2 emissions by 75% by 2015.regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of the Missouri rules, UE will use allowances and install pollution control equipment. UE’s costs to comply with SO2 emission reductions required by the Clean Air Interstate Ruleour generating facilities, which could increase materially if the EPA determines that existing allowances granted to sources under the Acid Rain Program cannot be used for compliance with the Clean Air Interstate Rule, or if a new allowance program is mandated by revisions to the Clean Air Interstate Rule. Missouri also adopted rules to implement the federal
Clean Air Mercury Rule. However, these rules are not enforceable since the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.
We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois in the near term. Under the MPS, as amended, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NOx and SO2 controls. This rule, when fully implemented, is expected to reduce mercury emissions by 90%, NOx emissions by 50%, and SO2 emissions by 70% by 2015 in Illinois. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. Genco, CILCO (AERG) and EEI will also need to install additional pollution control equipment. Current plans include installing scrubbers for SO2reduction as well as optimizing operations of selective catalytic reduction (SCR) systems for NOx reduction at certain coal-fired plants in Illinois. The Illinois Joint Committee on Administrative Rules approved a rule amendment in June 2009 that revised certain requirements of the MPS. As a result, Genco and CILCO (AERG) collectively were able to defer to subsequent years an estimated $300 million of environmental capital expenditures originally scheduled for 2009 through 2011.
In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. Illinois and Missouri have each submitted their recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas is expected in March 2010. State implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions for various requirement dates. Additional emission reductions may be required as a result of future state implementation plans. In January 2010, the EPA announced its plans to revise the ozone standard to a level lower than the level set in 2008. At this time, we are unable to determine the impact state implementation plans for such regulations would haveadverse effect on our results of operations, financial position, and liquidity.
The estimates in the table below presents estimatedcontain all of the known capital costs that are based on current technology to comply with state air quality implementation plans,existing environmental regulations and our preliminary assessment of the MPS, federalpotential impacts of the EPA’s proposed regulations for coal combustion byproducts, the CATR, and the revised ambient air quality standards including ozonefor SO2 and fine particulates, andNOx emissions as of December 31, 2010. The estimates in the federal Clean Air Visibility rule.table below assume that coal combustion byproducts will ultimately be regarded as nonhazardous. The estimates shown in the table below could change depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly ambient air quality standards or changes to existing standards for SO2 and NOx emissions, the requirements under a MACT standard for the control of hazardous air pollutants such as mercury and acid gases, the requirements under the finalized CATR, any new regulations under the Clean Water Act, a hazardous classification of coal combustion by products, new technology, and variations in costs of material or labor, or alternative compliance strategies, among other factors. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment. During 2009, Ameren identified significant opportunities to defer or reduce planned capital spending, which are reflected in the estimates provided in the table. The capital cost estimates are lower than previously anticipated, in part because of Ameren’s ability to manage its generating fleet to minimize emissions while
complying with emission limits and air permit requirements. Furthermore, previous estimates included assumptions about potential and developing air regulations, including rules that were subsequently vacated by the courts. These estimates include capital spending to comply primarily with existing and known regulations as of December 31, 2009.
| 2010 | 2011– 2014 | 2015 – 2017 | Total | 2011 | 2012 - 2015 | 2016 - 2020 | Total | ||||||||||||||||||||||||||||||||||||||||||
UE(a) | $ | 160 | $ | 170 – | $ | 215 | $ | 25 – | $ | 35 | $ | 355 – | $ | 410 | $ | 35 | $ | 850 - | $ | 1,050 | $ | 1,380 - | $ | 1,610 | $ | 2,265 - | $ | 2,695 | |||||||||||||||||||||
Genco | 95 | 650 – | 785 | 30 – | 35 | 775 – | 915 | 125 | 470 - | 580 | 50 - | 60 | 645 - | 765 | |||||||||||||||||||||||||||||||||||
AERG | 5 | 120 – | 150 | 65 – | 75 | 190 – | 230 | 10 | 125 - | 160 | 5 - | 10 | 140 - | 180 | |||||||||||||||||||||||||||||||||||
EEI | 5 | 275 – | 335 | 0 – | 5 | 280 – | 345 | ||||||||||||||||||||||||||||||||||||||||||
Ameren | $ | 265 | $ | 1,215 – | $ | 1,485 | $ | 120 – | $ | 150 | $ | 1,600 – | $ | 1,900 | $ | 170 | $ | 1,445 - | $ | 1,790 | $ | 1,435 - | $ | 1,680 | $ | 3,050 - | $ | 3,640 | |||||||||||||||||||||
| (a) | UE’s expenditures are expected to be recoverable |
In 2009, UE developed four-year and 20-year Environmental Compliance Plans to comply with all environmental regulations, including rules under the Clean Water Act, to support its environmental cost recovery mechanism tariff request, which was a part of its July 2009 electric rate case filing. The plans contain a comprehensive assessment of environmental investments likely to be required of UE. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on UE’s pending electric rate case.
See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for a further discussion of environmental matters, including global climate change.
Cash Flows from Financing Activities
20092010 versus 20082009
As a result of turmoil in the capital and credit markets in 2008 and 2009,During 2010, we sought to improve our liquidity position. We replaced and extended the expiration of our credit facilities, and we sought to reduce our reliance on borrowings from these credit facilities, increaseand reduce long-term debt outstanding while maintaining adequate cash balances for working capital needs.
Ameren had an $807 million net use of cash from financing activities in 2010, compared with a $342 million net source of cash in 2009. During 2010, Ameren’s cash flow from operating activities of $1.8 billion exceeded its capital expenditures of $1.0 billion and increase the equity contentcommon stock dividend requirements of our capitalization. We also sought$368 million. Ameren utilized this cash to eliminateredeem $310 million of long-term debt at CILCORP as a stepand $52 million of preferred stock in simplifying our organizational structure.
2010. During 2009, Ameren and its subsidiaries issued $1 billion of senior debt and $634 million in common stock and used the proceeds to repurchase, redeem, and fund maturities of $631 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, CIPS, AIC, and Genco.
UE had a $337 million net use of cash from financing activities in 2010, compared with a $250 million net source of cash in 2009. Planned reductions of expenditures, allowed UE to use cash from operations and credit facility borrowings to fund its capital expenditures and working capital needs without issuing additional senior debt or capital contributions from Ameren. Additionally, during 2010, these efforts allowed UE to redeem $70 million of long-term debt, including its 7.69% Series A subordinated debentures; to redeem all outstanding shares of its $7.64 Series preferred stock; to increase common stock dividends by $60 million; and to reduce short-term and intercompany borrowing repayments by $343 million, compared with 2009.
AIC’s net cash used in financing activities increased by $173 million in 2010 compared with 2009. Reduction of planned expenditures allowed it to use cash from operations to fund its capital expenditures and working capital needs without the issuance of additional senior debt or capital contributions from Ameren. Additionally, AIC’s common stock dividends increased $35 million compared with 2009, and CILCO redeemed all of its preferred stock in connection with the AIC Merger. During 2009, Ameren made capital contributions to AIC of $272 million and AIC repaid $250 million of long-term debt and $62 million of short-term borrowing balances.
Genco CILCOhad a $251 million net use of cash from financing activities in 2010, compared with a $139 million net source of cash in 2009, primarily as a result of reductions of planned expenditures. These efforts allowed Genco to use cash from operations and IP. Comparatively, duringcredit facility borrowings to fund capital expenditures, to meet working capital needs, to repay its $200 million of 8.35% senior notes at maturity, and to repay a net $176 million of intercompany note borrowings in 2010. Additionally, Genco received a capital contribution from Ameren associated with a tax allocation agreement that benefited 2010 cash flows from financing activities. During 2009, Genco issued $249 million of long-term debt and used the proceeds to repay short-term borrowings and to fund general corporate purposes.
2009 versus 2008
During 2009, Ameren and its subsidiaries issued $1 billion of senior debt and $634 million in common stock.
It used the proceeds to repurchase, redeem, and fund maturities of $631 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, AIC and Genco. During 2008, Ameren’s subsidiaries issued $1.9 billion of senior debt and $154 million in common stock and used the proceeds to repurchase, redeem, and fund maturities of $842 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCOAIC and IP.Genco. Ameren’s capital issuance costs increased in 2009 compared with 2008 because of $40 million in banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit
Agreement, and $17 million of issuance costs associated with Ameren’s September 2009 common stock issuance, partially offset by a decrease in issuance costs associated with long-term debt. Benefiting 2009 cash from financing activities, compared with 2008, was a $196 million decrease in common stock dividends and a $47 million increase in generator advances received for construction under generator interconnection agreements, net of repayments.
UE’s net cash provided by financing activities decreased by $55 million during 2009, compared with 2008, primarily because of $251 million of short-term borrowings repayments in 2009 compared with net short-term borrowings of $169 million in 2008, a $350 million decrease in the issuances of long-term debt, and a $184 million increase in net repayments under an intercompany borrowing arrangement with Ameren. Benefits to cash for 2009, compared with 2008, included a $436 million capital contribution from Ameren funded by the proceeds of Ameren’s September 2009 common stock issuance, a $378 million decrease in redemptions of long-term debt, and an $89 million decrease in common stock dividend payments. The proceeds from the capital contribution were primarily used to reduce outstanding short-term borrowings.
CIPS’AIC had a $151 million net use of cash used infrom financing activities increased duringin 2009, compared with 2008. CIPS used existinga $103 million net source of cash to fund a net reduction in money pool borrowings, to pay $47 million of dividends to Ameren in 2009, and to fund a $3 million increase in debt issuance costs as a result of the banking fees associated with the 2009 Illinois Credit Agreement. Benefiting the 2009 period was a $66 million capital contribution from Ameren.
Genco’s cash provided by financing activities increased during 2009 compared with 2008, primarily as a result of efforts to improve its liquidity position in response to the turmoil experienced in the capital and credit markets during 2009 and 2008. These efforts included no long-term debt issuances in 2009, which meant an $880 million decrease in long-term debt issuances from 2008. AIC also received a $101$272 million reduction in dividends paid on common stock and $100 millioncapital contribution from Ameren that was made to maintain a capital structure of approximately 50% to 55% equity. Additionally, improved financial results allowed AIC to increase dividend payments from 2008 by $38 million. The change in short-term borrowings repayments.borrowing arrangements at AERG also affected the 2009 financing activity of discontinued operations as compared with 2008.
Genco had a $139 million net source of cash from financing activities in 2009, compared with a $54 million net use of cash in 2008, primarily as a result of efforts to improve its liquidity position in response to the turmoil experienced in the capital and credit markets during 2009
and 2008, as well as its efforts to reduce, defer and cancel expenditures. As a result of these efforts, Genco decreased common stock dividends by $178 million and short-term borrowing repayments by $100 million. These benefits to
cash during the 2009 period were slightly offset by a $106 million decrease in net money pool borrowings and a $51 million decrease in the issuance of long-term debt.
CILCO had a net use of cash from financing activities in 2009, compared with a net source of cash in 2008 primarily as a result of the change in CILCO’s money pool borrowings, $127 million increase in repayments of short-term borrowings, a $150 decrease in issuance of long-term debt, and a $6 million increase in capital issuance costs as a result of banking fees associated with the 2009 Illinois Credit Agreement. During 2009, CILCO repaid a net $98 million to the money pool; CILCO received $98 million of net borrowings in 2008. Cash from financing activities benefited from a $288 million increase in intercompany borrowings from Ameren, a $51 million capital contribution from CILCORP, and a $35 million decrease in redemptions of long-term debt and preferred stock.
IP had a net use of cash from financing activities during 2009, compared with a net source of cash in 2008, primarily as a result of a $730 million decrease in long-term debt issuances. During 2009, cash from financing activities
benefited from $175 million decrease in net short-term borrowings repayments, a $141 million decrease in redemptions and maturities of long-term debt, including IP SPT, $155 million capital contribution received from Ameren, and a $40 million increase in net generator advances received for construction under generator interconnection agreements. During 2009, IP used existing cash to fund the maturity of $250 million of its 7.50% mortgage bonds and to pay banking fees associated with the 2009 Illinois Credit Agreement. Comparatively, during 2008, IP issued $730 million of senior secured notes to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds, which had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market, and to fund debt maturities and common stock dividends.
2008 versus 2007
During the year ended December 31, 2008, the Ameren Companies issued $1.9 billion of senior debt. The proceeds were used to repurchase, redeem, and fund maturities of $842 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO and IP. During the year ended December 31, 2007, net short-term borrowings of $860 million and senior debt of $674 million were used to fund $488 million of maturities of long-term debt, to fund working capital needs at Ameren subsidiaries and to build liquidity during a period of legislative uncertainty in Illinois. Additionally, CILCO redeemed the remaining shares of its 5.85% Class A preferred stock to complete the mandatory sinking fund redemption requirement, which resulted in a $16 million use of cash during 2008 compared with 2007. Benefiting 2008, compared with 2007, was a $63 million increase in proceeds from the issuance of Ameren common stock, which resulted from increased sales through Ameren’s 401(k) plan and DRPlus.
UE’s net cash from financing activities increased in the year ended December 31, 2008, compared with the year ended December 31, 2007. During 2008, UE used $699 million in proceeds from the issuance of senior secured notes to redeem outstanding auction-rate environmental improvement revenue refunding bonds that had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market, and to fund the maturity of $148 million of UE’s 6.75% first mortgage bonds. Additionally, net short-term borrowings increased $321 million. These borrowings were primarily used to fund working capital needs and capital expenditures. In 2007, UE issued $424 million in senior secured notes and received a $380 million capital contribution from Ameren to fund working capital requirements and to reduce net short-term borrowings.
CIPS had a net use of cash from financing activities in 2008, compared with a net source of cash in 2007. This change occurred because CIPS used net money pool borrowings and existing cash to fund a net reduction in short-term borrowings, to redeem $35 million of auction-rate environmental improvement revenue refunding bonds that
had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market, and to fund the maturity of $15 million of its 5.375% senior secured notes during 2008. In 2007, CIPS used net short-term borrowings of $90 million to fund working capital needs to build liquidity, and to fund $40 million of common stock dividends.
Genco issued $300 million of 7.00% senior unsecured notes during 2008, which resulted in a net source of cash from financing activities compared with a net use of cash in 2007. The proceeds from the issuance were used to fund capital expenditures and other working capital requirements, including a net reduction of $200 million of short-term borrowings during 2008 compared with 2007.
CILCO’s cash provided by financing activities decreased in 2008 compared with 2007. This decrease was primarily the result of CILCO’s net repayments of short-term borrowings during 2008 compared with 2007. These repayments were funded by a net increase in money pool borrowings of $98 million, primarily at AERG, and CILCO’s issuance of $150 million of its 8.875% senior secured notes. Partially offsetting the decrease were reduced redemptions and maturities of long-term debt in 2008. During 2008, $19 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market were redeemed at CILCO. In 2007, $50 million of CILCO’s 7.50% bonds matured.
IP’s cash from financing activities decreased in 2008, compared with 2007. During 2008, IP issued $730 million of senior secured notes and used the proceeds to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market and to repay short-term borrowings. Additionally, during 2008, IP funded $60 million of common stock dividends to Ameren and had net short-term borrowings repayments of $175 million. Comparatively, during 2007, IP issued $250 million of senior secured notes, paid $61 million of common stock dividends, and had $100 million of net borrowings under the 2007 credit facility. These borrowings were used to fund $87 million of long-term debt maturities and $43 million of net money pool repayments to build liquidity in 2007.
Credit Facility Borrowings and Liquidity
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, or drawings under committed bank credit facilities.facilities, or commercial paper issuances. See Note 4 – Credit Facility Borrowings and Liquidity under Part II, Item 8, of this report 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.
The following table presents the committed bank credit facilities of Ameren and the Ameren Companies, and their availability, as of December 31, 2009:2010:
| Credit Facility | Expiration | Amount Committed | Amount Available | ||||||
Ameren, UE and Genco: | |||||||||
2009 Multiyear revolving(a)(b) | July 2011 | $ | 1,300 | $ | 555 | (c) | |||
Ameren, CIPS, CILCO, and IP: | |||||||||
2009 Illinois revolving | June 2011 | 800 | 700 | ||||||
| Credit Facility | Expiration | Amount Committed | Amount Available | |||||||||
Ameren and UE: | ||||||||||||
2010 Missouri Credit Agreement(a)(b) | September 2011 | $ | 800 | $ | 445 | (c) | ||||||
Ameren and Genco: | ||||||||||||
2010 Genco Credit Agreement(a) | September 2013 | 500 | 400 | |||||||||
Ameren and AIC: | ||||||||||||
2010 Illinois Credit Agreement(a) | September 2013 | 800 | 800 | |||||||||
Ameren: | ||||||||||||
$20 million revolving credit facility | June 2012 | 20 | - | |||||||||
| (a) | The Ameren Companies may access these credit facilities through intercompany borrowing arrangements. |
| (b) |
| (c) | In addition to amounts drawn on these facilities, the amount available is further reduced by standby letters of credit issued under the facilities. The amount of such letters of credit at December 31, |
The 2010 Credit Agreements are used to support Ameren and UE’s commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper programs, subject to its borrowing sublimits. At December 31, 2010, Ameren had $269 million of commercial paper outstanding, which reduced the available amounts under these facilities. Based on outstanding borrowings under the 2010 Credit Agreements (and considering reductions for $15 million of letters of credit issued and $269 million of commercial paper borrowings), the aggregate available amount under the 2010 Credit Agreements at December 31, 2010, was $1.38 billion.
The combined maximum amount available to all of the borrowers, collectively, under the 2009 Multiyear2010 Credit Agreement and the Supplemental Credit Agreement (collectively, the “2009 Multiyear Credit Agreements”)Agreements is $1.3$2.1 billion. The combined maximum aggregate amount available to each borrower individually, under each facility is shown in the 2009 Multiyear Credit Agreements is limited as follows: Ameren – $1.15 billion, UE – $500 million and Genco – $150 millionfollowing table (such amountsamount being eachsuch borrower’s “Borrowing Sublimit”). CIPS, CILCO, and IP have no borrowing authority or liability under the 2009 Multiyear Credit Agreements. :
| 2010 Missouri Credit Agreement | 2010 Genco Credit Agreement | 2010 Illinois | ||||||||||
Ameren | $ | 500 | $ | 500 | $ | 300 | ||||||
UE | 500 | (a | ) | (a | ) | |||||||
AIC | (a | ) | (a | ) | 800 | |||||||
Genco | (a | ) | 500 | (a | ) | |||||||
| (a) | Not applicable. |
These credit facilities were also available for use, subject to applicable regulatory short-term borrowing authorizations, by EEI or by other Ameren non-state-regulated subsidiaries through direct short-term borrowings from Ameren and by most of
Ameren’s merchant generatingnon-rate-regulated subsidiaries, including, but not limited to, Ameren Services, Resources Company, AERG and Marketing Company, and AFS, through a non-state- regulatednon-state-regulated subsidiary money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. In addition, a unilateral borrowing agreement among Ameren, IP,AIC, and Ameren Services enables IPAIC to make short-term borrowings directly from Ameren. ThePursuant to the terms of the agreement, the aggregate amount of borrowings outstanding at any time by IPAIC under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding external credit facility borrowings by IP,AIC, may not exceed $500 million,
pursuant to authorization from the ICC. IPAIC is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 – Credit Facility Borrowings and Liquidity under Part II, Item 8, of this report for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement.
The combined maximum amount available to all borrowers collectively under the 2009 Illinois Credit Agreement is $800 million, and the combined maximum amount available to each borrower individually, under the 2009 Illinois Credit Agreement is limited as follows: Ameren – $300 million, CIPS – $135 million, CILCO – $150 million, and IP – $350 million.
On January 21, 2009,June 2, 2010, Ameren entered into a $20 million term loan agreement due January revolving credit facility ($20 2010, which wasMillion Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn on January 21, 2009. This term loan agreement was repaidsince June 15, 2010. Borrowings under the $20 Million Facility bear interest at maturity in January 2010.a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility. See Note 4 – Credit Facility Borrowings and Liquidity under Part II, Item 8, of this report for additional information.
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. At December 31, 2009, Ameren, UE, CIPS, Genco, CILCO, and IP had $622 million, $267 million, $28 million, $6 million, $88 million, and $190 million, respectively, of cash and cash equivalents.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2008,2010, FERC issued an order authorizing these utility subsidiariesthe issuance of up to issue such securities subject to the following limits on outstanding balances: UE – $1 billion CIPS – $250 million, and CILCO – $250 million.of short-term debt securities for UE. The authorization was effective as of April 1, 2008,2010, and terminates on March 31, 2010. UE, CIPS and CILCO have pending requests with FERC seeking authority to issue short-term debt securities subject to limits on outstanding balances of $1 billion, $300 million, and $250 million, respectively, for the period April 1, 2010, through
March 31, 2012. IPOn October 1, 2010, FERC authorized AIC to issue up to $1 billion of short-term debt securities. The authorization became effective immediately and terminates on September 30, 2012.
On July 16, 2010, FERC granted Genco’s request for unlimited long and short-term debt issuance authorization. EEI has unlimited short-term borrowing authorization from FERC.
Genco was authorized by FERC in its March 2008 order to have up to $500 million of short-term debt outstanding at any time. Genco is seeking a renewal of that authorization. AERG and EEI have unlimited short-term borrowing authorization from FERC.
The issuance of short-term debt securities by Ameren is not subject to approval by any regulatory body.
The Ameren Companies continually evaluate the adequacy and appropriateness of their creditliquidity arrangements given changing business and credit market conditions. When business and credit market conditions warrant, changes may be made to existing credit agreementsfacilities or to 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 and preferred stock (net of any issuance discounts and including any redemption premiums) for the years 2010, 2009, 2008, and 20072008 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 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.
| Month Issued, Redeemed, Repurchased or Matured | 2009 | 2008 | 2007 | Month Issued, Redeemed, Repurchased or Matured | 2010 | 2009 | 2008 | ||||||||||||||||||||
Issuances | |||||||||||||||||||||||||||
Long-term debt | |||||||||||||||||||||||||||
Ameren: | |||||||||||||||||||||||||||
8.875% Senior unsecured notes due 2014 | May | $ | 423 | $ | - | $ | - | May | $ | - | $ | 423 | $ | - | |||||||||||||
UE: | |||||||||||||||||||||||||||
6.40% Senior secured notes due 2017 | June | - | - | 424 | |||||||||||||||||||||||
6.00% Senior secured notes due 2018 | April | - | 250 | - | April | - | - | 250 | |||||||||||||||||||
6.70% Senior secured notes due 2019 | June | - | 449 | - | June | - | - | 449 | |||||||||||||||||||
8.45% Senior secured notes due 2039 | March | 349 | - | - | March | - | 349 | - | |||||||||||||||||||
Genco: | |||||||||||||||||||||||||||
6.30% Senior unsecured notes due 2020 | November | 249 | - | - | November | - | 249 | - | |||||||||||||||||||
7.00% Senior unsecured notes due 2018 | April | - | 300 | - | April | - | - | 300 | |||||||||||||||||||
CILCO: | |||||||||||||||||||||||||||
AIC: | |||||||||||||||||||||||||||
6.25% Senior secured notes due 2018 | April | - | - | 336 | |||||||||||||||||||||||
8.875% Senior secured notes due 2013 | December | - | 150 | - | December | - | - | 150 | |||||||||||||||||||
IP: | |||||||||||||||||||||||||||
6.125% Senior secured notes due 2017 | November | - | - | 250 | |||||||||||||||||||||||
6.25% Senior secured notes due 2018 | April | - | 336 | - | |||||||||||||||||||||||
9.75% Senior secured notes due 2018 | October | - | 394 | - | October | - | - | 394 | |||||||||||||||||||
Total Ameren long-term debt issuances | $ | 1,021 | $ | 1,879 | $ | 674 | $ | - | $ | 1,021 | $ | 1,879 | |||||||||||||||
Common stock | |||||||||||||||||||||||||||
Ameren: | |||||||||||||||||||||||||||
21,850,000 shares at $25.25 | September | $ | 552 | $ | - | $ | - | September | $ | - | $ | 552 | $ | - | |||||||||||||
DRPlus and 401(k) | Various | 82 | 154 | 91 | Various | 80 | 82 | 154 | |||||||||||||||||||
Total common stock issuances | $ | 80 | $ | 634 | $ | 154 | |||||||||||||||||||||
Total Ameren long-term debt and common stock issuances | $ | 80 | $ | 1,655 | $ | 2,033 | |||||||||||||||||||||
Redemptions, Repurchases and Maturities | |||||||||||||||||||||||||||
Long-term debt | |||||||||||||||||||||||||||
Ameren: | |||||||||||||||||||||||||||
8.70% Senior unsecured notes due 2009 (formerly CILCORP) | October | $ | - | $ | 124 | $ | - | ||||||||||||||||||||
9.375% Senior bonds due 2029 (formerly CILCORP) | December | - | 253 | - | |||||||||||||||||||||||
| Month Issued, Redeemed, Repurchased or Matured | 2009 | 2008 | 2007 | Month Issued, Redeemed, Repurchased or Matured | 2010 | 2009 | 2008 | ||||||||||||||||||||
Total common stock issuances | $ | 634 | $ | 154 | $ | 91 | |||||||||||||||||||||
Total Ameren long-term debt and common stock issuances | $ | 1,655 | $ | 2,033 | $ | 765 | |||||||||||||||||||||
Redemptions, Repurchases and Maturities | |||||||||||||||||||||||||||
Long-term debt | |||||||||||||||||||||||||||
Ameren: | |||||||||||||||||||||||||||
2002 5.70% notes due 2007 | February | $ | - | $ | - | $ | 100 | ||||||||||||||||||||
Senior notes due 2007 | May | - | - | 250 | |||||||||||||||||||||||
UE: | |||||||||||||||||||||||||||
City of Bowling Green capital lease (Peno Creek CT) | Various | 4 | 4 | 4 | Various | $ | 4 | $ | 4 | $ | 4 | ||||||||||||||||
2000 Series B environmental improvement bonds due 2035 | April | - | 63 | - | April | - | - | 63 | |||||||||||||||||||
2000 Series A environmental improvement bonds due 2035 | May | - | 64 | - | May | - | - | 64 | |||||||||||||||||||
2000 Series C environmental improvement bonds due 2035 | May | - | 60 | - | May | - | - | 60 | |||||||||||||||||||
1991 Series environmental improvement bonds due 2020 | May | - | 43 | - | May | - | - | 43 | |||||||||||||||||||
6.75% Series first mortgage bonds due 2008 | May | - | 148 | - | May | - | - | 148 | |||||||||||||||||||
CIPS: | |||||||||||||||||||||||||||
7.69% Series A subordinated deferrable interest debentures due 2036 | September | 66 | - | - | |||||||||||||||||||||||
AIC: | |||||||||||||||||||||||||||
2004 Series pollution control bonds due 2025 | April | - | 35 | - | April | $ | - | $ | - | $ | 35 | ||||||||||||||||
5.375% Senior secured notes due 2008 | December | - | 15 | - | |||||||||||||||||||||||
CILCORP: | |||||||||||||||||||||||||||
8.70% Senior unsecured notes due 2009 | October | 124 | - | - | |||||||||||||||||||||||
9.375% Senior bonds due 2029 | December | 253 | - | - | |||||||||||||||||||||||
CILCO: | |||||||||||||||||||||||||||
7.50% First mortgage bonds due 2007 | January | - | - | 50 | |||||||||||||||||||||||
2004 Series pollution control bonds due 2039 | April | - | 19 | - | April | - | - | 19 | |||||||||||||||||||
IP: | |||||||||||||||||||||||||||
Series 2001 Non-AMT bonds due 2028 | May | - | 112 | - | May | - | - | 112 | |||||||||||||||||||
Series 2001 AMT bonds due 2017 | May | - | 75 | - | May | - | - | 75 | |||||||||||||||||||
1997 Series A pollution control bonds due 2032 | May | - | 70 | - | May | - | - | 70 | |||||||||||||||||||
1997 Series B pollution control bonds due 2032 | May | - | 45 | - | May | - | - | 45 | |||||||||||||||||||
1997 Series C pollution control bonds due 2032 | June | - | 35 | - | June | - | - | 35 | |||||||||||||||||||
Note payable to IP SPT: | |||||||||||||||||||||||||||
5.65% Series due 2008 | Various | - | 54 | 84 | |||||||||||||||||||||||
7.50% Series mortgage bond due 2009 | June | 250 | - | - | |||||||||||||||||||||||
5.375% Senior secured notes due 2008 | December | - | - | 15 | |||||||||||||||||||||||
7.50% Series mortgage bonds due 2009 | June | - | 250 | - | |||||||||||||||||||||||
7.61% Series 1997-2 first mortgage bonds due 2017 | September | 40 | - | - | |||||||||||||||||||||||
Note payable to IP Special Purpose Trust 5.65% Series due 2008 | Various | - | - | 54 | |||||||||||||||||||||||
Genco: | |||||||||||||||||||||||||||
Senior notes Series D 8.35% due 2010 | November | 200 | - | - | |||||||||||||||||||||||
Total Ameren long-term debt redemptions, repurchases and maturities | $ | 310 | $ | 631 | $ | 842 | |||||||||||||||||||||
Preferred Stock | |||||||||||||||||||||||||||
CILCO: | |||||||||||||||||||||||||||
UE: | |||||||||||||||||||||||||||
$7.64 Series | August | $ | 33 | $ | $ | - | |||||||||||||||||||||
AIC: | |||||||||||||||||||||||||||
5.85% Series | July | - | 16 | 1 | July | - | - | 16 | |||||||||||||||||||
4.50% Series | August | 11 | - | - | |||||||||||||||||||||||
4.64% Series | August | 8 | - | - | |||||||||||||||||||||||
4.08% Series(a) | September | 7 | - | - | |||||||||||||||||||||||
4.20% Series(a) | September | 5 | - | - | |||||||||||||||||||||||
4.26% Series(a) | September | 4 | - | - | |||||||||||||||||||||||
4.42% Series(a) | September | 3 | - | - | |||||||||||||||||||||||
4.70% Series(a) | September | 5 | - | - | |||||||||||||||||||||||
7.75% Series(a) | September | 9 | - | - | |||||||||||||||||||||||
Total Ameren preferred stock redemptions and repurchases | $ | 85 | $ | - | $ | 16 | |||||||||||||||||||||
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities | $ | 631 | $ | 858 | $ | 489 | $ | 395 | $ | 631 | $ | 858 | |||||||||||||||
| (a) | In September 2010, Ameren contributed to the capital of AIC (formally IP), without the payment of any consideration, all of the IP preferred stock owned by Ameren ($33 million). IP cancelled these preferred shares. |
In November 2008, Ameren, as a well-known seasoned issuer, along with AIC’s predecessor companies, CIPS, Genco, CILCO and IP, and Genco, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011. As amended in December 2010, Ameren, AIC and Genco may offer securities pursuant to the November 2008 Form S-3 shelf registration statement. In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.
The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of December 31, 2009:
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In July 2008, Ameren filed aA Form S-3 registration statement was filed by Ameren with the SEC in July 2008, and supplemented in December
2010, authorizing the offering of six 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 selling newly issued shares of common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan, Ameren issued 3.0 million, 3.2 million, 4.0 million, and 1.74.0 million shares of common stock in 2010, 2009, 2008, and 2007,2008, respectively, which were valued at $80 million, $82 million, $154 million, and $91$154 million for the respective years.
In September 2009, Ameren issued and sold 21.85 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the offering proceeds to make
investments in its rate-regulated utility subsidiaries in the form of capital contributions as follows:to UE –and AIC of $436 million CIPS – $13and $99 million, CILCO – $25 million, and IP – $61 million.respectively.
The Ameren UE, CIPS, Genco, CILCO and IPCompanies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale.sales. 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 4 – Credit Facility Borrowings and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our bank credit and term loan facilitiesagreements and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At December 31, 2009,2010, the Ameren Companies were in compliance with their credit facility, indenture,agreements, indentures, 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 favorablereasonable 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 access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $368 million, or $1.54 per share, in 2010, $338 million, or $1.54 per share, in 2009,
$534 and $534 million, or $2.54 per share, in 2008,2008. The payout of common stock dividends exceeded net income in 2010 because of noncash goodwill and $527 million, or $2.54 per share, in 2007. This resulted in aother impairment charges recorded during 2010. The payout rate based on net income of 55% in 2009 88% inand 2008 was 55% and 85% in 2007.88%, respectively. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 20% in 2010, 17% in 2009 and 35% in 2008 and 48% in 2007.2008.
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, as it has done in the past, the board of directors is expected to consider various issues, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. On February 12, 2010,9, 2011, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 38.5 cents per share, payable on March 31, 2010,2011, to shareholders of record on March 10, 2010.9, 2011.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances. At December 31, 2009,2010, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.
UE would beUnder UE’s mortgage indenture, $31 million of total retained earnings as of December 31, 2010, was restricted as to dividend payments on itsagainst payment of common dividends, except those dividends payable in common stock, which left $2 billion of free and preferred stock if it were to extend or defer interest payments on its subordinated debentures. CIPS’unrestricted retained earnings at December 31, 2010. AIC’s articles of incorporation and mortgage indentures require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit it from making any dividend payments on common stock if debt service coverage ratios are below a defined threshold. CILCO has restrictions in its articles of incorporation on dividend payments on common stock relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock.
UE, CIPS,AIC and Genco CILCO and IP as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations; however,regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, CIPS, CILCO and IPAIC may not pay any dividend on their respectiveits stock, unless, among other things, their respectiveits earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless CIPS, CILCO or IPAIC has specific authorization from the ICC.
In its application for the FERC orders approving the AIC Merger and the AERG distribution, Ameren committed to maintain a minimum of 30% equity in its capital structure at AIC following the AIC Merger and the AERG distribution.
The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents.parents:
| 2009 | 2008 | 2007 | |||||||
UE | $ | 175 | $ | 264 | $ | 267 | |||
CIPS | 47 | - | 40 | ||||||
Genco | - | 101 | 113 | ||||||
CILCO | 20 | - | - | ||||||
IP | 31 | 60 | 61 | ||||||
Nonregistrants | 65 | 109 | 46 | ||||||
Dividends paid by Ameren | $ | 338 | $ | 534 | $ | 527 | |||
| 2010 | 2009 | 2008 | ||||||||||
UE | $ | 235 | $ | 175 | $ | 264 | ||||||
AIC | 133 | 98 | 60 | |||||||||
Genco | - | 43 | 221 | |||||||||
Nonregistrants including eliminations | - | 22 | (11 | ) | ||||||||
Dividends paid by Ameren | $ | 368 | $ | 338 | $ | 534 | ||||||
Certain of the Ameren Companies have issued preferred stock, on which they are obligated to makeprovides for cumulative preferred dividend payments.stock dividends. Each company’s board of directors considers the declaration of the preferred stock dividends to shareholders of record on a certain date, stating the date on
which the dividend is payable and the amount to be paid. See Note 105 – Preferred StockLong-Term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2009.2010. See Note 11 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.
| Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | After 5 Years | |||||||||||||
Ameren:(a) | |||||||||||||||||
Long-term debt and capital lease obligations(b)(c) | $ | 7,333 | $ | 204 | $ | 333 | $ | 940 | $ | 5,856 | |||||||
Short-term debt and credit facility borrowings | 850 | 20 | 830 | - | - | ||||||||||||
Interest payments(d) | 5,276 | 467 | 887 | 812 | 3,110 | ||||||||||||
Operating leases(e) | 351 | 37 | 59 | 52 | 203 | ||||||||||||
2007 Illinois Electric Settlement Agreement | 3 | 3 | - | - | - | ||||||||||||
Other obligations(f) | 7,048 | 1,714 | 2,558 | 996 | 1,780 | ||||||||||||
Total cash contractual obligations | $ | 20,861 | $ | 2,445 | $ | 4,667 | $ | 2,800 | $ | 10,949 | |||||||
UE: | |||||||||||||||||
Long-term debt and capital lease obligations(c) | $ | 4,030 | $ | 4 | $ | 183 | $ | 314 | $ | 3,529 | |||||||
Interest payments(d) | 3,220 | 239 | 474 | 443 | 2,064 | ||||||||||||
Operating leases(e) | 157 | 14 | 25 | 25 | 93 | ||||||||||||
Other obligations(f) | 3,812 | 729 | 1,029 | 614 | 1,440 | ||||||||||||
Total cash contractual obligations | $ | 11,219 | $ | 986 | $ | 1,711 | $ | 1,396 | $ | 7,126 | |||||||
CIPS: | |||||||||||||||||
Long-term debt(c) | $ | 422 | $ | - | $ | 150 | $ | 51 | $ | 221 | |||||||
Interest payments(d) | 286 | 27 | 39 | 32 | 188 | ||||||||||||
Operating leases(e) | 2 | - | 1 | 1 | - | ||||||||||||
2007 Illinois Electric Settlement Agreement | (g | ) | (g | ) | - | - | - | ||||||||||
Other obligations(f) | 346 | 93 | 142 | 89 | 22 | ||||||||||||
Total cash contractual obligations | $ | 1,056 | $ | 120 | $ | 332 | $ | 173 | $ | 431 | |||||||
Genco: | |||||||||||||||||
Long-term debt(c) | $ | 1,025 | $ | 200 | $ | - | $ | - | $ | 825 | |||||||
Intercompany note payable – CIPS | 45 | 45 | - | - | - | ||||||||||||
Interest payments | 679 | 57 | 86 | 86 | 450 | ||||||||||||
Operating leases(e) | 133 | 9 | 17 | 17 | 90 | ||||||||||||
2007 Illinois Electric Settlement Agreement | 1 | 1 | - | - | - | ||||||||||||
Other obligations(f) | 648 | 233 | 374 | 38 | 3 | ||||||||||||
Total cash contractual obligations | $ | 2,531 | $ | 545 | $ | 477 | $ | 141 | $ | 1,368 | |||||||
| Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | After 5 Years | Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | After 5 Years | ||||||||||||||||||||||||||
CILCO: | |||||||||||||||||||||||||||||||||||
Long-term debt | $ | 279 | $ | - | $ | 1 | $ | 150 | $ | 128 | |||||||||||||||||||||||||
Intercompany note payable – Ameren | 288 | 288 | - | - | - | ||||||||||||||||||||||||||||||
Ameren:(a) | |||||||||||||||||||||||||||||||||||
Long-term debt and capital lease obligations(b)(c) | $ | 7,021 | $ | 155 | $ | 534 | $ | 705 | $ | 5,627 | |||||||||||||||||||||||||
Short-term debt and credit facility borrowings | 729 | 269 | 460 | - | - | ||||||||||||||||||||||||||||||
Interest payments(d) | 4,793 | 455 | 885 | 755 | 2,698 | ||||||||||||||||||||||||||||||
Operating leases(e) | 336 | 39 | 66 | 50 | 181 | ||||||||||||||||||||||||||||||
Other obligations(f) | 7,486 | 1,977 | 2,297 | 1,025 | 2,187 | ||||||||||||||||||||||||||||||
Total cash contractual obligations | $ | 20,365 | $ | 2,895 | $ | 4,242 | $ | 2,535 | $ | 10,693 | |||||||||||||||||||||||||
UE: | |||||||||||||||||||||||||||||||||||
Long-term debt and capital lease obligations(c) | $ | 3,960 | $ | 5 | $ | 383 | $ | 229 | $ | 3,343 | |||||||||||||||||||||||||
Interest payments(d) | 2,837 | 233 | 451 | 414 | 1,739 | ||||||||||||||||||||||||||||||
Operating leases(e) | 146 | 13 | 25 | 24 | 84 | ||||||||||||||||||||||||||||||
Other obligations(f) | 3,700 | 751 | 933 | 645 | 1,371 | ||||||||||||||||||||||||||||||
Total cash contractual obligations | $ | 10,643 | $ | 1,002 | $ | 1,792 | $ | 1,312 | $ | 6,537 | |||||||||||||||||||||||||
AIC: | |||||||||||||||||||||||||||||||||||
Long-term debt(c) | $ | 1,811 | $ | 150 | $ | 151 | $ | 51 | $ | 1,459 | |||||||||||||||||||||||||
Interest payments(d) | 1,059 | 125 | 240 | 209 | 485 | ||||||||||||||||||||||||||||||
Operating leases(e) | 7 | 2 | 2 | 2 | 1 | ||||||||||||||||||||||||||||||
Other obligations(f) | 2,504 | 646 | 760 | 344 | 754 | ||||||||||||||||||||||||||||||
Total cash contractual obligations | $ | 5,381 | $ | 923 | $ | 1,153 | $ | 606 | $ | 2,699 | |||||||||||||||||||||||||
Genco: | |||||||||||||||||||||||||||||||||||
Long-term debt(c) | $ | 825 | $ | - | $ | - | $ | - | $ | 825 | |||||||||||||||||||||||||
Credit facility borrowings | 100 | - | 100 | - | - | ||||||||||||||||||||||||||||||
Interest payments | 173 | 21 | 42 | 29 | 81 | 769 | 59 | 118 | 118 | 474 | |||||||||||||||||||||||||
Operating leases(e) | 16 | 1 | 2 | 2 | 11 | 139 | 11 | 22 | 20 | 86 | |||||||||||||||||||||||||
2007 Illinois Electric Settlement Agreement | 1 | 1 | - | - | - | ||||||||||||||||||||||||||||||
Other obligations(f) | 1,043 | 263 | 428 | 161 | 191 | 863 | 427 | 431 | 5 | - | |||||||||||||||||||||||||
Total cash contractual obligations | $ | 1,800 | $ | 574 | $ | 473 | $ | 342 | $ | 411 | $ | 2,696 | $ | 497 | $ | 671 | $ | 143 | $ | 1,385 | |||||||||||||||
IP: | |||||||||||||||||||||||||||||||||||
Long-term debt(b)(c) | $ | 1,150 | $ | - | $ | - | $ | - | $ | 1,150 | |||||||||||||||||||||||||
Interest payments | 752 | 85 | 170 | 170 | 327 | ||||||||||||||||||||||||||||||
Operating leases(e) | 6 | 2 | 3 | 1 | - | ||||||||||||||||||||||||||||||
2007 Illinois Electric Settlement Agreement | 1 | 1 | - | - | - | ||||||||||||||||||||||||||||||
Other obligations(f) | 733 | 226 | 297 | 87 | 123 | ||||||||||||||||||||||||||||||
Total cash contractual obligations | $ | 2,642 | $ | 314 | $ | 470 | $ | 258 | $ | 1,600 | |||||||||||||||||||||||||
| (a) | Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations. |
| (b) | Excludes fair-market value adjustments of long-term debt of |
| (c) | Excludes unamortized discount of |
| (d) | The |
| (e) | Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. Ameren’s $2 million annual obligation for these items is included in the Less than 1 Year, 1 – 3 Years, and 3 – 5 Years columns. Amounts for After 5 Years are not included in the total amount because that period is indefinite. |
| (f) | See Other Obligations within Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items |
As of December 31, 2009,2010, the amounts of unrecognized tax benefits under the authoritative accounting guidance for uncertain tax positions were $135$246 million, $88$164 million, $- million, $28 million, $15$56 million, and $-$20 million for Ameren, UE, CIPS,AIC, and Genco, CILCO and IP, respectively. It is reasonably possible to expect that the settlement of an unrecognized tax benefit will result in an underpayment or overpayment of tax and related interest. However, there is a high degree of uncertainty with respect to the timing of cash payments or receipts associated with unrecognized tax benefits. The amount and timing of certain payments or receipts is not reliably estimable or determinable at this time. See Note 13 – Income Taxes under Part II, Item 8, of this report for information regarding the Ameren Companies’ unrecognized tax benefits and related liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2009,2010, none of the Ameren Companies had any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
Credit Ratings
The credit ratings of the Ameren Companies affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and collateral posting requirements under commodity contracts.
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 | Baa3 | BBB | |||||||||||||
Senior unsecured debt | Baa3 | BBB | |||||||||||||
Commercial paper | P-3 | A-3 | F2 | ||||||||||||
UE: | |||||||||||||||
Issuer/corporate credit rating | Baa2 | BBB+ | |||||||||||||
Secured debt | A3 | BBB+ | A | ||||||||||||
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Issuer/corporate credit rating | Baa3 | BBB | |||||||||||||
Secured debt | Baa1 | BBB+ | |||||||||||||
Senior unsecured debt | Baa3 | | BBB- | ||||||||||||
Genco: | |||||||||||||||
Issuer/corporate credit rating | Baa3 | BBB- | BBB | ||||||||||||
Senior unsecured debt | |||||||||||||||
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| Baa3 | ||||||||||||||
| BBB | ||||||||||||||
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Moody’s Ratings Actions
On January 29, 2009, Moody’s affirmed the ratings of CIPS, CILCO and IP and changed their rating outlooks to stable from positive. According to Moody’s, the change in the rating outlooks of these three companies was based on the near-term expiration of the 2007 and 2006 $500 million
credit facilities in January 2010 and related liquidity concerns. Moody’s also on January 29, 2009, affirmed the ratings of Ameren and UE with a stable outlook based on the January 2009 MoPSC electric rate order approving a rate increase and a FAC for UE.
On February 16, 2009, Moody’s affirmed the ratings of Ameren, UE, CIPS, Genco, CILCO, and IP with a stable outlook. The affirmation reflected Moody’s view that Ameren’s announcement to reduce its common dividend by 39% was a conservative, prudent, and credit positive action that would conserve cash and support financial coverage metrics. Moody’s stated that the more conservative dividend payout should also help facilitate the renewal of Ameren’s credit facilities that expired in 2010. They stated the dividend reduction should continue to reduce reliance on the credit facilities going forward and would likely be viewed favorably by lenders considering renewing or entering into new facilities with Ameren and its subsidiaries, which was important considering constrained credit market conditions at that time. According to Moody’s, the stable outlook on Ameren, UE, CIPS, Genco, CILCO, and IP reflected constructive rate case outcomes at UE, CIPS, CILCO and IP, including the approval of a FAC at UE; the improving regulatory environments for investor-owned utilities in Illinois and Missouri at that time; and Moody’s expectation that financial and cash flow coverage metrics should remain adequate to maintain current rating levels. In addition, Moody’s noted that the dividend reduction was supportive of the stable ratings outlooks and provided Ameren and its subsidiaries additional cushion at the rating levels.
On July 1, 2009, Moody’s stated that the successful execution of new two-year bank credit facilities was supportive of the credit quality of Ameren and its utility subsidiaries. However, Moody’s did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.
On August 3, 2009, Moody’s upgraded the majority of senior secured debt ratings of investment-grade regulated utilities by one notch. Senior secured debt ratings at UE were upgraded from Baa1 to A3 and at CIPS and IP from Baa3 to Baa2. Moody’s stated the rating action widened the notching between most senior secured debt ratings and senior unsecured debt ratings of investment-grade regulated utilities to two notches from one previously. Moody’s noted the wider notching was based on its analysis of the history of regulated utility defaults, which indicated that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than nonfinancial, nonutility corporate issuers.
On August 13, 2009, Moody’s upgraded the ratings of CIPS, CILCO and IP. Issuer/corporate credit ratings at CIPS, CILCO and IP were upgraded from Ba1 to Baa3. Moody’s also upgraded the senior secured debt ratings at CIPS, CILCO and IP from Baa2 to Baa1. Moody’s cited the execution of new bank credit facilities and an improved political and regulatory environment in Illinois as the basis for the return to investment grade status of the issuer/corporate ratings. Moody’s also affirmed the ratings of Ameren, UE and Genco
and assigned a stable outlook for Ameren and all of its rated subsidiaries.
S&P Ratings Actions
On February 25, 2009, S&P stated that it viewed the reduction in Ameren’s dividend as credit supportive. S&P did not make any changes in Ameren’s or its subsidiaries’ credit ratings or outlooks as a result of this action. S&P raised the business profile of UE to “excellent” from “strong” to reflect the electric rate order issued by the MoPSC in January 2009, which S&P viewed as constructive. S&P lowered the business profile of CILCO to “satisfactory” from “strong.”
On February 25, 2010, S&P assigned improved business risk profiles to CIPS and IP of “excellent” from “strong” and to CILCO of “strong” from “satisfactory.”
Fitch Ratings Actions
On February 17, 2009, Fitch stated that the reduction in Ameren’s common stock dividend and other cost cutting measures would be favorable to bondholders and credit quality. Fitch did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.
On March 9, 2009, Fitch lowered the credit ratings of UE by one notch as follows: issuer rating to BBB+, senior secured debt to A, subordinated debt to BBB+, and preferred stock to BBB+. The rating outlook was changed to stable. Fitch stated that these downgrades were made because of deteriorating financial measures over the past several years and the expectation that they will not improve materially without further rate support. They noted the financial deterioration was primarily due to increasing fuel and operating costs and a large capital expenditure program.
On July 31, 2009, Fitch affirmed the credit rating of Genco and changed its rating outlook to negative from stable. Additionally, Fitch affirmed the credit ratings of Ameren with a stable outlook. According to Fitch, the change in the credit rating outlook of Genco was based on the unfavorable outlook for wholesale energy prices and the sensitivity of the company’s largely coal-fired generating fleet to greenhouse gas and other environmental regulations. According to Fitch, the affirmation of Ameren’s credit ratings and stable outlook reflected the significant earnings and cash flow contribution derived from regulated utilities, the beneficial impact of recent rate increases in Illinois and Missouri, the savings generated by the February 2009 dividend reduction, and steps taken to maintain liquidity, including the renewal of bank credit facilities.
On January 22, 2010, Fitch announced new guidelines that affect its ratings on deferrable coupon hybrid securities and preferred stock for utility issuers. Under these new guidelines, Fitch will rate these securities two notches below the issuer’s senior unsecured debt ratings. The prior guidelines rated these securities one notch below. The ratings for UE, CIPS, CILCO and IP’s preferred stock, and for UE’s
7.69% subordinated deferrable interest debentures, were affected by this industry-wide methodology change.
Collateral Postings
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. CollateralCash collateral postings and prepayments made with external parties including postings related to exchange-traded contracts at December 31, 2009,2010, were $106$166 million, $25 million, $3 million, $1$15 million and $14$116 million at Ameren, UE CIPS, CILCO and IP,AIC, respectively. The amount of cash collateral external counterparties posted with Ameren was $12less than $1 million at December 31, 2009.2010. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at December 31, 2009,2010, could have resulted in Ameren, UE, CIPS,AIC or Genco CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $368$274 million, $129$93 million, $29 million, $48 million, $44$111 million, and $52$28 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than December 31, 2009,2010, levels in the next twelve12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS,AIC or Genco CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $171$61 million, $82$13 million, $- million, $- million, $9 million, and $- million, respectively. If market prices were 15% lower than December 31, 2009,2010, levels in the next twelve12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS,AIC or Genco CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $329$107 million, $171$9 million, $14 million, $- million, $53$62 million, and $50$- million, respectively.
The cost of borrowing under our credit facilities can also 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.
Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 20102011 and beyond.
Economy and Capital and Credit Markets
In 2008 and 2009, global capital and credit markets experienced extreme volatility. While these markets improved during 2009, the availability and cost of capital and economic activity continue to be significantly affected. We believe that
these events have several implications for our industry as a whole, including Ameren. They include the following:
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charges at their Merchant Generation reporting |
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| Ÿ | On September 10, 2010, Ameren and certain of its subsidiaries entered into new multiyear credit facility agreements. These facilities cumulatively provide $2.1 billion of credit through September 10, 2013, subject to borrowing sublimit extensions. The costs of these credit facilities are less than the costs of the facilities they replaced. Costs are being amortized over the term of the 2010 Credit Agreements. Fees for UE will be deferred for recovery in future customer rates. In addition, borrowing rates under the facilities decreased, including, in the case of Ameren, from LIBOR plus 3.25%, under the prior credit facilities, to LIBOR plus 2.05%. |
At December 31, |
| Ÿ | Economic conditions could affect the |
We believe that our liquidity is adequate given our expected operating cash flows, capital expenditures, and related financing plans (including accessing our existing credit facilities).plans. However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets, or other unforeseen events will not materially affect our ability to execute our expected operating, capital or financing plans.
Current Capital Expenditure Plans
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compliance with |
Approximately |
| Ÿ | Future federal and state legislation or regulations that mandate limits on emissions would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly situated electric power generators to close some coal-fired facilities. Investments to control emissions at Ameren’s coal-fired power plants to comply with future legislation or regulations would significantly increase future capital expenditures and operations and maintenance expenses, which if excessive could result in the |
| Ÿ | UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s integrated resource plan filed with the MoPSC in February |
| Ÿ | UE is considering filing an application to obtain an ESP from the NRC at the Callaway nuclear plant site. In |
an ESP application with the NRC |
| Ÿ | UE intends to submit a license extension application with the NRC to extend its existing Callaway nuclear plant’s |
operating license by 20 years so that the |
| Ÿ | Over the next few years, we expect to make significant investments in our electric and natural gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are |
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| Ÿ | In September 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could lead to repowering Genco’s Meredosia plant. This would create the world’s first full-scale, oxy-combustion coal-fired power plant designed for permanent CO2capture and |
| Ÿ | Increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs. |
Revenues
| Ÿ | The earnings of UE |
| Ÿ | In |
| Ÿ | In |
| Ÿ | The April 2010 ICC order confirmed the previously approved 80% allocation of fixed nonvolumetric residential and commercial natural gas customer charges and approved a higher percentage of recovery of fixed nonvolumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed nonvolumetric electric residential and commercial customer and meter charges increased from 27% to 40%. |
| Ÿ | AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric delivery service by $60 million. AIC also filed a request with the ICC in February 2011 to increase its annual revenues for natural gas delivery service by $51 million. AIC is using a future test year, 2012, in each of these rate |
| Ÿ | AIC filed a request with FERC in January 2011 to increase its annual revenues for electric delivery service for its wholesale customers by approximately $11 million. AIC provides electric delivery service to nine wholesale customers. These wholesale delivery revenues are treated as a deduction in AIC’s revenue requirement in retail rate filings with the |
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| Ÿ | In |
| Ÿ | The provisions of the May 2010 MoPSC order also resulted in the recognition of new regulatory assets. These new regulatory assets are being amortized over the next two to five years beginning July 2010, as described in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. The increased amortization of the regulatory assets and the increase in annual depreciation expense due to the adoption of the life span depreciation methodology is estimated to increase UE’s pretax expense by $25 million in 2011. |
| Ÿ | Noranda appealed certain aspects of the MoPSC’s January 2009 electric rate order to the Circuit Court of Stoddard County and was granted a stay by the Circuit Court of Stoddard County as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. In September 2010, UE filed an appeal with the Missouri Court of Appeals for the Southern District of Missouri. The Court of Appeals will conduct an independent review of the MoPSC’s January 2009 electric order. A decision by the Court of Appeals is not expected until at least the third quarter of 2011. |
| Ÿ | On February 16, 2011, the Missouri Office of Public Counsel (MoOPC) made a filing with the MoPSC in which the MoOPC argued that the December 20, 2010 Order Granting Stay Pursuant to Section 386.520 (Stay Order), discussed below, of the Circuit Court of Cole County, Missouri (Circuit Court) should apply to all UE customers rather than to just the four UE industrial customers that requested the Circuit Court to grant these industrial customers’ request to stay the MoPSC’s 2010 Missouri electric rate order as to their billings. On that basis, the MoOPC requested the MoPSC to suspend UE’s currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with UE’s previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. If the requested suspension occurs, it would continue until |
the earlier of the time that a subsequent order is issued by the MoPSC, or an order reversing any such suspension is issued by a court of competent jurisdiction, but in no event beyond the implementation of new electric rates for UE. It is anticipated that new electric rates for UE will take effect by early August 2011, pursuant to an anticipated MoPSC rate order in UE’s currently pending |
| Ÿ | Also on February 16, 2011, the Missouri Industrial Energy Consumers (MIEC), of which the four UE industrial customers referred to above are members, made a filing with the MoPSC in response to the MoOPC filing discussed above. In its filing, MIEC supported the position set forth in the |
| Ÿ | The filings by the MoOPC and MIEC relate to the December 20, 2010 Stay Order, in which the Circuit Court granted the request of four UE industrial customers to stay the MoPSC’s 2010 Missouri electric rate |
expected to |
| Ÿ | The Stay Order does not address the merits of the appeals of the MoPSC’s 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. The judicial review process typically takes 18 to 24 months to complete following the initiation of the process. At this time, UE does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 Missouri electric rate orders are probable of refund to UE’s customers. If UE were to conclude that some portion of these rate increases become probable of refund to UE’s customers, a |
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from operations |
| Ÿ | UE |
net fuel costs and $32 million of asset disallowances relating to the Sioux plant scrubbers. Other parties also made recommendations through testimony filed in |
| Ÿ | In January 2011, the MoPSC approved a stipulation and agreement that resolved a June 2010 request by UE to increase annual natural gas revenues. The stipulation and agreement authorized an increase in annual natural gas delivery revenues of $9 million, which included approximately $2 million of annual revenues previously collected through the ISRS rider for the test year ended December 31, 2009. The new rates became effective on February 20, 2011. The stipulation and agreement approved a revised block-rate structure for residential customers that results in more certainty of margin revenue recovery regardless of weather conditions or conservation efforts as recovery is less dependent on usage. |
| Ÿ | Missouri |
| Ÿ | As part of the 2007 Illinois Electric Settlement Agreement, |
| Ÿ | Volatile power prices in the Midwest can affect the amount of revenues Ameren |
marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets. |
| Ÿ | With few scheduled |
|
| Ÿ | The availability and performance of Ameren’s and Genco’s |
| Ÿ | The marketing strategy for the Merchant Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Merchant Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Merchant Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of |
|
| Ÿ | Current and future energy efficiency programs developed by UE, |
earned on supply-side capital investments, or recovery of their |
Fuel and Purchased Power
| Ÿ | In |
|
| Ÿ | Ameren’s fuel costs (including transportation) are expected to increase in |
Other Costs
| Ÿ | 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. |
|
could be material. See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for further discussion of Taum Sauk matters. |
| Ÿ | UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage will be in the |
| Ÿ | Over the next few years, we expect rising employee benefit costs, |
| Ÿ | Ameren’s Merchant Generation segment is expecting 2011 non-fuel other operations and maintenance expenses to be approximately $310 million, which is approximately 10% greater than other operations and maintenance expenses recorded in 2010. Higher employee-related costs are the primary driver for the expected increase. |
| Ÿ | The reduction in carrying value for some long-lived and intangible Merchant Generation assets, recognized as a result of Ameren’s and Genco’s third quarter 2010 impairment tests, as well as a corresponding change in the useful lives for some assets, is not expected to have a material impact on Ameren’s or Genco’s 2011 net income. |
| Ÿ | On January 12, 2011, the Illinois governor signed legislation that would increase the state’s corporate income tax rate from the current 7.3% to 9.5% (including the replacement tax), starting in 2011. The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3%, in 2025. This corporate income tax rate increase in Illinois is expected to increase Ameren’s income tax expense between $5 to $10 million in 2011 (AIC – $3 million to $6 million, Genco – $1 million to $2 million). |
| Ÿ | UE, AIC, ATXI and Marketing Company are MISO members. Each member company of MISO is responsible for a portion of MISO’s market cost. Recently, some non-Ameren Companies have announced their intention to leave MISO, while other companies have announced plans to study their potential inclusion into MISO. In the near term, it appears likely that more companies will exit MISO than will join it. Ameren could be negatively affected as existing MISO companies leave the RTO as Ameren’s operating companies would bear a larger share of MISO’s market costs. At this time, Ameren is unable to estimate the effects of these MISO member changes on its results of operation, financial position, and liquidity. |
Other
| Ÿ | A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least |
15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Compliance with the renewable energy portfolio requirement can be achieved through generation, the procurement of renewable energy, or the procurement of renewable energy credits. |
| Ÿ |
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| Ÿ | AIC’s $150 million 6.625% senior secured notes will mature in June 2011. AIC expects to use cash on hand and operating cash flows to pay the bondholders $150 million, plus interest, at the maturity date. Additionally in 2011, AIC is planning to contribute approximately $100 million to Ameren’s postretirement benefit plan. This cash contribution will reduce future postretirement expense. |
| Ÿ | In July 2010, President Obama signed into law the Wall Street Reform and Consumer Protection Act. This law will require additional |
Trading Commission has issued a number of |
| Ÿ | In |
care reforms, including any clarifying regulations issued to address how the |
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The above items could have a material impact on our results of operations, financial position, andor liquidity. Additionally, in the ordinary course of business, we evaluate our strategies to enhance our results of operations, financial position, andor liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s stockholder 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, andor liquidity.
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors which in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
Accounting Estimate
Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery
All of the Ameren, Companies except GencoUE and AIC defer costs in accordance with authoritative accounting guidance, and make investments that they assume will be collected in future rates.
| Ÿ | Regulatory environment and external regulatory decisions and requirements |
| Ÿ | Anticipated future regulatory decisions and their impact |
| Ÿ | Impact of deregulation, rate freezes, prudency reviews, and competition on ratemaking process and ability to recover costs |
Basis for Judgment
We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate orand any other factors that lead us to believe thatmay indicate whether cost recovery is probable. If facts and circumstances lead us to conclude that a recorded regulatory asset is probably no longer recoverableprobable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for quantification of these assets by registrant.for each of the Ameren Companies, excluding Genco.
Unbilled Revenue
At the end of each period, UE CIPS, CILCO and IPAIC project expected usage and estimate the amount of revenue to record for services that have been provided to customers but not yet billed.
| Ÿ | Projecting customer energy usage |
| Ÿ | Estimating impacts of weather and other usage-affecting factors for the unbilled period |
| Ÿ | Estimating loss of energy during transmission and delivery |
Basis for Judgment
We base our estimate of unbilled revenue each period on the volume of energy delivered, as valued by a model of billing cycles and historical usage rates and growth by customer class for our service area. This figure is then adjusted for the modeled impact of seasonal and weather variations based on historical results. See the balance sheets for each of the Ameren, Companies, excluding Genco,UE and AIC, under Part II, Item 8, of this report for unbilled revenue amounts.
Accounting Estimate
Uncertainties Affecting Application
Derivative Financial Instruments
We account for derivative financial instruments and measure their fair value in accordance with authoritative accounting guidance. The identification and classification of a derivative and the fair value of such derivative must be determined. See Commodity Price Risk and Fair Value of Contracts in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, Note 7 – Derivative Financial Instruments and Note 8 -– Fair Value Measurements under Part II, Item 8, of this report.
| Ÿ | Our ability to assess whether derivative contracts qualify for the NPNS |
| Ÿ |
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| Ÿ | Market conditions in the energy industry, especially the effects of price volatility and liquidity |
| Ÿ | Valuation assumptions on longer term contracts due to lack of observable inputs |
| Ÿ | Effectiveness of derivatives that have been designated as hedges |
| Ÿ | Counterparty default risk |
Accounting Estimate
Uncertainties Affecting Application
Basis for Judgment
We determine whether to exclude the fair value of certain derivatives from valuation under the normal purchase and normal salesNPNS provisions of authoritative accounting guidance based uponafter assessing our intent and ability to physically deliver commodities purchased and sold. Further, our forecasted purchases and sales also support our designation of some fair-valued derivative instruments as cash flow hedges. Fair value of our derivatives is measured in accordance with authoritative accounting guidance, which provides a fair value hierarchy that prioritizes inputs to valuation techniques. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When we do not have observable inputs, we use certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risks inherent in the inputs to the valuation. Our valuations also reflect our own assessment of counterparty default risk, using the best internal and external information available. If we were required to discontinue our use of the normal purchase and normal salesNPNS exception or cash flow hedge treatment for some of our contracts, the impact of changes in fair value for the applicable contracts could be material to our earnings.
Valuation of Goodwill, Intangible Assets, Long-Lived Assets, and Asset Retirement Obligations
We periodically assess the carrying value of our goodwill, intangible assets, and long-lived assets to determine whether they are impaired. We also review for the existence of asset retirement obligations. If an asset retirement obligation is identified, we determine its fair value and subsequently reassess and adjust the obligation, as necessary.
| Ÿ | Management’s identification of impairment indicators |
| Ÿ | Changes in business, industry, laws, technology, or economic and market conditions |
| Ÿ | Valuation assumptions and conclusions |
| Ÿ | Our assessment of market participants |
| Ÿ | Estimated useful lives of our significant long-lived assets |
| Ÿ | Actions or assessments by our regulators |
| Ÿ | Identification of an asset retirement obligation and assumptions about the timing of asset removals |
Basis for Judgment
Annually, or whenever events indicate a valuation may have changed, we use various methodologies that we believe market participants would use to determine valuations, including earnings before interest, taxes, depreciation and amortization multiples, and discounted, undiscounted, and probabilistic discounted cash flow models with multiple operating scenarios. The identification of asset retirement obligations is conducted through the review of legal documents and interviews. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for quantification of our goodwill, intangible assets, and asset retirement obligations. See Note 17 – Goodwill and Other Asset Impairments under Part II, Item 8, of this report for additional information of our goodwill, intangible asset, and long-lived asset impairment evaluation.evaluation and charge recorded in 2010.
Accounting Estimate
Uncertainties Affecting Application
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of providing future employee benefits in accordance with authoritative accounting guidance regarding benefit plans. See Note 11 – Retirement Benefits under Part II, Item 8, of this report.
| Ÿ | Future rate of return on pension and other plan assets |
| Ÿ | Interest rates used in valuing benefit obligations |
| Ÿ | Health care cost trend rates |
| Ÿ | Timing of employee retirements and mortality assumptions |
| Ÿ | Ability to recover certain benefit plan costs from our ratepayers |
| Ÿ | Changing market conditions impacting investment and interest rate environments |
| Ÿ | Impacts of the health care reform legislation enacted in 2010 |
Basis for Judgment
Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable. See Note 11 – Retirement Benefits under Part II, Item 8, of this report for sensitivity of Ameren’s benefit plans to potential changes in these assumptions.
Accounting for Contingencies
We make judgments and estimates in recording liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. A gain contingency is not recorded until realized or realizable.
| Ÿ | Estimating financial impact of events |
| Ÿ | Estimating likelihood of outcomes |
| Ÿ | Regulatory and political environments and requirements |
| Ÿ | Outcome of legal proceedings, settlements or other factors |
Basis for Judgment
The determination of a loss contingency requires significant judgment as to the expected outcome of each contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider all available evidence including the expected outcome of potential litigation. We record our best estimate of a loss or the minimum value of our estimated range of outcomes if no estimate is better than another estimate within our range of estimates. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. See Note 2 – Rate and Regulatory Matters, Note 10 – Callaway Nuclear Plant, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for information on the Ameren Companies’ contingencies.
Impact of Future Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
EFFECTS OF INFLATION AND CHANGING PRICES
Ameren’s rates for retail electric and natural gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by FERC. Adjustments to rates areRate regulation is generally based on a regulatory process that reviews athe recovery of historical period.or projected costs. As a result, revenue increases willcould lag behind changing prices. Inflation affects our operations, earnings, stockholders’ equity, and financial performance.
The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace the plant in
future years. Ameren’s Merchant Generation businesses do not have regulated recovery mechanisms and are therefore dependent on market prices for power to reflect rising costs.
As a part of the electric rate order issued by the MoPSC in January 2009, UE was granted permission to put in place, effective March 1, 2009, a FAC. Historically, in UE’s Missouri electric utility jurisdiction, there was no tariff for adjusting rates to accommodate changes inrecovers the cost of fuel for electric generation orand the cost of purchased power. As part of its pending electric rate case, UE requested the MoPSC to approve the continued use of the FAC and implementation ofpower by adjusting rates as allowed through an environmental cost recovery mechanism. The environmental cost recovery mechanism, if approved, would allow UE to adjust electric rates twice each year outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state, or local environmental laws, regulations, or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews by the MoPSC. UE’s request was consistent with the environmental cost recovery rules approved by the MoPSC in April 2009. UE will not be able to implement an
environmental cost recovery mechanism until so authorized by the MoPSC as part of a rate case proceeding. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information on UE’s pending electric rate case.
CIPS, CILCO and IP recoverFAC. AIC recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.
UE CIPS, CILCO, and IPAIC are affected by changes in the cost of electric transmission services. FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files regional transmission tariff rates for approval by FERC. All members
within that RTO are then subjected to those rates. As members of MISO, UE’s CIPS’, CILCO’s and IP’sAIC’s transmission rates are calculated in accordance with MISO’s rate formula. The transmission rate is updated in June of each year based on FERC filings. This rate is charged directly to wholesale customers. The Ameren Illinois UtilitiesAIC also chargecharges this rate directly to alternative retail electric suppliers. For the Ameren Illinois Utilities’Illinois’ retail customers who have not chosen an alternative retail electric supplier, the transmission rate is collected through a rider mechanism. This rate is not directly charged to Missouri retail customers because the MoPSC includes transmission-related costs in setting bundled retail rates in Missouri.
In our Missouri and Illinois retail natural gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses.
Ameren, UE Genco, and AERGGenco are affected by changes in market prices for natural gas to the extent that they must purchase natural gas to run CTs. These companies have structured various supply agreements to maintain access to multiple gas pools and supply basins, and to minimize the impact to their financial statements. See Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk under Part II, Item 7A, below for additional information. Also see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on the cost recovery mechanisms discussed above.
| ITEM 7A. | 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 to 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.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
| Ÿ | long-term and short-term variable-rate debt; |
| Ÿ | fixed-rate debt; |
| Ÿ | auction-rate long-term |
| Ÿ | defined pension and postretirement benefit plans. |
We manage our interest rate exposure by controlling the amount of thesedebt instruments we have within our total capitalization portfolio and by monitoring the effects of market changes in interest rates. For defined pension and postretirement benefit plans, we control the duration and portfolio mix of our plan assets.
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 December 31, 2009:2010:
| Interest Expense | Net Income(a) | Interest Expense | Net Income(a) | |||||||||||||
Ameren(b) | $ | 12 | $ | (7 | ) | $ | 10 | $ | (6 | ) | ||||||
UE | 2 | (1 | ) | 2 | (1 | ) | ||||||||||
CIPS | - | - | ||||||||||||||
AIC | (c | ) | (c | ) | ||||||||||||
Genco | - | - | 2 | (1 | ) | |||||||||||
CILCO | 3 | (2 | ) | |||||||||||||
IP | (c | ) | (c | ) | ||||||||||||
| (a) | Calculations are based on an effective tax rate of 38%. |
| (b) | Includes intercompany eliminations. |
| (c) | Less than $1 million. |
The estimated changes above do not consider the 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. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges 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. See Note 7 – Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2009.2010.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is
mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2009,2010, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. The risk associated with the Ameren Illinois Utilities’AIC’s electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows the Ameren Illinois UtilitiesAIC to recover the difference between theirits actual bad debt expense under GAAP and the bad debt expense included in theirits base rates. UE and the Ameren Illinois UtilitiesAIC continue to monitor the impact of increasing rates and a weak economic environment on customer collections. UE and the Ameren Illinois UtilitiesAIC make adjustments to their allowance for doubtful accounts as
deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.
Ameren, UE, CIPS,AIC and Genco CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with interchangeoff-system or wholesale purchase and sale activity with nonaffiliated companies. At December 31, 2009,2010, Ameren’s, UE’s, CIPS’,AIC’s and Genco’s CILCO’s, AERG’s, IP’s, AFS’, and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $2$3 million, net of collateral (2008(2009 – less than $1$2 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. It 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 lease. We estimate our credit exposure to MISO associated with the MISO Energy and Operating Reserves Market to be $13$53 million at December 31, 2009 (20082010 (2009 – $46$13 million).
Equity Price Risk
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide the benefits at the time they are payable and also to maximize total return on plan assets and minimize expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class.specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio
management results compared with benchmark returns, and for the effect of expenses paid from plan assets.
In future years, the costs of such plans reflected in net income, OCI, or regulatory assets, and cash contributions to the plans could increase materially, without pension and postretirement asset portfolio investment returns equal to or in excess of our 2011 assumed return on plan assets of 8%. and 7.75%, respectively.
UE also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2009,2010, this fund was
invested primarily in domestic equity securities (67%(68%) and debt securities (33%(32%). It totaled $293$337 million (2008(2009 – $239$293 million). By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates. UE actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the assets of the trust to various investment options. UE’s exposure to equity price market risk is in large part mitigated, because UE is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Commodity Price Risk
We are exposed to changes in market prices for electricity, emission allowances, fuel, and natural gas.
Ameren’s, UE’s Genco’s, AERG’s and EEI’sGenco’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEIMerchant Generation also seekseeks to sell power forward to wholesale, municipal, and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through risk management programs and policies, which include 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 Ameren, UE Genco, AERG and EEIGenco 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 20102011 through 2013:2014:
| Net Income(a) | ||||
Ameren(b) | $ | | ) | |
UE | ) | |||
Genco | ||||
| ||||
| ||||
| (a) | Calculations are based on an effective tax rate of 38%. |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (c) | Less than $1 million. |
Ameren’s forward-hedging power programs include the use of derivative financial swap contracts. These swap contracts financially settle a fixed price against a floating price. The floating price is typically the realized, or settled, price at a liquid regional hub at some forward period of time. Ameren controls the use of derivative financial swap contracts with volumetric and correlation limits that are intended to mitigate any material adverse financial impact. Historically, Ameren has utilized swaps that settle against the Cinergy Hub MISO locational marginal pricing. This hub had traditionally been the most liquid location, with a strong correlation to the pricing that was realized at our generating locations. As of December 31, 2011, MISO intends to stop publishing Cinergy Hub pricing. As a result, Ameren will pursue financial hedging at the next best available regional location with sufficient liquidity. Ameren does not expect any material adverse financial impact to the outcomes of its forward-hedging programs as a result of this change. Ameren will continue to pursue the best available options to fix pricing for the output of its generating units.
Ameren also uses 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.
We manage risks associated with changing prices of fuel for generation using techniques similar to those used to manage risks associated with changing market prices for electricity.
Most Ameren, UE Genco and AERGGenco fuel supply contracts are physical forward contracts. Genco, AERG and EEI doMerchant Generation does not have the ability to pass through higher fuel costs to theirits customers for electric operations.operations with the exception of an immaterial percentage of the output that has been contracted with a fuel cost pass through. Prior to March 2009, UE did not have this ability either except through a general rate proceeding. As a part of the January 2009The MoPSC electric rate order,granted UE was granted permission to put a FAC in place which became effectivebeginning March 1, 2009. UE remains exposed to 5% of changes, greater or less than the amounts set in base rates, in its fuel and purchased power costs, net of off-system revenues.
Ameren, UE Genco, AERG and EEIGenco have entered into long-term contracts with various suppliers to purchase coal 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. Ameren, UE Genco, AERG and EEIGenco generally purchase coal up to five years in advance, but wethey 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. UE has an ongoing need for coal to serve its native load customers and pursues a price hedging strategy consistent with this requirement. Merchant Generation’s forward coal requirements are dependent on the volume of power sales that have been contracted. As such, Merchant Generation strives to achieve increased margin certainty by aligning its fuel purchases with their power sales.
Transportation costs for coal and natural gas can be a significant portion of fuel costs. Ameren, UE Genco, AERG and EEIGenco typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of Ameren, UE Genco, AERG and EEIGenco are regulated by FERC through approved tariffs governing the rates, terms, and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the contracts prior to the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates 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 five-year period 2010 through 2014, as of December 31, 2009. The projected required supply of these commodities could be significantly affected by changes in our assumptions for such matters as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
| 2010 | 2011 | 2012 – 2014 | |||||||
Ameren: | |||||||||
Coal | 97 | % | 61 | % | 15 | % | |||
Coal transportation | 100 | 93 | 40 | ||||||
Nuclear fuel | 100 | 89 | 58 | ||||||
Natural gas for generation | 73 | 8 | - | ||||||
Natural gas for distribution(a) | 96 | 45 | 20 | ||||||
Purchased power for Illinois Regulated(b) | 82 | 55 | 16 | ||||||
UE: | |||||||||
Coal | 98 | % | 61 | % | 14 | % | |||
Coal transportation | 100 | 100 | 44 | ||||||
Nuclear fuel | 100 | 89 | 58 | ||||||
Natural gas for generation | 89 | 11 | - | ||||||
Natural gas for distribution(a) | 97 | 48 | 27 | ||||||
CIPS: | |||||||||
Natural gas for distribution(a) | 91 | % | 40 | % | 17 | % | |||
Purchased power(b) | 82 | 55 | 16 | ||||||
Genco: | |||||||||
Coal | 97 | % | 61 | % | 16 | % | |||
Coal transportation | 100 | 70 | 24 | ||||||
Natural gas for generation | 100 | 19 | - | ||||||
CILCO: | |||||||||
Coal (AERG) | 97 | % | 63 | % | 18 | % | |||
Coal transportation (AERG) | 100 | 100 | 57 | ||||||
Natural gas for distribution(a) | 93 | 47 | 20 | ||||||
Purchased power(b) | 82 | 55 | 16 | ||||||
IP: | |||||||||
Natural gas for distribution(a) | 99 | % | 46 | % | 19 | % | |||
Purchased power(b) | 82 | 55 | 16 | ||||||
EEI: | |||||||||
Coal | 97 | % | 60 | % | 14 | % | |||
Coal transportation | 100 | 100 | 34 |
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 2010 through 2014.
| Coal | Transportation | |||||||||||
Fuel Expense | Net Income(a) | Fuel Expense | Net Income(a) | |||||||||
Ameren(b) | $ | 19 | $ | (12) | $ | 17 | $ | (10) | ||||
UE | 11 | (7) | 7 | (4) | ||||||||
Genco | 4 | (3) | 6 | (4) | ||||||||
CILCO | 2 | (1) | 1 | (1) | ||||||||
EEI | 2 | (1) | 2 | (1) | ||||||||
In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. If diesel fuel costs were to increase or decrease by $0.25/$0.25 a gallon, Ameren’s fuel expense could increase or decrease by $10$12 million annually (UE – $5$7 million, Genco – $2 million, AERG – $1 million and EEI – $2$4 million). As of December 31, 2009,2010, Ameren had a price cap for approximately 93%89% of expected fuel surcharges in 2010.2011.
In the event of a significant change in coal prices, Ameren, UE Genco, AERG and EEIGenco 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.
With regard to exposure for commodity price risk for nuclear fuel, UE has both fixed-priced, base-price-with-escalation, and base-price-with- escalationmarket-priced agreements. It also uses inventories thatto provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion enrichment, and fabrication services.enrichment. There is no fuel reloading or planned maintenance outage scheduled for 2012.2012 and 2015. UE has price hedges (including inventories) for 75%approximately 83% of the 2010its 2011 to 2014 nuclear fuel requirements.
Nuclear fuel market prices remain subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing its inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some a base-price-with-escalation price mechanism, and may also have either a
market-price-related component.component or market-based price re-benchmarking. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices that cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have somewhat limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.
With regard to the electric generating operations for Ameren, UE Genco and AERGGenco that are exposed to changes in market prices for natural gas used to run CTs, the natural gas procurement strategy is designed to ensure reliable and
immediate delivery of natural gas while minimizing costs. We optimize transportation and storage options and price risk by structuring supply agreements to maintain access to multiple gas pools and supply basins.
Through the market allocation process, UE, CIPS,AIC and Genco CILCO and IP have been granted FTRs associated with the MISO Energy and Operating Reserves Market. In addition, Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois market. The FTRs are intended
to mitigate expected electric transmission congestion charges related to the physical electricity business. Depending on the congestion and prices at various points on the electric transmission grid, FTRs could result in either charges or credits. Complex grid modeling tools are used to determine which FTRs to nominate in the FTR allocation process. There is a risk of incorrectly modeling the amount of FTRs needed, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.
With regard to UE’s CIPS’, CILCO’s and IP’sAIC’s electric and natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow UE CIPS, CILCO and IPAIC to pass on to retail customers prudently incurred fuel, purchased power and gas supply costs. UE’s CIPS’, CILCO’s and IP’sAIC’s strategy is designed to reduce the effect of market fluctuations for our regulated customers. The effects of price volatility cannot be eliminated. However, procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.
The following table presents, as of December 31, 2010, 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 AIC, which does not own generation, that are price-hedged over the five-year period 2011 through 2015. The projected required supply of these commodities could be significantly affected by changes in our assumptions for such matters as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
| 2011 | 2012 | 2013 – 2015 | ||||||||||
Ameren(a): | ||||||||||||
Coal | 94 | % | 55 | % | 11 | % | ||||||
Coal transportation | 100 | 75 | 28 | |||||||||
Nuclear fuel | 98 | 84 | 78 | |||||||||
Natural gas for generation | 40 | 2 | - | |||||||||
Natural gas for distribution(b) | 89 | 39 | 19 | |||||||||
Purchased power for AIC(c) | 78 | 56 | 8 | |||||||||
UE: | ||||||||||||
Coal | 95 | % | 59 | % | 16 | % | ||||||
Coal transportation | 100 | 56 | 38 | |||||||||
Nuclear fuel | 98 | 84 | 78 | |||||||||
Natural gas for generation | 30 | 1 | - | |||||||||
Natural gas for distribution(b) | 90 | 35 | 19 | |||||||||
AIC: | ||||||||||||
Natural gas for distribution(b) | 89 | % | 39 | % | 19 | % | ||||||
Purchased power(c) | 78 | 56 | 8 | |||||||||
Genco: | ||||||||||||
Coal | 93 | % | 49 | % | 4 | % | ||||||
Coal transportation | 100 | 99 | 9 | |||||||||
Natural gas for generation | 84 | - | - | |||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| (b) | Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2011 represents January 2011 through March 2011. The year 2012 represents November 2011 through March 2012. This continues each successive year through March 2015. |
| (c) | Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. Larger customers are purchasing power from the competitive markets. See Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of the Illinois power procurement process and for additional information on AIC’s purchased power commitments. |
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 2011 through 2015:
| Coal | Coal Transportation | |||||||||||||||
Fuel Expense | Net Income(a) | Fuel Expense | Net Income(a) | |||||||||||||
Ameren(b)(c) | $ | 12 | $ | (7 | ) | $ | 12 | $ | (7 | ) | ||||||
UE(c) | 1 | (d | ) | 1 | (d | ) | ||||||||||
Genco | 8 | (5 | ) | 9 | (6 | ) | ||||||||||
| (a) | Calculations are based on an effective tax rate of 38%. |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| (c) | Includes the impact of the FAC |
| (d) | Less than $1 million. |
With regard to our exposure for commodity price risk for construction and maintenance activities, Ameren is exposed to changes in market prices for metal commodities and labor availability.
See Supply for Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear power, natural gas, hydroelectric power, and oil. Also see Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause the following:
| Ÿ | an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices; |
| Ÿ | market values of coal, natural gas, and uranium inventories or emission allowances that differ from the cost of those commodities in inventory; and |
| Ÿ | actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays. |
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that
sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty. See Note 7 – 7–Derivative Financial Instruments under Part II, Item 8, of this report for additional information.
The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2009.2010. We use various methods to determine the fair value of our contracts. In accordance with hierarchy levels outlined in authoritative accounting guidance, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years.
| Ameren(a) | UE | CIPS | Genco | CILCO | IP | Ameren(a) | UE | AIC | Genco | |||||||||||||||||||||||||||||||
Fair value of contracts at beginning of year, net | $ | 20 | $ | 16 | $ | (84 | ) | $ | (1 | ) | $ | (59 | ) | $ | (134 | ) | $ | 17 | $ | 16 | $ | (483 | ) | $ | 21 | |||||||||||||||
Contracts realized or otherwise settled during the period | 43 | (10 | ) | 54 | 1 | 57 | 102 | (20 | ) | (2 | ) | 169 | (9 | ) | ||||||||||||||||||||||||||
Changes in fair values attributable to changes in valuation technique and assumptions | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Fair value of new contracts entered into during the period | 52 | 22 | (3 | ) | 11 | 2 | (13 | ) | 2 | 4 | (19 | ) | 3 | |||||||||||||||||||||||||||
Other changes in fair value | (98 | ) | (12 | ) | (122 | ) | 2 | (75 | ) | (202 | ) | (78 | ) | (7 | ) | (160 | ) | 4 | ||||||||||||||||||||||
Fair value of contracts outstanding at end of year, net | $ | 17 | $ | 16 | $ | (155 | ) | $ | 13 | $ | (75 | ) | $ | (247 | ) | $ | (79 | ) | $ | 11 | $ | (493 | ) | $ | 19 | |||||||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
The following table presents maturities of derivative contracts as of December 31, 2009,2010, based on the hierarchy levels used to determine the fair value of the contracts:
| 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: | |||||||||||||||||||
Level 1 | $ | (8 | ) | $ | (4 | ) | $ | (1 | ) | $ | - | $ | (13 | ) | |||||
Level 2(a) | 1 | - | - | - | 1 | ||||||||||||||
Level 3(b) | 20 | 12 | (3 | ) | - | 29 | |||||||||||||
Total | $ | 13 | $ | 8 | $ | (4 | ) | $ | - | $ | 17 | ||||||||
UE: | |||||||||||||||||||
Level 1 | $ | (3 | ) | $ | (3 | ) | $ | (1 | ) | $ | - | $ | (7 | ) | |||||
Level 2(a) | - | - | - | - | - | ||||||||||||||
Level 3(b) | 5 | 18 | - | - | 23 | ||||||||||||||
Total | $ | 2 | $ | 15 | $ | (1 | ) | $ | - | $ | 16 | ||||||||
CIPS: | |||||||||||||||||||
Level 1 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||
Level 2(a) | - | - | - | - | - | ||||||||||||||
Level 3(b) | (53 | ) | (102 | ) | - | - | (155 | ) | |||||||||||
Total | $ | (53 | ) | $ | (102 | ) | $ | - | $ | - | $ | (155 | ) | ||||||
Genco: | |||||||||||||||||||
Level 1 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||
Level 2(a) | - | - | - | - | - | ||||||||||||||
Level 3(b) | 5 | 8 | - | - | 13 | ||||||||||||||
Total | $ | 5 | $ | 8 | $ | - | $ | - | $ | 13 | |||||||||
CILCO: | |||||||||||||||||||
Level 1 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||
Level 2(a) | - | - | - | - | - | ||||||||||||||
Level 3(b) | (22 | ) | (53 | ) | - | - | (75 | ) | |||||||||||
Total | $ | (22 | ) | $ | (53 | ) | $ | - | $ | - | $ | (75 | ) | ||||||
| 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 | Maturity Less than 1 Year | Maturity 1-3 Years | Maturity 4-5 Years | Maturity in Excess of 5 Years | Total Fair Value | |||||||||||||||||||||||||||||
IP: | |||||||||||||||||||||||||||||||||||||||
Ameren: | |||||||||||||||||||||||||||||||||||||||
Level 1 | $ | - | $ | (1 | ) | $ | - | $ | - | $ | (1 | ) | $ | (9 | ) | $ | (7 | ) | $ | (2 | ) | $ | - | $ | (18 | ) | |||||||||||||
Level 2(a) | - | - | - | - | - | (2 | ) | - | - | - | (2 | ) | |||||||||||||||||||||||||||
Level 3(b) | (84 | ) | (160 | ) | (2 | ) | - | (246 | ) | (21 | ) | (29 | ) | (9 | ) | - | (59 | ) | |||||||||||||||||||||
Total | $ | (84 | ) | $ | (161 | ) | $ | (2 | ) | $ | - | $ | (247 | ) | $ | (32 | ) | $ | (36 | ) | $ | (11 | ) | $ | - | $ | (79 | ) | |||||||||||
UE: | |||||||||||||||||||||||||||||||||||||||
Level 1 | $ | (3 | ) | $ | (4 | ) | $ | (2 | ) | $ | - | $ | (9 | ) | |||||||||||||||||||||||||
Level 2(a) | - | - | - | - | - | ||||||||||||||||||||||||||||||||||
Level 3(b) | 14 | 7 | (1 | ) | - | 20 | |||||||||||||||||||||||||||||||||
Total | $ | 11 | $ | 3 | $ | (3 | ) | $ | - | $ | 11 | ||||||||||||||||||||||||||||
AIC: | |||||||||||||||||||||||||||||||||||||||
Level 1 | $ | (4 | ) | $ | (3 | ) | $ | - | $ | - | $ | (7 | ) | ||||||||||||||||||||||||||
Level 2(a) | - | - | - | - | - | ||||||||||||||||||||||||||||||||||
Level 3(b) | (247 | ) | (230 | ) | (9 | ) | - | (486 | ) | ||||||||||||||||||||||||||||||
Total | $ | (251 | ) | $ | (233 | ) | $ | (9 | ) | $ | - | $ | (493 | ) | |||||||||||||||||||||||||
Genco: | |||||||||||||||||||||||||||||||||||||||
Level 1 | $ | (1 | ) | $ | - | $ | - | $ | - | $ | (1 | ) | |||||||||||||||||||||||||||
Level 2(a) | - | - | - | - | - | ||||||||||||||||||||||||||||||||||
Level 3(b) | 13 | 7 | - | - | 20 | ||||||||||||||||||||||||||||||||||
Total | $ | 12 | $ | 7 | $ | - | $ | - | $ | 19 | |||||||||||||||||||||||||||||
| (a) | Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed price vs. floating over-the-counter natural gas swaps. |
| (b) | Principally power forward contract values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes option contract values based on our estimates. |
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 20092010 and 2008,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) presentspresent fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2010, based on criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 201024, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Union Electric Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in
conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 24, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Illinois Company and its subsidiaries at December 31, 20092010 and 2008,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 201024, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Central Illinois Public Service Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Ameren Energy Generating Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Energy Generating Company and its subsidiaries at December 31, 20092010 and 2008,2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Central Illinois Light Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Light Company and its subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Illinois Power Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Illinois Power Company and its subsidiary at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 201024, 2011
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share amounts)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Operating Revenues: | |||||||||||||||||||||
Electric | $ | 5,909 | $ | 6,367 | $ | 6,283 | $ | 6,521 | $ | 5,940 | $ | 6,387 | |||||||||
Gas | 1,181 | 1,472 | 1,279 | 1,117 | 1,195 | 1,482 | |||||||||||||||
Total operating revenues | 7,090 | 7,839 | 7,562 | 7,638 | 7,135 | 7,869 | |||||||||||||||
Operating Expenses: | |||||||||||||||||||||
Fuel | 1,141 | 1,275 | 1,167 | 1,323 | 1,141 | 1,275 | |||||||||||||||
Purchased power | 909 | 1,210 | 1,387 | 1,106 | 909 | 1,210 | |||||||||||||||
Gas purchased for resale | 749 | 1,057 | 900 | 669 | 749 | 1,057 | |||||||||||||||
Other operations and maintenance | 1,738 | 1,857 | 1,687 | 1,821 | 1,768 | 1,862 | |||||||||||||||
Goodwill and other impairment losses | 589 | 7 | 14 | ||||||||||||||||||
Depreciation and amortization | 725 | 685 | 681 | 765 | 725 | 685 | |||||||||||||||
Taxes other than income taxes | 412 | 393 | 381 | 449 | 420 | 404 | |||||||||||||||
Total operating expenses | 5,674 | 6,477 | 6,203 | 6,722 | 5,719 | 6,507 | |||||||||||||||
Operating Income | 1,416 | 1,362 | 1,359 | 916 | 1,416 | 1,362 | |||||||||||||||
Other Income and Expenses: | |||||||||||||||||||||
Miscellaneous income | 71 | 80 | 75 | 90 | 71 | 80 | |||||||||||||||
Miscellaneous expense | (23) | (31) | (25) | 33 | 23 | 31 | |||||||||||||||
Total other income | 48 | 49 | 50 | 57 | 48 | 49 | |||||||||||||||
Interest Charges | 508 | 440 | 423 | 497 | 508 | 440 | |||||||||||||||
Income Before Income Taxes | 956 | 971 | 986 | 476 | 956 | 971 | |||||||||||||||
Income Taxes | 332 | 327 | 330 | 325 | 332 | 327 | |||||||||||||||
Net Income | 624 | 644 | 656 | 151 | 624 | 644 | |||||||||||||||
Less: Net Income Attributable to Noncontrolling Interests | 12 | 39 | 38 | 12 | 12 | 39 | |||||||||||||||
Net Income Attributable to Ameren Corporation | $ | 612 | $ | 605 | $ | 618 | $ | 139 | $ | 612 | $ | 605 | |||||||||
Earnings per Common Share – Basic and Diluted | $ | 2.78 | $ | 2.88 | $ | 2.98 | $ | 0.58 | $ | 2.78 | $ | 2.88 | |||||||||
Dividends per Common Share | $ | 1.54 | $ | 2.54 | $ | 2.54 | $ | 1.54 | $ | 1.54 | $ | 2.54 | |||||||||
Average Common Shares Outstanding | 220.4 | 210.1 | 207.4 | 238.8 | 220.4 | 210.1 | |||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
| December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009 | |||||||||||
| ASSETS | ||||||||||||||
Current Assets: | ||||||||||||||
Cash and cash equivalents | $ | 622 | $ | 92 | $ | 545 | $ | 622 | ||||||
Accounts receivable – trade (less allowance for doubtful accounts of $24 and $28, respectively) | 434 | 516 | ||||||||||||
Accounts receivable – trade (less allowance for doubtful accounts of $23 and $24, respectively) | 500 | 424 | ||||||||||||
Unbilled revenue | 367 | 427 | 406 | 367 | ||||||||||
Miscellaneous accounts and notes receivable | 308 | 315 | 231 | 318 | ||||||||||
Materials and supplies | 782 | 842 | 707 | 782 | ||||||||||
Mark-to-market derivative assets | 121 | 207 | 129 | 121 | ||||||||||
Current regulatory assets | 267 | 110 | ||||||||||||
Other current assets | 208 | 209 | 109 | 98 | ||||||||||
Total current assets | 2,842 | 2,608 | 2,894 | 2,842 | ||||||||||
Property and Plant, Net | 17,610 | 16,567 | 17,853 | 17,610 | ||||||||||
Investments and Other Assets: | ||||||||||||||
Nuclear decommissioning trust fund | 293 | 239 | 337 | 293 | ||||||||||
Goodwill | 831 | 831 | 411 | 831 | ||||||||||
Intangible assets | 129 | 167 | 7 | 129 | ||||||||||
Regulatory assets | 1,430 | 1,653 | 1,259 | 1,342 | ||||||||||
Other assets | 655 | 606 | 754 | 655 | ||||||||||
Total investments and other assets | 3,338 | 3,496 | 2,768 | 3,250 | ||||||||||
TOTAL ASSETS | $ | 23,790 | $ | 22,671 | $ | 23,515 | $ | 23,702 | ||||||
| LIABILITIES AND EQUITY | ||||||||||||||
Current Liabilities: | ||||||||||||||
Current maturities of long-term debt | $ | 204 | $ | 380 | $ | 155 | $ | 204 | ||||||
Short-term debt | 20 | 1,174 | 269 | 20 | ||||||||||
Accounts and wages payable | 694 | 813 | 651 | 694 | ||||||||||
Taxes accrued | 54 | 54 | 63 | 54 | ||||||||||
Interest accrued | 110 | 107 | 107 | 110 | ||||||||||
Customer deposits | 101 | 126 | 100 | 101 | ||||||||||
Mark-to-market derivative liabilities | 109 | 155 | 161 | 109 | ||||||||||
Current regulatory liabilities | 99 | 82 | ||||||||||||
Other current liabilities | 419 | 268 | 283 | 337 | ||||||||||
Total current liabilities | 1,711 | 3,077 | 1,888 | 1,711 | ||||||||||
Credit Facility Borrowings | 830 | - | 460 | 830 | ||||||||||
Long-term Debt, Net | 7,113 | 6,554 | 6,853 | 7,111 | ||||||||||
Deferred Credits and Other Liabilities: | ||||||||||||||
Accumulated deferred income taxes, net | 2,554 | 2,131 | 2,886 | 2,554 | ||||||||||
Accumulated deferred investment tax credits | 94 | 100 | 90 | 94 | ||||||||||
Regulatory liabilities | 1,338 | 1,291 | 1,319 | 1,257 | ||||||||||
Asset retirement obligations | 429 | 406 | 475 | 429 | ||||||||||
Pension and other postretirement benefits | 1,165 | 1,495 | 1,045 | 1,165 | ||||||||||
Other deferred credits and liabilities | 496 | 438 | 615 | 491 | ||||||||||
Total deferred credits and other liabilities | 6,076 | 5,861 | 6,430 | 5,990 | ||||||||||
Commitments and Contingencies (Notes 2, 14, 15 and 16) | ||||||||||||||
Commitments and Contingencies (Notes 2, 10, 14 and 15) | ||||||||||||||
Ameren Corporation Stockholders’ Equity: | ||||||||||||||
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 237.4 and 212.3, respectively | 2 | 2 | ||||||||||||
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 240.4 and 237.4, respectively | 2 | 2 | ||||||||||||
Other paid-in capital, principally premium on common stock | 5,412 | 4,780 | 5,520 | 5,412 | ||||||||||
Retained earnings | 2,455 | 2,181 | 2,225 | 2,455 | ||||||||||
Accumulated other comprehensive loss | (16) | - | (17) | (13) | ||||||||||
Total Ameren Corporation stockholders’ equity | 7,853 | 6,963 | 7,730 | 7,856 | ||||||||||
Noncontrolling Interests | 207 | 216 | 154 | 204 | ||||||||||
Total equity | 8,060 | 7,179 | 7,884 | 8,060 | ||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 23,790 | $ | 22,671 | $ | 23,515 | $ | 23,702 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||
Cash Flows From Operating Activities: | ||||||||||||||||||
Net income | $ 624 | $ 644 | $ 656 | $ | 151 | $ | 624 | $ | 644 | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||||
Gain on sales of emission allowances | (6) | (8) | (8) | |||||||||||||||
Loss on asset impairments | 7 | 14 | - | |||||||||||||||
Loss on goodwill and other impairments | 589 | 7 | 14 | |||||||||||||||
Net mark-to-market gain on derivatives | (23) | (3) | (3) | (15) | (23) | (3) | ||||||||||||
Depreciation and amortization | 748 | 705 | 735 | 783 | 748 | 705 | ||||||||||||
Amortization of nuclear fuel | 53 | 37 | 37 | 54 | 53 | 37 | ||||||||||||
Amortization of debt issuance costs and premium/discounts | 25 | 20 | 19 | 23 | 25 | 20 | ||||||||||||
Deferred income taxes and investment tax credits, net | 402 | 167 | (28) | 302 | 402 | 167 | ||||||||||||
Allowance for equity funds used during construction | (52) | (36) | (28) | |||||||||||||||
Other | (17) | (9) | 9 | 40 | 17 | 14 | ||||||||||||
Changes in assets and liabilities: | ||||||||||||||||||
Receivables | 21 | 12 | (172) | (85) | 21 | 12 | ||||||||||||
Materials and supplies | 67 | (100) | (88) | 78 | 67 | (100) | ||||||||||||
Accounts and wages payable | (42) | 57 | - | 27 | (42) | 57 | ||||||||||||
Taxes accrued | - | (30) | 21 | 9 | - | (30) | ||||||||||||
Assets, other | (66) | 83 | 42 | (109) | (66) | 83 | ||||||||||||
Liabilities, other | 103 | 113 | (44) | 71 | 99 | 110 | ||||||||||||
Pension and other postretirement benefits | (9) | (4) | 27 | (5) | (9) | (4) | ||||||||||||
Counterparty collateral, net | (17) | (25) | (39) | (73) | (17) | (25) | ||||||||||||
Taum Sauk costs, net of insurance recoveries | 107 | (149) | (56) | |||||||||||||||
Taum Sauk insurance recoveries, net of costs | 54 | 107 | (149) | |||||||||||||||
Net cash provided by operating activities | 1,977 | 1,524 | 1,108 | 1,842 | 1,977 | 1,524 | ||||||||||||
Cash Flows From Investing Activities: | ||||||||||||||||||
Capital expenditures | (1,704) | (1,896) | (1,381) | (1,031) | (1,704) | (1,896) | ||||||||||||
Nuclear fuel expenditures | (80) | (173) | (68) | (90) | (80) | (173) | ||||||||||||
Purchases of securities – nuclear decommissioning trust fund | (383) | (520) | (142) | (271) | (383) | (520) | ||||||||||||
Sales of securities – nuclear decommissioning trust fund | 380 | 497 | 128 | 256 | 380 | 497 | ||||||||||||
Purchases of emission allowances | (4) | (14) | (24) | |||||||||||||||
Sales of emission allowances | - | 6 | 5 | |||||||||||||||
Other | 2 | 3 | 14 | 24 | (2) | (5) | ||||||||||||
Net cash used in investing activities | (1,789) | (2,097) | (1,468) | (1,112) | (1,789) | (2,097) | ||||||||||||
Cash Flows From Financing Activities: | ||||||||||||||||||
Dividends on common stock | (338) | (534) | (527) | (368) | (338) | (534) | ||||||||||||
Dividends paid to noncontrolling interest holders | (8) | (21) | (40) | |||||||||||||||
Capital issuance costs | (65) | (12) | (4) | (15) | (65) | (12) | ||||||||||||
Short-term and credit facility borrowings, net | (324) | (298) | 860 | (121) | (324) | (298) | ||||||||||||
Dividends paid to noncontrolling interest holders | (21) | (40) | (32) | |||||||||||||||
Redemptions, repurchases, and maturities: | ||||||||||||||||||
Long-term debt | (631) | (842) | (488) | (310) | (631) | (842) | ||||||||||||
Preferred stock | - | (16) | (1) | (52) | - | (16) | ||||||||||||
Issuances: | ||||||||||||||||||
Common stock | 634 | 154 | 91 | 80 | 634 | 154 | ||||||||||||
Long-term debt | 1,021 | 1,879 | 674 | - | 1,021 | 1,879 | ||||||||||||
Generator advances received for construction, net | 66 | 19 | 5 | |||||||||||||||
Generator advances received for construction, net of repayments | (13) | 66 | 19 | |||||||||||||||
Net cash provided by financing activities | 342 | 310 | 578 | |||||||||||||||
Net cash provided by (used in) financing activities | (807) | 342 | 310 | |||||||||||||||
Net change in cash and cash equivalents | 530 | (263) | 218 | (77) | 530 | (263) | ||||||||||||
Cash and cash equivalents at beginning of year | 92 | 355 | 137 | 622 | 92 | 355 | ||||||||||||
Cash and cash equivalents at end of year | $ 622 | $ 92 | $ 355 | $ | 545 | $ | 622 | $ | 92 | |||||||||
Cash Paid During the Year: | ||||||||||||||||||
Interest (net of $40, $41, and $31 capitalized, respectively) | $ 478 | $ 409 | $ 391 | |||||||||||||||
Cash Paid (Refunded) During the Year: | ||||||||||||||||||
Interest (net of $34, $40, and $41 capitalized, respectively) | $ | 494 | $ | 485 | $ | 409 | ||||||||||||
Income taxes, net | 9 | 106 | 283 | (92) | 9 | 106 | ||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Common Stock: | |||||||||||||||||||||
Beginning of year | $ | 2 | $ | 2 | $ | 2 | $ | 2 | $ | 2 | $ | 2 | |||||||||
Shares issued | - | - | - | - | - | - | |||||||||||||||
Common stock, end of year | 2 | 2 | 2 | 2 | 2 | 2 | |||||||||||||||
Other Paid-in Capital: | |||||||||||||||||||||
Beginning of year | 4,780 | 4,604 | 4,495 | 5,412 | 4,780 | 4,604 | |||||||||||||||
Shares issued (less issuance costs of $17, $-, and $-, respectively) | 617 | 154 | 91 | ||||||||||||||||||
Shares issued (less issuance costs of $-, $17, and $-, respectively) | 80 | 617 | 154 | ||||||||||||||||||
Stock-based compensation cost | 15 | 22 | 18 | 14 | 15 | 22 | |||||||||||||||
Regulatory recovery of prior-period common stock issuance costs | 14 | - | - | ||||||||||||||||||
Other paid-in capital, end of year | 5,412 | 4,780 | 4,604 | 5,520 | 5,412 | 4,780 | |||||||||||||||
Retained Earnings: | |||||||||||||||||||||
Beginning of year | 2,181 | 2,110 | 2,024 | 2,455 | 2,181 | 2,110 | |||||||||||||||
Net income attributable to Ameren Corporation | 612 | 605 | 618 | 139 | 612 | 605 | |||||||||||||||
Dividends | (338) | (534) | (527) | (368) | (338) | (534) | |||||||||||||||
Adjustment to adopt new accounting standard | - | - | (5) | ||||||||||||||||||
Other | (1) | - | - | ||||||||||||||||||
Retained earnings, end of year | 2,455 | 2,181 | 2,110 | 2,225 | 2,455 | 2,181 | |||||||||||||||
Accumulated Other Comprehensive Income (Loss): | |||||||||||||||||||||
Derivative financial instruments, beginning of year | 48 | 9 | 60 | 10 | 48 | 9 | |||||||||||||||
Change in derivative financial instruments | (38) | 39 | (51) | (10) | (38) | 39 | |||||||||||||||
Derivative financial instruments, end of year | 10 | 48 | 9 | - | 10 | 48 | |||||||||||||||
Deferred retirement benefit costs, beginning of year | (48) | 27 | 2 | (23) | (43) | 25 | |||||||||||||||
Change in deferred retirement benefit costs | 22 | (75) | 25 | 6 | 20 | (68) | |||||||||||||||
Deferred retirement benefit costs, end of year | (26) | (48) | 27 | (17) | (23) | (43) | |||||||||||||||
Total accumulated other comprehensive income (loss), end of year | (16) | - | 36 | (17) | (13) | 5 | |||||||||||||||
Total Ameren Corporation Stockholders’ Equity | $ | 7,853 | $ | 6,963 | $ | 6,752 | $ | 7,730 | $ | 7,856 | $ | 6,968 | |||||||||
Noncontrolling Interests: | |||||||||||||||||||||
Beginning of year | 216 | 217 | 211 | 204 | 211 | 218 | |||||||||||||||
Net income attributable to noncontrolling interests | 12 | 39 | 38 | ||||||||||||||||||
Net income attributable to noncontrolling interest holders | 12 | 12 | 39 | ||||||||||||||||||
Dividends paid to noncontrolling interest holders | (21) | (40) | (32) | (8) | (21) | (40) | |||||||||||||||
Redemptions of preferred stock | (52) | - | - | ||||||||||||||||||
Other | (2) | 2 | (6) | ||||||||||||||||||
Noncontrolling interests, end of year | 207 | 216 | 217 | 154 | 204 | 211 | |||||||||||||||
Total Equity | $ | 8,060 | $ | 7,179 | $ | 6,969 | $ | 7,884 | $ | 8,060 | $ | 7,179 | |||||||||
Comprehensive Income, Net of Taxes: | |||||||||||||||||||||
Net income | $ | 624 | $ | 644 | $ | 656 | $ | 151 | $ | 624 | $ | 644 | |||||||||
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $78, $65, and $(7), respectively | 103 | 116 | (12) | ||||||||||||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $82, $43, and $22, respectively | (112) | (77) | (39) | ||||||||||||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $18, $-, and $-, respectively | (29) | - | - | ||||||||||||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $22, $(45), and $1, respectively | 22 | (75) | 25 | ||||||||||||||||||
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $(1), $78, and $65, respectively | (2) | 103 | 116 | ||||||||||||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $5, $82, and $43, respectively | (8) | (112) | (77) | ||||||||||||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $-, $18, and $-, respectively | - | (29) | - | ||||||||||||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $6, $22, and $(45), respectively | 4 | 22 | (75) | ||||||||||||||||||
Total Comprehensive Income, Net of Taxes | $ | 608 | $ | 608 | $ | 630 | $ | 145 | $ | 608 | $ | 608 | |||||||||
Comprehensive income attributable to noncontrolling interests | (12) | (39) | (38) | 10 | 14 | 33 | |||||||||||||||
Total Comprehensive Income Attributable to Ameren Corporation, Net of Taxes | $ | 596 | $ | 569 | $ | 592 | $ | 135 | $ | 594 | $ | 575 | |||||||||
|
| ||||||||||||||||||||
Common stock shares at beginning of year | 212.3 | 208.3 | 206.6 | 237.4 | 212.3 | 208.3 | |||||||||||||||
Shares issued | 25.1 | 4.0 | 1.7 | 3.0 | 25.1 | 4.0 | |||||||||||||||
Common stock shares at end of year | 237.4 | 212.3 | 208.3 | 240.4 | 237.4 | 212.3 | |||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Operating Revenues: | |||||||||||||||||||||
Electric | $ | 2,700 | $ | 2,756 | $ | 2,786 | $ | 3,030 | $ | 2,700 | $ | 2,756 | |||||||||
Gas | 170 | 201 | 174 | 166 | 170 | 201 | |||||||||||||||
Other | 4 | 3 | 1 | 1 | 4 | 3 | |||||||||||||||
Total operating revenues | 2,874 | 2,960 | 2,961 | 3,197 | 2,874 | 2,960 | |||||||||||||||
Operating Expenses: | |||||||||||||||||||||
Fuel | 593 | 672 | 608 | 635 | 593 | 672 | |||||||||||||||
Purchased power | 124 | 160 | 192 | 162 | 124 | 160 | |||||||||||||||
Gas purchased for resale | 97 | 123 | 104 | 91 | 97 | 123 | |||||||||||||||
Other operations and maintenance | 880 | 922 | 900 | 931 | 880 | 922 | |||||||||||||||
Depreciation and amortization | 357 | 329 | 333 | 382 | 357 | 329 | |||||||||||||||
Taxes other than income taxes | 257 | 240 | 234 | 285 | 257 | 240 | |||||||||||||||
Total operating expenses | 2,308 | 2,446 | 2,371 | 2,486 | 2,308 | 2,446 | |||||||||||||||
Operating Income | 566 | 514 | 590 | 711 | 566 | 514 | |||||||||||||||
Other Income and Expenses: | |||||||||||||||||||||
Miscellaneous income | 63 | 62 | 38 | 83 | 63 | 62 | |||||||||||||||
Miscellaneous expense | (7) | (9) | (7) | 13 | 7 | 9 | |||||||||||||||
Total other income | 56 | 53 | 31 | 70 | 56 | 53 | |||||||||||||||
Interest Charges | 229 | 193 | 194 | 213 | 229 | 193 | |||||||||||||||
Income Before Income Taxes and Equity in Income of Unconsolidated Investment | 393 | 374 | 427 | 568 | 393 | 374 | |||||||||||||||
Income Taxes | 128 | 134 | 140 | 199 | 128 | 134 | |||||||||||||||
Income Before Equity in Income of Unconsolidated Investment | 265 | 240 | 287 | 369 | 265 | 240 | |||||||||||||||
Equity in Income of Unconsolidated Investment, Net of Taxes | - | 11 | 55 | - | - | 11 | |||||||||||||||
Net Income | 265 | 251 | 342 | 369 | 265 | 251 | |||||||||||||||
Preferred Stock Dividends | 6 | 6 | 6 | 5 | 6 | 6 | |||||||||||||||
Net Income Available to Common Stockholder | $ | 259 | $ | 245 | $ | 336 | $ | 364 | $ | 259 | $ | 245 | |||||||||
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
BALANCE SHEET
(In millions, except per share amounts)
| December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009 | |||||||||||
| ASSETS | ||||||||||||||
Current Assets: | ||||||||||||||
Cash and cash equivalents | $ | 267 | $ | - | $ | 202 | $ | 267 | ||||||
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $8, respectively) | 154 | 147 | ||||||||||||
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $6, respectively) | 217 | 154 | �� | |||||||||||
Accounts receivable – affiliates | 22 | 32 | 6 | 22 | ||||||||||
Unbilled revenue | 127 | 111 | 159 | 127 | ||||||||||
Miscellaneous accounts and notes receivable | 199 | 281 | 116 | 199 | ||||||||||
Materials and supplies | 346 | 339 | 341 | 346 | ||||||||||
Mark-to-market derivative assets | 31 | 50 | ||||||||||||
Current regulatory assets | 63 | 10 | 179 | 63 | ||||||||||
Other current assets | 19 | 28 | 55 | 50 | ||||||||||
Total current assets | 1,228 | 998 | 1,275 | 1,228 | ||||||||||
Property and Plant, Net | 9,585 | 8,995 | 9,775 | 9,585 | ||||||||||
Investments and Other Assets: | ||||||||||||||
Nuclear decommissioning trust fund | 293 | 239 | 337 | 293 | ||||||||||
Intangible assets | 35 | 48 | 2 | 35 | ||||||||||
Regulatory assets | 765 | 897 | 694 | 683 | ||||||||||
Other assets | 395 | 352 | 421 | 395 | ||||||||||
Total investments and other assets | 1,488 | 1,536 | 1,454 | 1,406 | ||||||||||
TOTAL ASSETS | $ | 12,301 | $ | 11,529 | $ | 12,504 | $ | 12,219 | ||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||
Current Liabilities: | ||||||||||||||
Current maturities of long-term debt | $ | 4 | $ | 4 | $ | 5 | $ | 4 | ||||||
Short-term debt | - | 251 | ||||||||||||
Intercompany note payable – Ameren | - | 92 | ||||||||||||
Accounts and wages payable | 336 | 360 | 326 | 336 | ||||||||||
Accounts payable – affiliates | 132 | 151 | 75 | 132 | ||||||||||
Taxes accrued | 21 | 20 | 76 | 21 | ||||||||||
Interest accrued | 63 | 56 | 63 | 63 | ||||||||||
Current accumulated deferred income taxes, net | 43 | 12 | ||||||||||||
Other current liabilities | 127 | 126 | 112 | 115 | ||||||||||
Total current liabilities | 683 | 1,060 | 700 | 683 | ||||||||||
Long-term Debt, Net | 4,018 | 3,673 | 3,949 | 4,018 | ||||||||||
Deferred Credits and Other Liabilities: | ||||||||||||||
Accumulated deferred income taxes, net | 1,660 | 1,372 | 1,908 | 1,660 | ||||||||||
Accumulated deferred investment tax credits | 79 | 80 | 78 | 79 | ||||||||||
Regulatory liabilities | 947 | 922 | 766 | 865 | ||||||||||
Asset retirement obligations | 331 | 317 | 363 | 331 | ||||||||||
Pension and other postretirement benefits | 400 | 494 | 369 | 400 | ||||||||||
Other deferred credits and liabilities | 126 | 49 | 218 | 126 | ||||||||||
Total deferred credits and other liabilities | 3,543 | 3,234 | 3,702 | 3,461 | ||||||||||
Commitments and Contingencies (Notes 2, 14, 15 and 16) | ||||||||||||||
Commitments and Contingencies (Notes 2, 10, 14 and 15) | ||||||||||||||
Stockholders’ Equity: | ||||||||||||||
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | 511 | 511 | 511 | ||||||||||
Other paid-in capital, principally premium on common stock | 1,555 | 1,119 | 1,555 | 1,555 | ||||||||||
Preferred stock not subject to mandatory redemption | 113 | 113 | 80 | 113 | ||||||||||
Retained earnings | 1,878 | 1,794 | 2,007 | 1,878 | ||||||||||
Accumulated other comprehensive income | - | 25 | ||||||||||||
Total stockholders’ equity | 4,057 | 3,562 | 4,153 | 4,057 | ||||||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 12,301 | $ | 11,529 | $ | 12,504 | $ | 12,219 | ||||||
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Cash Flows From Operating Activities: | |||||||||||||||||||||
Net income | $ | 265 | $ | 251 | $ | 342 | $ | 369 | $ | 265 | $ | 251 | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||||||
Gain on sales of emission allowances | (5) | (5) | (5) | ||||||||||||||||||
Net mark-to-market (gain) loss on derivatives | (29) | 29 | (2) | (1) | (29) | 29 | |||||||||||||||
Depreciation and amortization | 357 | 329 | 333 | 382 | 357 | 329 | |||||||||||||||
Amortization of nuclear fuel | 53 | 37 | 37 | 54 | 53 | 37 | |||||||||||||||
Amortization of debt issuance costs and premium/discounts | 10 | 6 | 6 | 4 | 10 | 6 | |||||||||||||||
Deferred income taxes and investment tax credits, net | 276 | 89 | 1 | 228 | 276 | 89 | |||||||||||||||
Allowance for equity funds used during construction | (50) | (33) | (27) | ||||||||||||||||||
Other | (30) | (28) | (6) | 20 | - | (5) | |||||||||||||||
Changes in assets and liabilities: | |||||||||||||||||||||
Receivables | (58) | 60 | (60) | (56) | (58) | 60 | |||||||||||||||
Materials and supplies | (2) | (32) | (65) | 7 | (2) | (32) | |||||||||||||||
Accounts and wages payable | 16 | (89) | 42 | (17) | 16 | (89) | |||||||||||||||
Taxes accrued | 1 | (61) | 12 | 55 | 1 | (61) | |||||||||||||||
Assets, other | (58) | 42 | 39 | (145) | (58) | 42 | |||||||||||||||
Liabilities, other | 71 | 64 | (49) | 77 | 69 | 63 | |||||||||||||||
Pension and other postretirement benefits | (2) | - | 18 | (3) | (2) | - | |||||||||||||||
Taum Sauk costs, net of insurance recoveries | 107 | (149) | (56) | ||||||||||||||||||
Taum Sauk insurance recoveries, net of costs | 54 | 107 | (149) | ||||||||||||||||||
Net cash provided by operating activities | 972 | 543 | 587 | 978 | 972 | 543 | |||||||||||||||
Cash Flows From Investing Activities: | |||||||||||||||||||||
Capital expenditures | (872) | (874) | (625) | (608) | (872) | (874) | |||||||||||||||
Nuclear fuel expenditures | (80) | (173) | (68) | (90) | (80) | (173) | |||||||||||||||
Money pool advances, net | - | - | 3 | ||||||||||||||||||
Proceeds from intercompany note receivable | - | 36 | - | - | - | 36 | |||||||||||||||
Purchases of securities – nuclear decommissioning trust fund | (383) | (520) | (142) | (271) | (383) | (520) | |||||||||||||||
Sales of securities – nuclear decommissioning trust fund | 380 | 497 | 128 | 256 | 380 | 497 | |||||||||||||||
Sales of emission allowances | - | 1 | 4 | ||||||||||||||||||
Other | 7 | - | 1 | ||||||||||||||||||
Net cash used in investing activities | (955) | (1,033) | (700) | (706) | (955) | (1,033) | |||||||||||||||
Cash Flows From Financing Activities: | |||||||||||||||||||||
Dividends on common stock | (175) | (264) | (267) | (235) | (175) | (264) | |||||||||||||||
Dividends on preferred stock | (6) | (6) | (6) | (5) | (6) | (6) | |||||||||||||||
Capital issuance costs | (14) | (5) | (3) | (4) | (14) | (5) | |||||||||||||||
Short-term debt, net | (251) | 169 | (152) | - | (251) | 169 | |||||||||||||||
Intercompany note payable – Ameren, net | (92) | 92 | (77) | - | (92) | 92 | |||||||||||||||
Redemptions, repurchases, and maturities of long-term debt | (4) | (382) | (4) | ||||||||||||||||||
Redemptions, repurchases, and maturities: | |||||||||||||||||||||
Long-term debt | (70) | (4) | (382) | ||||||||||||||||||
Preferred stock | (33) | - | - | ||||||||||||||||||
Issuances of long-term debt | 349 | 699 | 424 | - | 349 | 699 | |||||||||||||||
Capital contribution from parent | 436 | - | 380 | - | 436 | - | |||||||||||||||
Other | 7 | 2 | 2 | 10 | 7 | 2 | |||||||||||||||
Net cash provided by financing activities | 250 | 305 | 297 | ||||||||||||||||||
Net cash provided by (used in) financing activities | (337) | 250 | 305 | ||||||||||||||||||
Net change in cash and cash equivalents | 267 | (185) | 184 | (65) | 267 | (185) | |||||||||||||||
Cash and cash equivalents at beginning of year | - | 185 | 1 | 267 | - | 185 | |||||||||||||||
Cash and cash equivalents at end of year | $ | 267 | $ | - | $ | 185 | $ | 202 | $ | 267 | $ | - | |||||||||
Cash Paid (Refunded) During the Year: | |||||||||||||||||||||
Interest (net of $23, $19, and $15 capitalized, respectively) | $ | 212 | $ | 177 | $ | 203 | |||||||||||||||
Interest (net of $26, $23, and $19 capitalized, respectively) | $ | 213 | $ | 212 | $ | 177 | |||||||||||||||
Income taxes, net | (208) | 130 | 106 | (106) | (208) | 130 | |||||||||||||||
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | ||||||||||||||||
Common Stock | $ | 511 | $ | 511 | $ | 511 | $ | 511 | $ | 511 | $ | 511 | |||||||||
Other Paid-in Capital: | |||||||||||||||||||||
Beginning of year | 1,119 | 1,119 | 739 | 1,555 | 1,119 | 1,119 | |||||||||||||||
Capital contribution from parent | 436 | - | 380 | - | 436 | - | |||||||||||||||
Other paid-in capital, end of year | 1,555 | 1,119 | 1,119 | 1,555 | 1,555 | 1,119 | |||||||||||||||
Preferred Stock Not Subject to Mandatory Redemption | 113 | 113 | 113 | ||||||||||||||||||
Preferred Stock Not Subject to Mandatory Redemption: | |||||||||||||||||||||
Beginning balance | 113 | 113 | 113 | ||||||||||||||||||
Redemptions | (33) | - | - | ||||||||||||||||||
Preferred stock not subject to mandatory redemption, end of year | 80 | 113 | 113 | ||||||||||||||||||
Retained Earnings: | |||||||||||||||||||||
Beginning of year | 1,794 | 1,855 | 1,783 | 1,878 | 1,794 | 1,855 | |||||||||||||||
Net income | 265 | 251 | 342 | 369 | 265 | 251 | |||||||||||||||
Common stock dividends | (175) | (264) | (267) | (235) | (175) | (264) | |||||||||||||||
Preferred stock dividends | (6) | (6) | (6) | (5) | (6) | (6) | |||||||||||||||
Dividend-in-kind to Ameren | - | (42) | - | - | - | (42) | |||||||||||||||
Adjustment to adopt new accounting standard | - | - | 3 | ||||||||||||||||||
Retained earnings, end of year | 1,878 | 1,794 | 1,855 | 2,007 | 1,878 | 1,794 | |||||||||||||||
Accumulated Other Comprehensive Income: | |||||||||||||||||||||
Beginning of year | 25 | 3 | 7 | - | 25 | 3 | |||||||||||||||
Change in derivative financial instruments | (25) | 22 | (4) | - | (25) | 22 | |||||||||||||||
Accumulated other comprehensive income, end of year | - | 25 | 3 | - | - | 25 | |||||||||||||||
Total Stockholders’ Equity | $ | 4,057 | $ | 3,562 | $ | 3,601 | $ | 4,153 | $ | 4,057 | $ | 3,562 | |||||||||
Comprehensive Income, Net of Taxes: | |||||||||||||||||||||
Net income | $ | 265 | $ | 251 | $ | 342 | $ | 369 | $ | 265 | $ | 251 | |||||||||
Unrealized net gain on derivative hedging instruments, net of income taxes of $11, $22, and $-, respectively | 17 | 36 | - | ||||||||||||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $8, $9, and $2, respectively | (13) | (14) | (4) | ||||||||||||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $18, $-, and $-, respectively | (29) | - | - | ||||||||||||||||||
Unrealized net gain on derivative hedging instruments, net of income taxes of $-, $11, and $22, respectively | - | 17 | 36 | ||||||||||||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $-, $8, and $9, respectively | - | (13) | (14) | ||||||||||||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $-, $18, and $-, respectively | - | (29) | - | ||||||||||||||||||
Total Comprehensive Income, Net of Taxes | $ | 240 | $ | 273 | $ | 338 | $ | 369 | $ | 240 | $ | 273 | |||||||||
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
CENTRALAMEREN ILLINOIS PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009(a) | 2008(a) | ||||||||||||||||
Operating Revenues: | |||||||||||||||||||||
Electric | $ | 642 | $ | 720 | $ | 772 | $ | 2,061 | $ | 1,965 | $ | 2,242 | |||||||||
Gas | 224 | 259 | 230 | 953 | 1,015 | 1,265 | |||||||||||||||
Other | 3 | 3 | 3 | - | 4 | 1 | |||||||||||||||
Total operating revenues | 869 | 982 | 1,005 | 3,014 | 2,984 | 3,508 | |||||||||||||||
Operating Expenses: | |||||||||||||||||||||
Purchased power | 372 | 461 | 527 | 965 | 1,048 | 1,405 | |||||||||||||||
Gas purchased for resale | 143 | 179 | 157 | 578 | 642 | 914 | |||||||||||||||
Other operations and maintenance | 181 | 196 | 172 | 635 | 590 | 653 | |||||||||||||||
Depreciation and amortization | 68 | 67 | 66 | 210 | 216 | 219 | |||||||||||||||
Taxes other than income taxes | 37 | 37 | 34 | 128 | 125 | 126 | |||||||||||||||
Total operating expenses | 801 | 940 | 956 | 2,516 | 2,621 | 3,317 | |||||||||||||||
Operating Income | 68 | 42 | 49 | 498 | 363 | 191 | |||||||||||||||
Other Income and Expenses: | |||||||||||||||||||||
Miscellaneous income | 8 | 11 | 17 | 7 | 12 | 23 | |||||||||||||||
Miscellaneous expense | (2) | (3) | (3) | 13 | 10 | 12 | |||||||||||||||
Total other income | 6 | 8 | 14 | ||||||||||||||||||
Total other income (expense) | (6) | 2 | 11 | ||||||||||||||||||
Interest Charges | 29 | 30 | 37 | 143 | 153 | 145 | |||||||||||||||
Income Before Income Taxes | 45 | 20 | 26 | 349 | 212 | 57 | |||||||||||||||
Income Taxes | 16 | 5 | 9 | 137 | 79 | 16 | |||||||||||||||
Income from Continuing Operations | 212 | 133 | 41 | ||||||||||||||||||
Income from Discontinued Operations, net of tax | 40 | 114 | 52 | ||||||||||||||||||
Net Income | 29 | 15 | 17 | 252 | 247 | 93 | |||||||||||||||
Preferred Stock Dividends | 3 | 3 | 3 | 4 | 6 | 6 | |||||||||||||||
Net Income Available to Common Stockholder | $ | 26 | $ | 12 | $ | 14 | $ | 248 | $ | 241 | $ | 87 | |||||||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to CIPSAIC are an integral part of these consolidated financial statements.
CENTRALAMEREN ILLINOIS PUBLIC SERVICE COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
| December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009(a) | |||||||||||
ASSETS | ||||||||||||||
Current Assets: | ||||||||||||||
Cash and cash equivalents | $ | 28 | $ | - | $ | 322 | $ | 306 | ||||||
Accounts receivable – trade (less allowance for doubtful accounts of $5 and $6, respectively) | 53 | 82 | ||||||||||||
Accounts receivable – affiliates | 12 | 4 | ||||||||||||
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $17, respectively) | 230 | 199 | ||||||||||||
Accounts and notes receivable – affiliates | 73 | 105 | ||||||||||||
Unbilled revenue | 52 | 74 | 205 | 189 | ||||||||||
Miscellaneous accounts and notes receivable | 14 | 1 | 44 | 51 | ||||||||||
Current portion of intercompany note receivable – Genco | 45 | 42 | ||||||||||||
Current portion of intercompany tax receivable – Genco | 9 | 9 | ||||||||||||
Materials and supplies | 47 | 70 | 198 | 212 | ||||||||||
Counterparty collateral asset | 2 | 21 | ||||||||||||
Current regulatory assets | 59 | 32 | 260 | 174 | ||||||||||
Deferred taxes | 18 | 5 | ||||||||||||
Other current assets | 3 | 2 | 106 | 63 | ||||||||||
Current assets of discontinued operations | - | 112 | ||||||||||||
Total current assets | 342 | 342 | 1,438 | 1,411 | ||||||||||
Property and Plant, Net | 1,268 | 1,212 | 4,576 | 4,354 | ||||||||||
Investments and Other Assets: | ||||||||||||||
Intercompany note receivable – Genco | - | 45 | ||||||||||||
Intercompany tax receivable – Genco | 82 | 93 | 72 | 82 | ||||||||||
Goodwill | 411 | 411 | ||||||||||||
Regulatory assets | 248 | 195 | 743 | 944 | ||||||||||
Other assets | 25 | 33 | 166 | 91 | ||||||||||
Noncurrent assets of discontinued operations | - | 1,005 | ||||||||||||
Total investments and other assets | 355 | 366 | 1,392 | 2,533 | ||||||||||
TOTAL ASSETS | $ | 1,965 | $ | 1,920 | $ | 7,406 | $ | 8,298 | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||
Current Liabilities: | ||||||||||||||
Short-term debt | $ | - | $ | 62 | ||||||||||
Borrowings from money pool | - | 44 | ||||||||||||
Current maturities of long-term debt | $ | 150 | $ | - | ||||||||||
Accounts and wages payable | 48 | 48 | 182 | 192 | ||||||||||
Accounts payable – affiliates | 58 | 49 | 82 | 179 | ||||||||||
Taxes accrued | 7 | 7 | 26 | 15 | ||||||||||
Customer deposits | 21 | 16 | 83 | 85 | ||||||||||
Mark-to-market derivative liabilities | 10 | 17 | 82 | 38 | ||||||||||
Mark-to-market derivative liabilities – affiliates | 43 | 14 | 172 | 127 | ||||||||||
Environmental remediation | 22 | 7 | 72 | 80 | ||||||||||
Current regulatory liabilities | 76 | 57 | ||||||||||||
Other current liabilities | 45 | 47 | 90 | 132 | ||||||||||
Current liabilities of discontinued operations | - | 334 | ||||||||||||
Total current liabilities | 254 | 311 | 1,015 | 1,239 | ||||||||||
Long-term Debt, Net | 421 | 421 | 1,657 | 1,847 | ||||||||||
Deferred Credits and Other Liabilities: | ||||||||||||||
Accumulated deferred income taxes | 273 | 259 | ||||||||||||
Accumulated deferred income taxes, net | 724 | 554 | ||||||||||||
Accumulated deferred investment tax credits | 7 | 9 | 8 | 10 | ||||||||||
Regulatory liabilities | 242 | 234 | 553 | 391 | ||||||||||
Pension and other postretirement benefits | 58 | 79 | 413 | 471 | ||||||||||
Other deferred credits and liabilities | 136 | 78 | 460 | 483 | ||||||||||
Noncurrent liabilities of discontinued operations | - | 231 | ||||||||||||
Total deferred credits and other liabilities | 716 | 659 | 2,158 | 2,140 | ||||||||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||||||||||
Stockholders’ Equity: | ||||||||||||||
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | - | - | - | - | ||||||||||
Other paid-in capital | 257 | 191 | 1,952 | 2,223 | ||||||||||
Preferred stock not subject to mandatory redemption | 50 | 50 | 62 | 115 | ||||||||||
Retained earnings | 267 | 288 | 542 | 709 | ||||||||||
Accumulated other comprehensive income | 20 | 25 | ||||||||||||
Total stockholders’ equity | 574 | 529 | 2,576 | 3,072 | ||||||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 1,965 | $ | 1,920 | $ | 7,406 | $ | 8,298 | ||||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to CIPSAIC are an integral part of these consolidated financial statements.
CENTRALAMEREN ILLINOIS PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009(a) | 2008(a) | ||||||||||||||||
Cash Flows From Operating Activities: | |||||||||||||||||||||
Net income | $ | 29 | $ | 15 | $ | 17 | $ | 252 | $ | 247 | $ | 93 | |||||||||
Income from discontinued operations, net of tax | (40) | (114) | (52) | ||||||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||||||
Depreciation and amortization | 68 | 67 | 66 | 210 | 212 | 209 | |||||||||||||||
Amortization of debt issuance costs and premium/discounts | 2 | 1 | 1 | 10 | 9 | 11 | |||||||||||||||
Deferred income taxes and investment tax credits, net | (5) | (2) | (27) | 161 | 72 | 22 | |||||||||||||||
Other | 2 | (11) | 6 | ||||||||||||||||||
Changes in assets and liabilities: | |||||||||||||||||||||
Receivables | 41 | (5) | (12) | (41) | 142 | (25) | |||||||||||||||
Materials and supplies | 23 | (4) | 5 | 14 | 85 | (37) | |||||||||||||||
Accounts and wages payable | 15 | 14 | (48) | (44) | (3) | 74 | |||||||||||||||
Taxes accrued | - | (1) | (2) | 11 | (11) | 11 | |||||||||||||||
Assets, other | 19 | (5) | 14 | (76) | 74 | (35) | |||||||||||||||
Liabilities, other | (1) | 21 | (3) | 32 | 11 | 72 | |||||||||||||||
Pension and other postretirement benefits | - | - | 3 | (7) | 5 | (20) | |||||||||||||||
Operating cash flows provided by discontinued operations | 113 | 141 | 159 | ||||||||||||||||||
Net cash provided by operating activities | 191 | 101 | 14 | 597 | 859 | 488 | |||||||||||||||
Cash Flows From Investing Activities: | |||||||||||||||||||||
Capital expenditures | (110) | (96) | (79) | (286) | (356) | (345) | |||||||||||||||
Advances to ATXI for construction | (10) | (47) | (13) | ||||||||||||||||||
Proceeds from intercompany note receivable – Genco | 42 | 39 | 37 | 45 | 42 | 39 | |||||||||||||||
Other | - | - | (2) | ||||||||||||||||||
Capital expenditures of discontinued operations | (6) | (91) | (256) | ||||||||||||||||||
Net cash used in investing activities | (68) | (57) | (42) | (257) | (452) | (577) | |||||||||||||||
Cash Flows From Financing Activities: | |||||||||||||||||||||
Dividends on common stock | (47) | - | (40) | (133) | (98) | (60) | |||||||||||||||
Dividends on preferred stock | (3) | (3) | (3) | (4) | (6) | (6) | |||||||||||||||
Capital issuance costs | (3) | - | - | (4) | (13) | (6) | |||||||||||||||
Short-term debt, net | (62) | (63) | 90 | ||||||||||||||||||
Money pool borrowings, net | (44) | 44 | - | ||||||||||||||||||
Redemptions, repurchases, and maturities of long-term debt | - | (50) | - | ||||||||||||||||||
Short-term and credit facility borrowings, net | - | (62) | (353) | ||||||||||||||||||
Redemptions, repurchases, and maturities: | |||||||||||||||||||||
Long-term debt | (40) | (250) | (460) | ||||||||||||||||||
Preferred stock | (19) | - | (16) | ||||||||||||||||||
Issuances of long-term debt | - | - | 880 | ||||||||||||||||||
Generator advances for construction received (refunded), net of repayments | (23) | 56 | 20 | ||||||||||||||||||
Capital contribution from parent | 66 | - | 1 | 6 | 272 | - | |||||||||||||||
Other | (2) | 2 | - | ||||||||||||||||||
Net financing activities provided by (used in) discontinued operations | (107) | (50) | 104 | ||||||||||||||||||
Net cash provided by (used in) financing activities | (95) | (70) | 48 | (324) | (151) | 103 | |||||||||||||||
Net change in cash and cash equivalents | 28 | (26) | 20 | 16 | 256 | 14 | |||||||||||||||
Cash and cash equivalents at beginning of year | - | 26 | 6 | 306 | 50 | 36 | |||||||||||||||
Cash and cash equivalents at end of year | $ | 28 | $ | - | $ | 26 | $ | 322 | $ | 306 | $ | 50 | |||||||||
Cash Paid (Refunded) During the Year: | |||||||||||||||||||||
Interest | $ | 27 | $ | 32 | $ | 36 | |||||||||||||||
Interest (net of $1, $3 and $10 capitalized, respectively) | $ | 160 | $ | 167 | $ | 131 | |||||||||||||||
Income taxes, net | 24 | (21) | 44 | (39) | 129 | (80) | |||||||||||||||
Noncash investing activity – asset transfer from ATXI | 7 | 29 | - | ||||||||||||||||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to CIPSAIC are an integral part of these consolidated financial statements.
CENTRALAMEREN ILLINOIS PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009(a) | 2008(a) | ||||||||||||||||
Common Stock | $ | - | $ | - | $ | - | $ | - | $ | -�� | $ | - | |||||||||
Other Paid-in Capital: | |||||||||||||||||||||
Beginning of year | 191 | 191 | 190 | 2,223 | 1,951 | 1,951 | |||||||||||||||
Capital contribution from parent | 66 | - | 1 | 6 | 272 | - | |||||||||||||||
Contribution of Ameren owned preferred stock without consideration | 33 | - | - | ||||||||||||||||||
Transfer of AERG to parent (Notes 1 and 16) | (310) | - | - | ||||||||||||||||||
Other paid-in capital, end of year | 257 | 191 | 191 | 1,952 | 2,223 | 1,951 | |||||||||||||||
Preferred Stock Not Subject to Mandatory Redemption | 50 | 50 | 50 | ||||||||||||||||||
Preferred Stock Not Subject to Mandatory Redemption: | |||||||||||||||||||||
Beginning balance | 115 | 115 | 115 | ||||||||||||||||||
Redemptions | (19) | - | - | ||||||||||||||||||
Contribution of Ameren owned preferred stock without consideration | (33) | - | - | ||||||||||||||||||
Other | (1) | - | - | ||||||||||||||||||
Preferred stock not subject to mandatory redemption, end of year | 62 | 115 | 115 | ||||||||||||||||||
Retained Earnings: | |||||||||||||||||||||
Beginning of year | 288 | 276 | 302 | 709 | 566 | 539 | |||||||||||||||
Net income | 29 | 15 | 17 | 252 | 247 | 93 | |||||||||||||||
Common stock dividends | (47) | - | (40) | (133) | (98) | (60) | |||||||||||||||
Preferred stock dividends | (3) | (3) | (3) | (4) | (6) | (6) | |||||||||||||||
Transfer of AERG to parent (Notes 1 and 16) | (281) | - | - | ||||||||||||||||||
Other | (1) | - | - | ||||||||||||||||||
Retained earnings, end of year | 267 | 288 | 276 | 542 | 709 | 566 | |||||||||||||||
Accumulated Other Comprehensive Income: | |||||||||||||||||||||
Beginning of year | - | - | 1 | ||||||||||||||||||
Change in derivative financial instruments | - | - | (1) | ||||||||||||||||||
Deferred retirement benefit costs, beginning of year | 25 | 23 | 30 | ||||||||||||||||||
Change in deferred retirement benefit costs | (4) | (4) | (1) | ||||||||||||||||||
Change in accumulated other comprehensive income from discontinued operations | (1) | 6 | (6) | ||||||||||||||||||
Accumulated other comprehensive income, end of year | - | - | - | ||||||||||||||||||
Deferred retirement benefit costs, end of year | 20 | 25 | 23 | ||||||||||||||||||
Total accumulated other comprehensive income, end of year | 20 | 25 | 23 | ||||||||||||||||||
Total Stockholders’ Equity | $ | 574 | $ | 529 | $ | 517 | $ | 2,576 | $ | 3,072 | $ | 2,655 | |||||||||
Comprehensive Income, Net of Taxes: | |||||||||||||||||||||
Net income | $ | 29 | $ | 15 | $ | 17 | $ | 252 | $ | 247 | $ | 93 | |||||||||
Reclassification adjustments for (gains) included in net income, net of income taxes of $-, $-, and $1, respectively | - | - | (1) | ||||||||||||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $(2), $(2), and $(1), respectively | (4) | (4) | (1) | ||||||||||||||||||
Comprehensive income from discontinued operations | (1) | 6 | (6) | ||||||||||||||||||
Total Comprehensive Income, Net of Taxes | $ | 29 | $ | 15 | $ | 16 | $ | 247 | $ | 249 | $ | 86 | |||||||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to CIPSAIC are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME (LOSS)
(In millions)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009(a) | 2008(a) | ||||||||||||||||
Operating Revenues | $ | 850 | $ | 908 | $ | 876 | $ | 1,126 | $ | 1,148 | $ | 1,422 | |||||||||
Operating Expenses: | |||||||||||||||||||||
Fuel | 278 | 377 | 344 | 522 | 415 | 509 | |||||||||||||||
Coal contract settlement | - | (60) | - | - | - | (60) | |||||||||||||||
Purchased power | - | - | 23 | 61 | 72 | 97 | |||||||||||||||
Other operations and maintenance | 172 | 175 | 163 | 191 | 226 | 227 | |||||||||||||||
Goodwill and other impairment losses | 170 | 6 | - | ||||||||||||||||||
Depreciation and amortization | 69 | 65 | 69 | 98 | 81 | 75 | |||||||||||||||
Taxes other than income taxes | 21 | 21 | 19 | 22 | 24 | 23 | |||||||||||||||
Total operating expenses | 540 | 578 | 618 | 1,064 | 824 | 871 | |||||||||||||||
Operating Income | 310 | 330 | 258 | 62 | 324 | 551 | |||||||||||||||
Other Income and Expenses: | |||||||||||||||||||||
Miscellaneous income | - | 1 | - | 1 | 1 | 1 | |||||||||||||||
Miscellaneous expense | - | (1) | - | 1 | 1 | 1 | |||||||||||||||
Total other income | - | - | - | - | - | - | |||||||||||||||
Interest Charges | 59 | 55 | 55 | 78 | 61 | 55 | |||||||||||||||
Income Before Income Taxes | 251 | 275 | 203 | ||||||||||||||||||
Income (Loss) Before Income Taxes | (16) | 263 | 496 | ||||||||||||||||||
Income Taxes | 96 | 100 | 78 | 20 | 101 | 182 | |||||||||||||||
Net Income | $ | 155 | $ | 175 | $ | 125 | |||||||||||||||
Net Income (Loss) | (36) | 162 | 314 | ||||||||||||||||||
Less: Net Income Attributable to Noncontrolling Interest | 3 | 2 | 28 | ||||||||||||||||||
Net Income (Loss) Attributable to Ameren Energy Generating Company | $ | (39) | $ | 160 | $ | 286 | |||||||||||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
| December 31, | December 31, | |||||||||||||
| 2009 | 2008 | 2010 | 2009(a) | |||||||||||
ASSETS | ||||||||||||||
Current Assets: | ||||||||||||||
Cash and cash equivalents | $ | 6 | $ | 2 | $ | 6 | $ | 6 | ||||||
Advances to money pool | 25 | 73 | ||||||||||||
Accounts receivable – affiliates | 103 | 88 | 126 | 129 | ||||||||||
Miscellaneous accounts and notes receivable | 22 | 20 | 19 | 26 | ||||||||||
Advances to money pool | 73 | - | ||||||||||||
Materials and supplies | 132 | 122 | 130 | 170 | ||||||||||
Mark-to-market derivative assets | 26 | 22 | ||||||||||||
Other current assets | 10 | 5 | 4 | 2 | ||||||||||
Total current assets | 346 | 237 | 336 | 428 | ||||||||||
Property and Plant, Net | 2,135 | 1,950 | 2,248 | 2,337 | ||||||||||
Investments and Other Assets: | ||||||||||||||
Goodwill | - | 65 | ||||||||||||
Intangible Assets | 34 | 49 | 3 | 62 | ||||||||||
Other Assets | 20 | 8 | 24 | 28 | ||||||||||
TOTAL ASSETS | $ | 2,535 | $ | 2,244 | $ | 2,611 | $ | 2,920 | ||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | ||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||
Current Liabilities: | ||||||||||||||
Current maturities of long-term debt | $ | 200 | $ | - | $ | - | $ | 200 | ||||||
Current portion of intercompany note payable – CIPS | 45 | 42 | ||||||||||||
Borrowings from money pool | - | 80 | ||||||||||||
Current portion of note payable – AIC | - | 45 | ||||||||||||
Note payable – Ameren | - | 131 | ||||||||||||
Accounts and wages payable | 71 | 82 | 62 | 85 | ||||||||||
Accounts payable – affiliates | 36 | 58 | 23 | 40 | ||||||||||
Current portion of intercompany tax payable – CIPS | 9 | 9 | ||||||||||||
Current portion of tax payable – AIC | 8 | 9 | ||||||||||||
Taxes accrued | 17 | 16 | 20 | 17 | ||||||||||
Deferred taxes | 26 | 15 | ||||||||||||
Interest accrued | 13 | 13 | ||||||||||||
Mark-to-market derivative liabilities | 9 | 12 | ||||||||||||
Mark-to-market derivative liabilities – affiliates | 5 | 1 | ||||||||||||
Current accumulated deferred income taxes, net | 13 | 26 | ||||||||||||
Other current liabilities | 34 | 28 | 12 | 19 | ||||||||||
Total current liabilities | 438 | 330 | 165 | 598 | ||||||||||
Credit Facility Borrowings | 100 | - | ||||||||||||
Long-term Debt, Net | 823 | 774 | 824 | 823 | ||||||||||
Intercompany Note Payable – CIPS | - | 45 | ||||||||||||
Deferred Credits and Other Liabilities: | ||||||||||||||
Accumulated deferred income taxes, net | 190 | 136 | 253 | 216 | ||||||||||
Accumulated deferred investment tax credits | 4 | 6 | 3 | 4 | ||||||||||
Intercompany tax payable – CIPS | 82 | 93 | ||||||||||||
Tax payable – AIC | 72 | 82 | ||||||||||||
Asset retirement obligations | 53 | 49 | 74 | 60 | ||||||||||
Pension and other postretirement benefits | 51 | 67 | 88 | 89 | ||||||||||
Other deferred credits and liabilities | 32 | 49 | 23 | 35 | ||||||||||
Total deferred credits and other liabilities | 412 | 400 | 513 | 486 | ||||||||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||||||||||
Stockholder’s Equity: | ||||||||||||||
Ameren Energy Generating Company Stockholder’s Equity: | ||||||||||||||
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding | - | - | - | - | ||||||||||
Other paid-in capital | 503 | 503 | 649 | 620 | ||||||||||
Retained earnings | 396 | 241 | 393 | 432 | ||||||||||
Accumulated other comprehensive loss | (37) | (49) | (44) | (48) | ||||||||||
Total stockholder’s equity | 862 | 695 | ||||||||||||
Total Ameren Energy Generating Company stockholder’s equity | 998 | 1,004 | ||||||||||||
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY | $ | 2,535 | $ | 2,244 | ||||||||||
Noncontrolling Interest | 11 | 9 | ||||||||||||
Total equity | 1,009 | 1,013 | ||||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 2,611 | $ | 2,920 | ||||||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009(a) | 2008(a) | ||||||||||||||||
Cash Flows From Operating Activities: | |||||||||||||||||||||
Net income | $ | 155 | $ | 175 | $ | 125 | |||||||||||||||
Net income (loss) | $ | (36) | $ | 162 | $ | 314 | |||||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||||||
Gain on sales of emission allowances | - | (2) | (2) | ||||||||||||||||||
Loss on goodwill and other impairments | 170 | 6 | - | ||||||||||||||||||
Net mark-to-market (gain) loss on derivatives | (17) | 16 | (2) | (8) | (27) | 24 | |||||||||||||||
Depreciation and amortization | 86 | 92 | 101 | 113 | 106 | 104 | |||||||||||||||
Amortization of debt issuance costs and discounts | 2 | - | - | 3 | 2 | 1 | |||||||||||||||
Deferred income taxes and investment tax credits, net | 55 | 14 | 30 | 19 | 64 | 22 | |||||||||||||||
Loss on asset impairment | 6 | - | - | ||||||||||||||||||
Other | - | - | 1 | 1 | - | (2) | |||||||||||||||
Changes in assets and liabilities: | |||||||||||||||||||||
Receivables | (17) | (18) | 10 | 10 | (13) | (22) | |||||||||||||||
Materials and supplies | (10) | (29) | 3 | 42 | (12) | (34) | |||||||||||||||
Accounts and wages payable | (9) | (11) | (4) | (25) | (19) | 6 | |||||||||||||||
Taxes accrued | 1 | 1 | (7) | 3 | - | 1 | |||||||||||||||
Assets, other | 7 | 12 | 3 | 7 | 9 | 10 | |||||||||||||||
Liabilities, other | (28) | (5) | (8) | (24) | (26) | (6) | |||||||||||||||
Pension and other postretirement benefits | 1 | 1 | 5 | 5 | 1 | 3 | |||||||||||||||
Net cash provided by operating activities | 232 | 246 | 255 | 280 | 253 | 421 | |||||||||||||||
Cash Flows From Investing Activities: | |||||||||||||||||||||
Capital expenditures | (277) | (317) | (191) | (95) | (316) | (353) | |||||||||||||||
Proceeds from sale of property interests | 18 | - | - | ||||||||||||||||||
Money pool advances, net | (73) | - | - | 48 | (73) | - | |||||||||||||||
Purchases of emission allowances | (2) | (13) | (20) | ||||||||||||||||||
Sales of emission allowances | 1 | 2 | 1 | ||||||||||||||||||
Other | 2 | (2) | - | - | - | (13) | |||||||||||||||
Net cash used in investing activities | (349) | (330) | (210) | (29) | (389) | (366) | |||||||||||||||
Cash Flows From Financing Activities: | |||||||||||||||||||||
Dividends on common stock | - | (101) | (113) | - | (43) | (221) | |||||||||||||||
Dividends paid to noncontrolling interest holder | - | (11) | (30) | ||||||||||||||||||
Capital issuance costs | (6) | (2) | - | (4) | (7) | (2) | |||||||||||||||
Short-term debt, net | - | (100) | 100 | ||||||||||||||||||
Short-term and credit facility borrowings, net | 100 | - | (100) | ||||||||||||||||||
Money pool borrowings, net | (80) | 26 | (69) | - | (80) | 26 | |||||||||||||||
Intercompany note payable – CIPS | (42) | (39) | (37) | ||||||||||||||||||
Redemptions of long-term debt | (200) | - | - | ||||||||||||||||||
Issuances of long-term debt | 249 | 300 | - | - | 249 | 300 | |||||||||||||||
Notes payable – affiliates | (176) | 31 | (27) | ||||||||||||||||||
Capital contribution from parent | - | - | 75 | 29 | - | - | |||||||||||||||
Net cash provided by (used in) financing activities | 121 | 84 | (44) | (251) | 139 | (54) | |||||||||||||||
Net change in cash and cash equivalents | 4 | - | 1 | - | 3 | 1 | |||||||||||||||
Cash and cash equivalents at beginning of year | 2 | 2 | 1 | 6 | 3 | 2 | |||||||||||||||
Cash and cash equivalents at end of year | $ | 6 | $ | 2 | $ | 2 | $ | 6 | $ | 6 | $ | 3 | |||||||||
Cash Paid During the Year: | |||||||||||||||||||||
Interest (net of $11, $10, and $6 capitalized, respectively) | $ | 56 | $ | 51 | $ | 53 | |||||||||||||||
Interest (net of $6, $12, and $10 capitalized, respectively) | $ | 77 | $ | 58 | $ | 51 | |||||||||||||||
Income taxes, net | 85 | 62 | 49 | 1 | 74 | 152 | |||||||||||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
| December 31, | December 31, | ||||||||||||||||||||
| 2009 | 2008 | 2007 | 2010 | 2009(a) | 2008(a) | ||||||||||||||||
Common Stock | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||
Other Paid-in Capital: | |||||||||||||||||||||
Beginning of year | 503 | 503 | 428 | 620 | 620 | 620 | |||||||||||||||
Capital contribution from parent | - | - | 75 | 29 | - | - | |||||||||||||||
Other paid-in capital, end of year | 503 | 503 | 503 | 649 | 620 | 620 | |||||||||||||||
Retained Earnings: | |||||||||||||||||||||
Beginning of year | 241 | 167 | 156 | 432 | 315 | 250 | |||||||||||||||
Net income | 155 | 175 | 125 | ||||||||||||||||||
Net income (loss) attributable to Ameren Energy Generating Company | (39) | 160 | 286 | ||||||||||||||||||
Common stock dividends | - | (101) | (113) | - | (43) | (221) | |||||||||||||||
Adjustment to adopt new accounting standard | - | - | (1) | ||||||||||||||||||
Retained earnings, end of year | 396 | 241 | 167 | 393 | 432 | 315 | |||||||||||||||
Accumulated Other Comprehensive Loss: | |||||||||||||||||||||
Derivative financial instruments, beginning of year | (6) | (1) | 3 | (6) | (6) | (1) | |||||||||||||||
Change in derivative financial instruments | - | (5) | (4) | - | - | (5) | |||||||||||||||
Derivative financial instruments, end of year | (6) | (6) | (1) | (6) | (6) | (6) | |||||||||||||||
Deferred retirement benefit costs, beginning of year | (43) | (21) | (24) | (42) | (61) | (12) | |||||||||||||||
Change in deferred retirement benefit costs | 12 | (22) | 3 | 4 | 19 | (49) | |||||||||||||||
Deferred retirement benefit costs, end of year | (31) | (43) | (21) | (38) | (42) | (61) | |||||||||||||||
Total accumulated other comprehensive loss, end of year | (37) | (49) | (22) | (44) | (48) | (67) | |||||||||||||||
Total Stockholder’s Equity | $ | 862 | $ | 695 | $ | 648 | |||||||||||||||
Total Ameren Energy Generating Company Stockholder’s Equity | $ | 998 | $ | 1,004 | $ | 868 | |||||||||||||||
Comprehensive Income, Net of Taxes: | |||||||||||||||||||||
Net income | $ | 155 | $ | 175 | $ | 125 | |||||||||||||||
Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $-, and $(2), respectively | - | - | (3) | ||||||||||||||||||
Reclassification adjustments for derivative gains included in net income, net of income taxes of $-, $3, and $1, respectively | - | (5) | (1) | ||||||||||||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $9, $(19), and $5, respectively | 12 | (22) | 3 | ||||||||||||||||||
Noncontrolling Interest: | |||||||||||||||||||||
Beginning of year | 9 | 16 | 24 | ||||||||||||||||||
Net income attributable to noncontrolling interest holder | 3 | 2 | 28 | ||||||||||||||||||
Dividends paid to noncontrolling interest holder | - | (11) | (30) | ||||||||||||||||||
Other comprehensive income (loss) attributable to noncontrolling interest holder | (1) | 2 | (6) | ||||||||||||||||||
Total Comprehensive Income, Net of Taxes | $ | 167 | $ | 148 | $ | 124 | |||||||||||||||
Noncontrolling interest, end of year | 11 | 9 | 16 | ||||||||||||||||||
Total Equity | $ | 1,009 | $ | 1,013 | $ | 884 | |||||||||||||||
Comprehensive Income (Loss), Net of Taxes: | |||||||||||||||||||||
Net income (loss) | $ | (36) | $ | 162 | $ | 314 | |||||||||||||||
Reclassification adjustments for derivative gains included in net income, net of income taxes of $-, $-, and $3, respectively | - | - | (5) | ||||||||||||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $5, $12, and $(29), respectively | 3 | 21 | (55) | ||||||||||||||||||
Total Comprehensive Income (Loss), Net of Taxes | $ | (33) | $ | 183 | $ | 254 | |||||||||||||||
Comprehensive income attributable to noncontrolling interest holder | 2 | 4 | 22 | ||||||||||||||||||
Total Comprehensive Income (Loss) Attributable to Ameren Energy Generating Company, Net of Taxes | $ | (35) | $ | 179 | $ | 232 | |||||||||||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Operating Revenues: | |||||||||
Electric | $ | 729 | $ | 771 | $ | 681 | |||
Gas | 277 | 375 | 329 | ||||||
Support services – affiliates | 70 | - | - | ||||||
Other | 6 | 1 | 1 | ||||||
Total operating revenues | 1,082 | 1,147 | 1,011 | ||||||
Operating Expenses: | |||||||||
Fuel | 115 | 121 | 71 | ||||||
Purchased power | 169 | 291 | 280 | ||||||
Gas purchased for resale | 189 | 284 | 237 | ||||||
Other operations and maintenance | 260 | 217 | 184 | ||||||
Depreciation and amortization | 70 | 77 | 73 | ||||||
Taxes other than income taxes | 27 | 25 | 23 | ||||||
Total operating expenses | 830 | 1,015 | 868 | ||||||
Operating Income | 252 | 132 | 143 | ||||||
Other Income and Expenses: | |||||||||
Miscellaneous income | 1 | 2 | 5 | ||||||
Miscellaneous expense | (5) | (5) | (6) | ||||||
Total other expenses | (4) | (3) | (1) | ||||||
Interest Charges | 41 | 21 | 27 | ||||||
Income Before Income Taxes | 207 | 108 | 115 | ||||||
Income Taxes | 72 | 39 | 39 | ||||||
Net Income | 135 | 69 | 76 | ||||||
Preferred Stock Dividends | 1 | 1 | 2 | ||||||
Net Income Available to Common Stockholder | $ | 134 | $ | 68 | $ | 74 | |||
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
| December 31, | ||||||
| 2009 | 2008 | |||||
ASSETS | ||||||
Current Assets: | ||||||
Cash and cash equivalents | $ | 88 | $ | - | ||
Accounts receivable –trade (less allowance for doubtful accounts of $3 and $3, respectively) | 39 | 62 | ||||
Accounts receivable – affiliates | 68 | 51 | ||||
Unbilled revenue | 43 | 65 | ||||
Miscellaneous accounts and notes receivable | 16 | - | ||||
Materials and supplies | 107 | 131 | ||||
Current regulatory assets | 29 | 24 | ||||
Other current assets | 18 | 35 | ||||
Total current assets | 408 | 368 | ||||
Property and Plant, Net | 1,789 | 1,734 | ||||
Investments and Other Assets: | ||||||
Intangible assets | 1 | 1 | ||||
Regulatory assets | 162 | 171 | ||||
Other assets | 22 | 22 | ||||
Total investments and other assets | 185 | 194 | ||||
TOTAL ASSETS | $ | 2,382 | $ | 2,296 | ||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||
Current Liabilities: | ||||||
Short-term debt | $ | - | $ | 236 | ||
Borrowings from money pool | - | 98 | ||||
Intercompany note payable – Ameren | 288 | - | ||||
Accounts and wages payable | 62 | 117 | ||||
Accounts payable – affiliates | 50 | 83 | ||||
Taxes accrued | 5 | 8 | ||||
Mark-to-market derivative liabilities | 10 | 21 | ||||
Mark-to-market derivative liabilities – affiliates | 19 | 7 | ||||
Other current liabilities | 72 | 62 | ||||
Total current liabilities | 506 | 632 | ||||
Long-term Debt, Net | 279 | 279 | ||||
Deferred Credits and Other Liabilities: | ||||||
Accumulated deferred income taxes, net | 214 | 171 | ||||
Accumulated deferred investment tax credits | 4 | 5 | ||||
Regulatory liabilities | 209 | 206 | ||||
Pension and other postretirement benefits | 193 | 216 | ||||
Asset retirement obligations | 34 | 28 | ||||
Other deferred credits and liabilities | 88 | 75 | ||||
Total deferred credits and other liabilities | 742 | 701 | ||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||
Stockholders’ Equity: | ||||||
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding | - | - | ||||
Other paid-in capital | 480 | 429 | ||||
Preferred stock not subject to mandatory redemption | 19 | 19 | ||||
Retained earnings | 354 | 240 | ||||
Accumulated other comprehensive loss | 2 | (4) | ||||
Total stockholders’ equity | 855 | 684 | ||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 2,382 | $ | 2,296 | ||
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Cash Flows From Operating Activities: | |||||||||
Net income | $ | 135 | $ | 69 | $ | 76 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||
Net mark-to-market (gain) loss on derivatives | (10) | 9 | - | ||||||
Depreciation and amortization | 72 | 77 | 74 | ||||||
Amortization of debt issuance costs and premium/discounts | 3 | 1 | 1 | ||||||
Deferred income taxes and investment tax credits, net | 40 | 15 | (1) | ||||||
Loss on asset impairment | 1 | 12 | - | ||||||
Changes in assets and liabilities: | |||||||||
Receivables | 9 | (17) | (32) | ||||||
Materials and supplies | 24 | (21) | (17) | ||||||
Accounts and wages payable | (38) | 65 | (6) | ||||||
Taxes accrued | (3) | 5 | (2) | ||||||
Assets, other | 21 | (7) | (7) | ||||||
Liabilities, other | - | 10 | (13) | ||||||
Pension and postretirement benefits | 9 | (11) | 1 | ||||||
Net cash provided by operating activities | 263 | 207 | 74 | ||||||
Cash Flows From Investing Activities: | |||||||||
Capital expenditures | (154) | (319) | (254) | ||||||
Money pool advances, net | - | - | 42 | ||||||
Purchases of emission allowances | (1) | - | - | ||||||
Other | 2 | 2 | - | ||||||
Net cash used in investing activities | (153) | (317) | (212) | ||||||
Cash Flows From Financing Activities: | |||||||||
Dividends on common stock | (20) | - | - | ||||||
Dividends on preferred stock | (1) | (1) | (2) | ||||||
Capital issuance costs | (7) | (1) | - | ||||||
Short-term debt, net | (236) | (109) | 180 | ||||||
Intercompany note payable – Ameren, net | 288 | - | - | ||||||
Money pool borrowings, net | (98) | 98 | - | ||||||
Redemptions, repurchases, and maturities of: | |||||||||
Long-term debt | - | (19) | (50) | ||||||
Preferred stock | - | (16) | (1) | ||||||
Issuances of long-term debt | - | 150 | - | ||||||
Capital contribution from parent | 51 | - | 14 | ||||||
Other | 1 | 2 | - | ||||||
Net cash provided by (used in) financing activities | (22) | 104 | 141 | ||||||
Net change in cash and cash equivalents | 88 | (6) | 3 | ||||||
Cash and cash equivalents at beginning of year | - | 6 | 3 | ||||||
Cash and cash equivalents at end of year | $ | 88 | $ | - | $ | 6 | |||
Cash Paid (Refunded) During the Year: | |||||||||
Interest (net of $1, $8, and $8 capitalized, respectively) | $ | 37 | $ | 24 | $ | 30 | |||
Income taxes, net | 82 | (15) | 35 | ||||||
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Common Stock | $ | - | $ | - | $ | - | |||
Other Paid-in Capital: | |||||||||
Beginning of year | 429 | 429 | 415 | ||||||
Capital contribution from parent | 51 | - | 14 | ||||||
Other paid-in capital, end of year | 480 | 429 | 429 | ||||||
Preferred Stock Not Subject to Mandatory Redemption | 19 | 19 | 19 | ||||||
Retained Earnings: | |||||||||
Beginning of year | 240 | 172 | 99 | ||||||
Net income | 135 | 69 | 76 | ||||||
Common stock dividends | (20) | - | - | ||||||
Preferred stock dividends | (1) | (1) | (2) | ||||||
Adjustment to adopt new accounting standard | - | - | (1) | ||||||
Retained earnings, end of year | 354 | 240 | 172 | ||||||
Accumulated Other Comprehensive Income (Loss): | |||||||||
Derivative financial instruments, beginning of year | - | 1 | 4 | ||||||
Change in derivative financial instruments | - | (1) | (3) | ||||||
Derivative financial instruments, end of year | - | - | 1 | ||||||
Deferred retirement benefit costs, beginning of year | (4) | 1 | (2) | ||||||
Change in deferred retirement benefit costs | 6 | (5) | 3 | ||||||
Deferred retirement benefit costs, end of year | 2 | (4) | 1 | ||||||
Total accumulated other comprehensive income (loss), end of year | 2 | (4) | 2 | ||||||
Total Stockholders’ Equity | $ | 855 | $ | 684 | $ | 622 | |||
Comprehensive Income, Net of Taxes: | |||||||||
Net income | $ | 135 | $ | 69 | $ | 76 | |||
Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $-, and $(1), respectively | - | - | (1) | ||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $-, $1, and $1, respectively | - | (1) | (2) | ||||||
Pension and other postretirement activity, net of income taxes (benefit) of $4, $(4), and $2, respectively | 6 | (5) | 3 | ||||||
Total Comprehensive Income, Net of Taxes | $ | 141 | $ | 63 | $ | 76 | |||
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Operating Revenues: | |||||||||
Electric | $ | 992 | $ | 1,071 | $ | 1,104 | |||
Gas | 501 | 620 | 540 | ||||||
Other | 11 | 5 | 2 | ||||||
Total operating revenues | 1,504 | 1,696 | 1,646 | ||||||
Operating Expenses: | |||||||||
Purchased power | 509 | 654 | 714 | ||||||
Gas purchased for resale | 310 | 452 | 390 | ||||||
Other operations and maintenance | 275 | 318 | 271 | ||||||
Depreciation and amortization | 99 | 85 | 80 | ||||||
Amortization of regulatory assets | 17 | 17 | 16 | ||||||
Taxes other than income taxes | 64 | 67 | 66 | ||||||
Total operating expenses | 1,274 | 1,593 | 1,537 | ||||||
Operating Income | 230 | 103 | 109 | ||||||
Other Income and Expenses: | |||||||||
Miscellaneous income | 3 | 11 | 14 | ||||||
Miscellaneous expense | (3) | (5) | (5) | ||||||
Total other income | - | 6 | 9 | ||||||
Interest Charges | 98 | 99 | 77 | ||||||
Income Before Income Taxes | 132 | 10 | 41 | ||||||
Income Taxes | 53 | 5 | 15 | ||||||
Net Income | 79 | 5 | 26 | ||||||
Preferred Stock Dividends | 2 | 2 | 2 | ||||||
Net Income Available to Common Stockholder | $ | 77 | $ | 3 | $ | 24 | |||
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
BALANCE SHEET
(In millions)
| December 31, | ||||||
| 2009 | 2008 | |||||
| ASSETS | ||||||
Current Assets: | ||||||
Cash and cash equivalents | $ | 190 | $ | 50 | ||
Accounts receivable –trade (less allowance for doubtful accounts of $9 and $12, respectively) | 107 | 156 | ||||
Accounts receivable – affiliates | 49 | 23 | ||||
Unbilled revenue | 94 | 133 | ||||
Miscellaneous accounts and notes receivable | 23 | - | ||||
Advances to money pool | - | 44 | ||||
Materials and supplies | 112 | 144 | ||||
Counterparty collateral | 5 | 35 | ||||
Current regulatory assets | 86 | 58 | ||||
Other current assets | 21 | 20 | ||||
Total current assets | 687 | 663 | ||||
Property and Plant, Net | 2,450 | 2,329 | ||||
Investments and Other Assets: | ||||||
Goodwill | 214 | 214 | ||||
Regulatory assets | 540 | 517 | ||||
Other assets | 51 | 47 | ||||
Total investments and other assets | 805 | 778 | ||||
TOTAL ASSETS | $ | 3,942 | $ | 3,770 | ||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||
Current Liabilities: | ||||||
Current maturities of long-term debt | $ | - | $ | 250 | ||
Accounts and wages payable | 98 | 94 | ||||
Accounts payable – affiliates | 117 | 105 | ||||
Taxes accrued | 6 | 8 | ||||
Customer deposits | 46 | 50 | ||||
Mark-to-market derivative liabilities | 20 | 36 | ||||
Mark-to-market derivative liabilities – affiliates | 65 | 20 | ||||
Environmental remediation | 59 | 18 | ||||
Current regulatory liabilities | 24 | 23 | ||||
Other current liabilities | 70 | 48 | ||||
Total current liabilities | 505 | 652 | ||||
Long-term Debt, Net | 1,147 | 1,150 | ||||
Deferred Credits and Other Liabilities: | ||||||
Accumulated deferred income taxes, net | 232 | 176 | ||||
Regulatory liabilities | 88 | 76 | ||||
Pension and other postretirement benefits | 238 | 314 | ||||
Other deferred credits and liabilities | 281 | 151 | ||||
Total deferred credits and other liabilities | 839 | 717 | ||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||
Stockholders’ Equity: | ||||||
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding | - | - | ||||
Other paid-in-capital | 1,349 | 1,194 | ||||
Preferred stock not subject to mandatory redemption | 46 | 46 | ||||
Retained earnings | 53 | 7 | ||||
Accumulated other comprehensive income | 3 | 4 | ||||
Total stockholders’ equity | 1,451 | 1,251 | ||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 3,942 | $ | 3,770 | ||
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Cash Flows From Operating Activities: | |||||||||
Net income | $ | 79 | $ | 5 | $ | 26 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||
Depreciation and amortization | 113 | 93 | 105 | ||||||
Amortization of debt issuance costs and premium/discounts | 6 | 9 | 8 | ||||||
Deferred income taxes | 54 | 26 | 4 | ||||||
Other | (2) | - | (1) | ||||||
Changes in assets and liabilities: | |||||||||
Receivables | 14 | (26) | (51) | ||||||
Materials and supplies | 33 | (10) | (12) | ||||||
Accounts and wages payable | 75 | 70 | (38) | ||||||
Taxes accrued | (2) | 1 | - | ||||||
Assets, other | 28 | (8) | (27) | ||||||
Liabilities, other | 11 | 23 | 21 | ||||||
Pension and other postretirement benefits | - | (5) | (5) | ||||||
Net cash provided by operating activities | 409 | 178 | 30 | ||||||
Cash Flows From Investing Activities: | |||||||||
Capital expenditures | (186) | (186) | (178) | ||||||
Advances to AITC for construction | (47) | (13) | (6) | ||||||
Money pool advances, net | 44 | (44) | - | ||||||
Other | - | (3) | (2) | ||||||
Net cash used in investing activities | (189) | (246) | (186) | ||||||
Cash Flows From Financing Activities: | |||||||||
Dividends on common stock | (31) | (60) | (61) | ||||||
Dividends on preferred stock | (2) | (2) | (2) | ||||||
Capital issuance costs | (7) | (5) | (2) | ||||||
Short-term debt, net | - | (175) | 100 | ||||||
Money pool borrowings, net | - | - | (43) | ||||||
Redemptions, repurchases, and maturities of long-term debt | (250) | (337) | - | ||||||
Issuance of long-term debt | - | 730 | 250 | ||||||
Capital contribution from parent | 155 | - | - | ||||||
IP SPT maturities | - | (54) | (87) | ||||||
Generator advances received for construction, net | 55 | 15 | 4 | ||||||
Overfunding of TFNs | - | - | 3 | ||||||
Net cash provided by (used in) financing activities | (80) | 112 | 162 | ||||||
Net change in cash and cash equivalents | 140 | 44 | 6 | ||||||
Cash and cash equivalents at beginning of year | 50 | 6 | - | ||||||
Cash and cash equivalents at end of year | $ | 190 | $ | 50 | $ | 6 | |||
Cash Paid (Refunded) During the Year: | |||||||||
Interest (net of $2, $1, and $1 capitalized, respectively) | $ | 96 | $ | 75 | $ | 65 | |||
Income taxes, net | 22 | (43) | 18 | ||||||
Noncash investing activity – asset transfer from AITC | 26 | - | - | ||||||
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Common Stock | $ | - | $ | - | $ | - | |||
Other Paid-in Capital: | |||||||||
Beginning of year | 1,194 | 1,194 | 1,194 | ||||||
Capital contribution from parent | 155 | - | - | ||||||
Other paid-in capital, end of year | 1,349 | 1,194 | 1,194 | ||||||
Preferred Stock Not Subject to Mandatory Redemption | 46 | 46 | 46 | ||||||
Retained Earnings: | |||||||||
Beginning of year | 7 | 64 | 101 | ||||||
Net income | 79 | 5 | 26 | ||||||
Common stock dividends | (31) | (60) | (61) | ||||||
Preferred stock dividends | (2) | (2) | (2) | ||||||
Retained earnings, end of year | 53 | 7 | 64 | ||||||
Accumulated Other Comprehensive Income: | |||||||||
Beginning of year | 4 | 4 | 5 | ||||||
Change in deferred retirement benefit costs | (1) | - | (1) | ||||||
Total accumulated other comprehensive income, end of year | 3 | 4 | 4 | ||||||
Total Stockholders’ Equity | $ | 1,451 | $ | 1,251 | $ | 1,308 | |||
Comprehensive Income, Net of Taxes: | |||||||||
Net income | $ | 79 | $ | 5 | $ | 26 | |||
Pension and other postretirement activity, net of income taxes of $-, $-, and $-, respectively | (1) | - | (1) | ||||||
Total Comprehensive Income, Net of Taxes | $ | 78 | $ | 5 | $ | 25 | |||
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY
AMEREN ILLINOIS COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 20092010
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
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, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.
| Ÿ | UE, or Union Electric Company, |
| Ÿ |
|
| Ÿ | Genco, or Ameren Energy Generating Company, operates a merchant electric generation business in Illinois and Missouri. Genco was incorporated in Illinois |
in March 2000. Genco’s coal, |
respectively, at the time of the |
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger, pursuant to the terms of the agreement, dated as of April 13, 2010. Upon consummation of the AIC Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The AIC Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in AIC included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. AIC accounted for the AERG distribution as a spinoff. AIC transferred AERG to Ameren based on AERG’s carrying value. AIC determined that the operating results of AERG qualified for discontinued operations presentation; therefore, AIC has segregated AERG’s operating results and presented them separately as discontinued operations for all periods presented prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operation remain classified as continuing operations. See Note 16 – Corporate Reorganization and Discontinued Operations for additional information. |
|
Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. OnEffective January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior-period financial statements to be
retrospectively combined for all periods presented. Consequently, Genco’s prior-period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco. Ameren and Genco consolidate EEI for financial reporting purposes. See Note 14 – Related Party Transactions for additional information.
The following table presents summarized financial information of EEI (in millions):
| For the years ended December 31, | 2009 | 2008 | 2007 | ||||||
Operating revenues | $ | 303 | $ | 520 | $ | 427 | |||
Operating income | 19 | 226 | 216 | ||||||
Net income | 10 | 142 | 136 | ||||||
As of December 31, | 2009 | 2008 | 2007 | ||||||
Current assets | $ | 86 | $ | 76 | $ | 69 | |||
Noncurrent assets | 172 | 140 | 124 | ||||||
Current liabilities | 165 | 93 | 60 | ||||||
Noncurrent liabilities | 48 | 43 | 10 | ||||||
The financial statements of Ameren, GencoAIC and CILCOGenco are prepared on a consolidated basis. CIPS has noUE does not have subsidiaries and therefore isits financial statements are not consolidated. UE had a subsidiary in 2007 (Union Electric Development Corporation), but in January 2008 this subsidiary was transferred to Ameren in the form of a stock dividend. Accordingly, UE’s financial statements were prepared on a consolidated basis for 2007 only. IP had a subsidiary in 2007 (Illinois Gas Supply Company) that was dissolved at December 31, 2007. Accordingly, IP’s financial statements were prepared on a consolidated basis for 2007 only. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
At December 31, 2010 and 2009, Ameren had immaterial investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership. Ameren has a variable interest in these investments as a limited partner. Ameren is not the primary beneficiary of these investments because Ameren does not have the power to direct matters that most significantly impact the activities of these VIE. The maximum exposure to loss as a result of these variable interests is limited to the investments in these partnerships. Ameren uses the equity method of accounting for its investments in these partnerships. See Note 14 – Related Party Transactions for information about AIC’s variable interest in ATXI.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires that Ameren management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, the NRC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE CIPS, CILCO
and IPAIC defer certain costs as assets pursuant to actions of our rate regulators or the expected ability to recover such costs in rates charged to customers. UE CIPS, CILCO and IPAIC also defer certain amounts as liabilities pursuant to actions of rate regulators or the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on regulatory assets and liabilities. AssetsIn addition, other costs that UE and AIC expect to recover from customers are also recorded as construction work in progress and property and plant, net. See Note 3 – Property and Plant, Net.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. See Note 2 – Rate and Regulatory MattersAIC has a rate mechanism that adjusts rates for additional information regarding regulatory recovery of uncollectible accounts receivable by the Ameren Illinois Utilities.bad debt expense above or below those being collected in rates.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 20092010 and 2008:2009:
| Ameren(a) | UE | AIC | Genco | |||||||||||||||||||||||||||||||
2010: | ||||||||||||||||||||||||||||||||||
Fuel(b) | $ | 255 | $ | 152 | $ | - | $ | 81 | ||||||||||||||||||||||||||
Gas stored underground | 175 | 22 | 152 | - | ||||||||||||||||||||||||||||||
Other materials and supplies | 277 | 167 | 46 | 49 | ||||||||||||||||||||||||||||||
| Ameren(a) | UE | CIPS | Genco | CILCO | IP | $ | 707 | $ | 341 | $ | 198 | $ | 130 | |||||||||||||||||||||
2009: | ||||||||||||||||||||||||||||||||||
Fuel(b) | $ | 315 | $ | 154 | $ | - | �� | $ | 97 | $ | 38 | $ | - | $ | 315 | $ | 154 | $ | - | $ | 123 | |||||||||||||
Gas stored underground | 183 | 22 | 32 | - | 45 | 84 | 183 | 22 | 161 | - | ||||||||||||||||||||||||
Other materials and supplies | 284 | 170 | 15 | 35 | 24 | 28 | 284 | 170 | 51 | 47 | ||||||||||||||||||||||||
| $ | 782 | $ | 346 | $ | 47 | $ | 132 | $ | 107 | $ | 112 | $ | 782 | $ | 346 | $ | 212 | $ | 170 | |||||||||||||||
2008: | ||||||||||||||||||||||||||||||||||
Fuel(b) | $ | 290 | $ | 139 | $ | - | $ | 92 | $ | 32 | $ | - | ||||||||||||||||||||||
Gas stored underground | 277 | 32 | 54 | - | 75 | 117 | ||||||||||||||||||||||||||||
Other materials and supplies | 275 | 168 | 16 | 30 | 24 | 27 | ||||||||||||||||||||||||||||
| $ | 842 | $ | 339 | $ | 70 | $ | 122 | $ | 131 | $ | 144 | |||||||||||||||||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| (b) | Consists of coal, oil, paint, propane, and tire chips. |
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Interest during construction is capitalized as a cost of merchant generation assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred by our merchant generation operations that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 – Property and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2010, 2009 2008 and 2007 generally2008 ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, as is the utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The following table presents the annual allowance for funds used during construction rates that were utilized during 2010, 2009 2008, and 2007:2008:
| 2009 | 2008 | 2007 | |||||||
Ameren | 6% – 10 | % | 1% – 7 | % | 6% – 7 | % | |||
UE | 6 | 7 | 6 | ||||||
CIPS | 6 | 1 | 6 | ||||||
CILCO | 10 | 1 | 7 | ||||||
IP | 9 | 5 | 6 |
| 2010 | 2009 | 2008 | ||||||||||
Ameren | 8% - 9% | 6% - 9% | 3% - 7% | |||||||||
UE | 8 | 6 | 7 | |||||||||
AIC | 9 | 9 | 3 | |||||||||
Goodwill and Intangible Assets
Goodwill.Goodwill represents the excess of the purchase price of an acquisition over the fair value of the
net assets acquired. As of December 31, 2010, Ameren’s and AIC’s goodwill relatesrelated to its acquisition of IP and an additional 20% EEI ownership interest acquired in 2004 and its acquisition of CILCORP in 2003.
We evaluate goodwill for impairment as well as itsof October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Ameren and Genco conducted an interim goodwill impairment test in the third quarter of 2010. That test resulted in the elimination of all goodwill associated with the Merchant Generation segment at Ameren ($420 million) and Genco ($65 million). This goodwill was associated with the acquisition of CILCORP and Medina Valley in 2003. IP’s goodwill relates to the acquisition of IP2003 and an additional 20% interest in EEI in 2004. See Note 17 – Goodwill–Goodwill and Other Asset Impairments for additional information.
Intangible Assets.We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s Genco’s and CILCO’sGenco’s intangible assets at December 31, 20092010, and 2008,2009, consisted of emission allowances. During 2010, Ameren and Genco recorded a noncash pretax impairment charge relating to SO2 emission allowances of $68 million and $41 million, respectively. UE recorded a $23 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability related to the SO2 emission allowances, which had no impact to earnings. See Note 17 – Goodwill and Other Asset Impairments for additional information about the asset impairment charges recorded during 2010. See also Note 15 – Commitments and Contingencies for additional information on emission allowances.
The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were carriedrecorded as intangible assets as ofat December 31, 2009.2010. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.
| SO2 and NOX in tons | SO2(a) | NOX(b) | Book Value(c) | |||||||||||||||||
| SO2 and NOx in tons | SO2(a) | NOx(b) | Book Value(c) | |||||||||||||||||
Ameren(d) | 3,028,000 | 25,091 | $ | 129 | (e) | 3,061,914 | 21,284 | $ | 7 | |||||||||||
UE | 1,610,000 | 13,677 | 35 | 1,587,663 | 15,850 | 2 | ||||||||||||||
Genco | 743,000 | 9,258 | 34 | 1,102,744 | 5,139 | 3 | ||||||||||||||
CILCO (AERG) | 354,000 | 210 | 1 | |||||||||||||||||
EEI | 321,000 | 1,946 | 5 | |||||||||||||||||
| (a) | Vintages are from |
| (b) | Vintage is |
| (c) | The book value represents SO2 and NOx emission allowances for use in periods through |
| (d) | Includes amounts for Ameren |
The following table presents amortization expense recorded in connection with the usageuse of emission allowances, net of gains and losses from emission allowance sales, for Ameren, UE Genco and CILCO (AERG)Genco during the years ended December 31, 2010, 2009, 2008, and 2007:2008.The table below does not include the intangible asset impairment charges referenced above.
| 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | |||||||||||||||||||
Ameren | $ | 24 | $ | 28 | $ | 35 | $ | 21 | $ | 29 | $ | 32 | ||||||||||||
UE | (5 | ) | (5 | ) | (5 | ) | (b | ) | - | - | ||||||||||||||
Genco | 16 | 25 | 30 | 18 | 24 | 26 | ||||||||||||||||||
CILCO (AERG) | 2 | (c | ) | 1 | ||||||||||||||||||||
| (a) |
| Includes allowances consumed that were recorded through purchase accounting. |
| Less than $1 million. |
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value. In the period in which we determine an asset meets the held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. In 2009,During 2010, Ameren and Genco recorded pretax asset impairment charges of $6$101 million as a result of the termination of a rail line extension project at a subsidiary of Genco and $64 million respectively, to adjustreduce the carrying value of an office building owned by Genco to its estimated fair value as of December 31, 2009. The charge related to the office building was based on the expected net proceeds to be generated from its sale in 2010. In addition, CILCO recorded an asset impairment charge of $1 million to adjust the carrying value of CILCO’s (AERG’s) Indian Trails generation facility’s estimated fair value as of December 31, 2009. This charge was based on the net proceeds generated from the sale of the facility in January 2010.
In 2008, asset impairment charges were recorded to adjust the carrying value of CILCO’s (AERG’s) Indian Trails and Sterling Avenue generationcertain generating facilities to their estimated fair values as of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails generation facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT. The charge was based on the net proceeds generated from the sale of the facility in 2009.
The 2009value. See Note 17 – Goodwill and 2008 asset impairment charges were recorded in Operating Expenses – Other OperationsAsset Impairments for information about Ameren and Maintenance Expense in the applicable statements of income and were included in Merchant Generation segment results.Genco’s impairments.
Investments
Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which UE believes would be recovered in electric rates paid by its customers. Accordingly, Ameren and UE recognize a regulatory asset on their balance sheets for losses on investments held in the nuclear decommissioning trust fund. See Note 9 – Nuclear Decommissioning Trust Fund Investments for additional information.
Environmental CostsNoncontrolling Interests
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liabilityTotal equity
TOTAL LIABILITIES AND EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income | $ | 151 | $ | 624 | $ | 644 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Loss on goodwill and other impairments | 589 | 7 | 14 | |||||||||
Net mark-to-market gain on derivatives | (15) | (23) | (3) | |||||||||
Depreciation and amortization | 783 | 748 | 705 | |||||||||
Amortization of nuclear fuel | 54 | 53 | 37 | |||||||||
Amortization of debt issuance costs and premium/discounts | 23 | 25 | 20 | |||||||||
Deferred income taxes and investment tax credits, net | 302 | 402 | 167 | |||||||||
Allowance for equity funds used during construction | (52) | (36) | (28) | |||||||||
Other | 40 | 17 | 14 | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | (85) | 21 | 12 | |||||||||
Materials and supplies | 78 | 67 | (100) | |||||||||
Accounts and wages payable | 27 | (42) | 57 | |||||||||
Taxes accrued | 9 | - | (30) | |||||||||
Assets, other | (109) | (66) | 83 | |||||||||
Liabilities, other | 71 | 99 | 110 | |||||||||
Pension and other postretirement benefits | (5) | (9) | (4) | |||||||||
Counterparty collateral, net | (73) | (17) | (25) | |||||||||
Taum Sauk insurance recoveries, net of costs | 54 | 107 | (149) | |||||||||
Net cash provided by operating activities | 1,842 | 1,977 | 1,524 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (1,031) | (1,704) | (1,896) | |||||||||
Nuclear fuel expenditures | (90) | (80) | (173) | |||||||||
Purchases of securities – nuclear decommissioning trust fund | (271) | (383) | (520) | |||||||||
Sales of securities – nuclear decommissioning trust fund | 256 | 380 | 497 | |||||||||
Other | 24 | (2) | (5) | |||||||||
Net cash used in investing activities | (1,112) | (1,789) | (2,097) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | (368) | (338) | (534) | |||||||||
Dividends paid to noncontrolling interest holders | (8) | (21) | (40) | |||||||||
Capital issuance costs | (15) | (65) | (12) | |||||||||
Short-term and credit facility borrowings, net | (121) | (324) | (298) | |||||||||
Redemptions, repurchases, and maturities: | ||||||||||||
Long-term debt | (310) | (631) | (842) | |||||||||
Preferred stock | (52) | - | (16) | |||||||||
Issuances: | ||||||||||||
Common stock | 80 | 634 | 154 | |||||||||
Long-term debt | - | 1,021 | 1,879 | |||||||||
Generator advances received for construction, net of repayments | (13) | 66 | 19 | |||||||||
Net cash provided by (used in) financing activities | (807) | 342 | 310 | |||||||||
Net change in cash and cash equivalents | (77) | 530 | (263) | |||||||||
Cash and cash equivalents at beginning of year | 622 | 92 | 355 | |||||||||
Cash and cash equivalents at end of year | $ | 545 | $ | 622 | $ | 92 | ||||||
Cash Paid (Refunded) During the Year: | ||||||||||||
Interest (net of $34, $40, and $41 capitalized, respectively) | $ | 494 | $ | 485 | $ | 409 | ||||||
Income taxes, net | (92) | 9 | 106 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Common Stock: | ||||||||||||
Beginning of year | $ | 2 | $ | 2 | $ | 2 | ||||||
Shares issued | - | - | - | |||||||||
Common stock, end of year | 2 | 2 | 2 | |||||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 5,412 | 4,780 | 4,604 | |||||||||
Shares issued (less issuance costs of $-, $17, and $-, respectively) | 80 | 617 | 154 | |||||||||
Stock-based compensation cost | 14 | 15 | 22 | |||||||||
Regulatory recovery of prior-period common stock issuance costs | 14 | - | - | |||||||||
Other paid-in capital, end of year | 5,520 | 5,412 | 4,780 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 2,455 | 2,181 | 2,110 | |||||||||
Net income attributable to Ameren Corporation | 139 | 612 | 605 | |||||||||
Dividends | (368) | (338) | (534) | |||||||||
Other | (1) | - | - | |||||||||
Retained earnings, end of year | 2,225 | 2,455 | 2,181 | |||||||||
Accumulated Other Comprehensive Income (Loss): | ||||||||||||
Derivative financial instruments, beginning of year | 10 | 48 | 9 | |||||||||
Change in derivative financial instruments | (10) | (38) | 39 | |||||||||
Derivative financial instruments, end of year | - | 10 | 48 | |||||||||
Deferred retirement benefit costs, beginning of year | (23) | (43) | 25 | |||||||||
Change in deferred retirement benefit costs | 6 | 20 | (68) | |||||||||
Deferred retirement benefit costs, end of year | (17) | (23) | (43) | |||||||||
Total accumulated other comprehensive income (loss), end of year | (17) | (13) | 5 | |||||||||
Total Ameren Corporation Stockholders’ Equity | $ | 7,730 | $ | 7,856 | $ | 6,968 | ||||||
Noncontrolling Interests: | ||||||||||||
Beginning of year | 204 | 211 | 218 | |||||||||
Net income attributable to noncontrolling interest holders | 12 | 12 | 39 | |||||||||
Dividends paid to noncontrolling interest holders | (8) | (21) | (40) | |||||||||
Redemptions of preferred stock | (52) | - | - | |||||||||
Other | (2) | 2 | (6) | |||||||||
Noncontrolling interests, end of year | 154 | 204 | 211 | |||||||||
Total Equity | $ | 7,884 | $ | 8,060 | $ | 7,179 | ||||||
Comprehensive Income, Net of Taxes: | ||||||||||||
Net income | $ | 151 | $ | 624 | $ | 644 | ||||||
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $(1), $78, and $65, respectively | (2) | 103 | 116 | |||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $5, $82, and $43, respectively | (8) | (112) | (77) | |||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $-, $18, and $-, respectively | - | (29) | - | |||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $6, $22, and $(45), respectively | 4 | 22 | (75) | |||||||||
Total Comprehensive Income, Net of Taxes | $ | 145 | $ | 608 | $ | 608 | ||||||
Comprehensive income attributable to noncontrolling interests | 10 | 14 | 33 | |||||||||
Total Comprehensive Income Attributable to Ameren Corporation, Net of Taxes | $ | 135 | $ | 594 | $ | 575 | ||||||
| Common stock shares at beginning of year | 237.4 | 212.3 | 208.3 | |||||||||
Shares issued | 3.0 | 25.1 | 4.0 | |||||||||
| Common stock shares at end of year | 240.4 | 237.4 | 212.3 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating Revenues: | ||||||||||||
Electric | $ | 3,030 | $ | 2,700 | $ | 2,756 | ||||||
Gas | 166 | 170 | 201 | |||||||||
Other | 1 | 4 | 3 | |||||||||
Total operating revenues | 3,197 | 2,874 | 2,960 | |||||||||
Operating Expenses: | ||||||||||||
Fuel | 635 | 593 | 672 | |||||||||
Purchased power | 162 | 124 | 160 | |||||||||
Gas purchased for resale | 91 | 97 | 123 | |||||||||
Other operations and maintenance | 931 | 880 | 922 | |||||||||
Depreciation and amortization | 382 | 357 | 329 | |||||||||
Taxes other than income taxes | 285 | 257 | 240 | |||||||||
Total operating expenses | 2,486 | 2,308 | 2,446 | |||||||||
Operating Income | 711 | 566 | 514 | |||||||||
Other Income and Expenses: | ||||||||||||
Miscellaneous income | 83 | 63 | 62 | |||||||||
Miscellaneous expense | 13 | 7 | 9 | |||||||||
Total other income | 70 | 56 | 53 | |||||||||
Interest Charges | 213 | 229 | 193 | |||||||||
Income Before Income Taxes and Equity in Income of Unconsolidated Investment | 568 | 393 | 374 | |||||||||
Income Taxes | 199 | 128 | 134 | |||||||||
Income Before Equity in Income of Unconsolidated Investment | 369 | 265 | 240 | |||||||||
Equity in Income of Unconsolidated Investment, Net of Taxes | - | - | 11 | |||||||||
Net Income | 369 | 265 | 251 | |||||||||
Preferred Stock Dividends | 5 | 6 | 6 | |||||||||
Net Income Available to Common Stockholder | $ | 364 | $ | 259 | $ | 245 | ||||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
BALANCE SHEET
(In millions, except per share amounts)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 202 | $ | 267 | ||||
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $6, respectively) | 217 | 154 | �� | |||||
Accounts receivable – affiliates | 6 | 22 | ||||||
Unbilled revenue | 159 | 127 | ||||||
Miscellaneous accounts and notes receivable | 116 | 199 | ||||||
Materials and supplies | 341 | 346 | ||||||
Current regulatory assets | 179 | 63 | ||||||
Other current assets | 55 | 50 | ||||||
Total current assets | 1,275 | 1,228 | ||||||
Property and Plant, Net | 9,775 | 9,585 | ||||||
Investments and Other Assets: | ||||||||
Nuclear decommissioning trust fund | 337 | 293 | ||||||
Intangible assets | 2 | 35 | ||||||
Regulatory assets | 694 | 683 | ||||||
Other assets | 421 | 395 | ||||||
Total investments and other assets | 1,454 | 1,406 | ||||||
TOTAL ASSETS | $ | 12,504 | $ | 12,219 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities: | ||||||||
Current maturities of long-term debt | $ | 5 | $ | 4 | ||||
Accounts and wages payable | 326 | 336 | ||||||
Accounts payable – affiliates | 75 | 132 | ||||||
Taxes accrued | 76 | 21 | ||||||
Interest accrued | 63 | 63 | ||||||
Current accumulated deferred income taxes, net | 43 | 12 | ||||||
Other current liabilities | 112 | 115 | ||||||
Total current liabilities | 700 | 683 | ||||||
Long-term Debt, Net | 3,949 | 4,018 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Accumulated deferred income taxes, net | 1,908 | 1,660 | ||||||
Accumulated deferred investment tax credits | 78 | 79 | ||||||
Regulatory liabilities | 766 | 865 | ||||||
Asset retirement obligations | 363 | 331 | ||||||
Pension and other postretirement benefits | 369 | 400 | ||||||
Other deferred credits and liabilities | 218 | 126 | ||||||
Total deferred credits and other liabilities | 3,702 | 3,461 | ||||||
Commitments and Contingencies (Notes 2, 10, 14 and 15) | ||||||||
Stockholders’ Equity: | ||||||||
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | 511 | ||||||
Other paid-in capital, principally premium on common stock | 1,555 | 1,555 | ||||||
Preferred stock not subject to mandatory redemption | 80 | 113 | ||||||
Retained earnings | 2,007 | 1,878 | ||||||
Total stockholders’ equity | 4,153 | 4,057 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 12,504 | $ | 12,219 | ||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income | $ | 369 | $ | 265 | $ | 251 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Net mark-to-market (gain) loss on derivatives | (1) | (29) | 29 | |||||||||
Depreciation and amortization | 382 | 357 | 329 | |||||||||
Amortization of nuclear fuel | 54 | 53 | 37 | |||||||||
Amortization of debt issuance costs and premium/discounts | 4 | 10 | 6 | |||||||||
Deferred income taxes and investment tax credits, net | 228 | 276 | 89 | |||||||||
Allowance for equity funds used during construction | (50) | (33) | (27) | |||||||||
Other | 20 | - | (5) | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | (56) | (58) | 60 | |||||||||
Materials and supplies | 7 | (2) | (32) | |||||||||
Accounts and wages payable | (17) | 16 | (89) | |||||||||
Taxes accrued | 55 | 1 | (61) | |||||||||
Assets, other | (145) | (58) | 42 | |||||||||
Liabilities, other | 77 | 69 | 63 | |||||||||
Pension and other postretirement benefits | (3) | (2) | - | |||||||||
Taum Sauk insurance recoveries, net of costs | 54 | 107 | (149) | |||||||||
Net cash provided by operating activities | 978 | 972 | 543 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (608) | (872) | (874) | |||||||||
Nuclear fuel expenditures | (90) | (80) | (173) | |||||||||
Proceeds from intercompany note receivable | - | - | 36 | |||||||||
Purchases of securities – nuclear decommissioning trust fund | (271) | (383) | (520) | |||||||||
Sales of securities – nuclear decommissioning trust fund | 256 | 380 | 497 | |||||||||
Other | 7 | - | 1 | |||||||||
Net cash used in investing activities | (706) | (955) | (1,033) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | (235) | (175) | (264) | |||||||||
Dividends on preferred stock | (5) | (6) | (6) | |||||||||
Capital issuance costs | (4) | (14) | (5) | |||||||||
Short-term debt, net | - | (251) | 169 | |||||||||
Intercompany note payable – Ameren, net | - | (92) | 92 | |||||||||
Redemptions, repurchases, and maturities: | ||||||||||||
Long-term debt | (70) | (4) | (382) | |||||||||
Preferred stock | (33) | - | - | |||||||||
Issuances of long-term debt | - | 349 | 699 | |||||||||
Capital contribution from parent | - | 436 | - | |||||||||
Other | 10 | 7 | 2 | |||||||||
Net cash provided by (used in) financing activities | (337) | 250 | 305 | |||||||||
Net change in cash and cash equivalents | (65) | 267 | (185) | |||||||||
Cash and cash equivalents at beginning of year | 267 | - | 185 | |||||||||
Cash and cash equivalents at end of year | $ | 202 | $ | 267 | $ | - | ||||||
Cash Paid (Refunded) During the Year: | ||||||||||||
Interest (net of $26, $23, and $19 capitalized, respectively) | $ | 213 | $ | 212 | $ | 177 | ||||||
Income taxes, net | (106) | (208) | 130 | |||||||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Common Stock | $ | 511 | $ | 511 | $ | 511 | ||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 1,555 | 1,119 | 1,119 | |||||||||
Capital contribution from parent | - | 436 | - | |||||||||
Other paid-in capital, end of year | 1,555 | 1,555 | 1,119 | |||||||||
Preferred Stock Not Subject to Mandatory Redemption: | ||||||||||||
Beginning balance | 113 | 113 | 113 | |||||||||
Redemptions | (33) | - | - | |||||||||
Preferred stock not subject to mandatory redemption, end of year | 80 | 113 | 113 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 1,878 | 1,794 | 1,855 | |||||||||
Net income | 369 | 265 | 251 | |||||||||
Common stock dividends | (235) | (175) | (264) | |||||||||
Preferred stock dividends | (5) | (6) | (6) | |||||||||
Dividend-in-kind to Ameren | - | - | (42) | |||||||||
Retained earnings, end of year | 2,007 | 1,878 | 1,794 | |||||||||
Accumulated Other Comprehensive Income: | ||||||||||||
Beginning of year | - | 25 | 3 | |||||||||
Change in derivative financial instruments | - | (25) | 22 | |||||||||
Accumulated other comprehensive income, end of year | - | - | 25 | |||||||||
Total Stockholders’ Equity | $ | 4,153 | $ | 4,057 | $ | 3,562 | ||||||
Comprehensive Income, Net of Taxes: | ||||||||||||
Net income | $ | 369 | $ | 265 | $ | 251 | ||||||
Unrealized net gain on derivative hedging instruments, net of income taxes of $-, $11, and $22, respectively | - | 17 | 36 | |||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $-, $8, and $9, respectively | - | (13) | (14) | |||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $-, $18, and $-, respectively | - | (29) | - | |||||||||
Total Comprehensive Income, Net of Taxes | $ | 369 | $ | 240 | $ | 273 | ||||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Operating Revenues: | ||||||||||||
Electric | $ | 2,061 | $ | 1,965 | $ | 2,242 | ||||||
Gas | 953 | 1,015 | 1,265 | |||||||||
Other | - | 4 | 1 | |||||||||
Total operating revenues | 3,014 | 2,984 | 3,508 | |||||||||
Operating Expenses: | ||||||||||||
Purchased power | 965 | 1,048 | 1,405 | |||||||||
Gas purchased for resale | 578 | 642 | 914 | |||||||||
Other operations and maintenance | 635 | 590 | 653 | |||||||||
Depreciation and amortization | 210 | 216 | 219 | |||||||||
Taxes other than income taxes | 128 | 125 | 126 | |||||||||
Total operating expenses | 2,516 | 2,621 | 3,317 | |||||||||
Operating Income | 498 | 363 | 191 | |||||||||
Other Income and Expenses: | ||||||||||||
Miscellaneous income | 7 | 12 | 23 | |||||||||
Miscellaneous expense | 13 | 10 | 12 | |||||||||
Total other income (expense) | (6) | 2 | 11 | |||||||||
Interest Charges | 143 | 153 | 145 | |||||||||
Income Before Income Taxes | 349 | 212 | 57 | |||||||||
Income Taxes | 137 | 79 | 16 | |||||||||
Income from Continuing Operations | 212 | 133 | 41 | |||||||||
Income from Discontinued Operations, net of tax | 40 | 114 | 52 | |||||||||
Net Income | 252 | 247 | 93 | |||||||||
Preferred Stock Dividends | 4 | 6 | 6 | |||||||||
Net Income Available to Common Stockholder | $ | 248 | $ | 241 | $ | 87 | ||||||
| (a) | Prior period has been |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET
(In millions)
| December 31, | ||||||||
| 2010 | 2009(a) | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 322 | $ | 306 | ||||
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $17, respectively) | 230 | 199 | ||||||
Accounts and notes receivable – affiliates | 73 | 105 | ||||||
Unbilled revenue | 205 | 189 | ||||||
Miscellaneous accounts and notes receivable | 44 | 51 | ||||||
Materials and supplies | 198 | 212 | ||||||
Current regulatory assets | 260 | 174 | ||||||
Other current assets | 106 | 63 | ||||||
Current assets of discontinued operations | - | 112 | ||||||
Total current assets | 1,438 | 1,411 | ||||||
Property and Plant, Net | 4,576 | 4,354 | ||||||
Investments and Other Assets: | ||||||||
Intercompany tax receivable – Genco | 72 | 82 | ||||||
Goodwill | 411 | 411 | ||||||
Regulatory assets | 743 | 944 | ||||||
Other assets | 166 | 91 | ||||||
Noncurrent assets of discontinued operations | - | 1,005 | ||||||
Total investments and other assets | 1,392 | 2,533 | ||||||
TOTAL ASSETS | $ | 7,406 | $ | 8,298 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities: | ||||||||
Current maturities of long-term debt | $ | 150 | $ | - | ||||
Accounts and wages payable | 182 | 192 | ||||||
Accounts payable – affiliates | 82 | 179 | ||||||
Taxes accrued | 26 | 15 | ||||||
Customer deposits | 83 | 85 | ||||||
Mark-to-market derivative liabilities | 82 | 38 | ||||||
Mark-to-market derivative liabilities – affiliates | 172 | 127 | ||||||
Environmental remediation | 72 | 80 | ||||||
Current regulatory liabilities | 76 | 57 | ||||||
Other current liabilities | 90 | 132 | ||||||
Current liabilities of discontinued operations | - | 334 | ||||||
Total current liabilities | 1,015 | 1,239 | ||||||
Long-term Debt, Net | 1,657 | 1,847 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Accumulated deferred income taxes, net | 724 | 554 | ||||||
Accumulated deferred investment tax credits | 8 | 10 | ||||||
Regulatory liabilities | 553 | 391 | ||||||
Pension and other postretirement benefits | 413 | 471 | ||||||
Other deferred credits and liabilities | 460 | 483 | ||||||
Noncurrent liabilities of discontinued operations | - | 231 | ||||||
Total deferred credits and other liabilities | 2,158 | 2,140 | ||||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||||
Stockholders’ Equity: | ||||||||
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | - | - | ||||||
Other paid-in capital | 1,952 | 2,223 | ||||||
Preferred stock not subject to mandatory redemption | 62 | 115 | ||||||
Retained earnings | 542 | 709 | ||||||
Accumulated other comprehensive income | 20 | 25 | ||||||
Total stockholders’ equity | 2,576 | 3,072 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 7,406 | $ | 8,298 | ||||
| (a) | Prior period has been adjusted to reflect the |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income | $ | 252 | $ | 247 | $ | 93 | ||||||
Income from discontinued operations, net of tax | (40) | (114) | (52) | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 210 | 212 | 209 | |||||||||
Amortization of debt issuance costs and premium/discounts | 10 | 9 | 11 | |||||||||
Deferred income taxes and investment tax credits, net | 161 | 72 | 22 | |||||||||
Other | 2 | (11) | 6 | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | (41) | 142 | (25) | |||||||||
Materials and supplies | 14 | 85 | (37) | |||||||||
Accounts and wages payable | (44) | (3) | 74 | |||||||||
Taxes accrued | 11 | (11) | 11 | |||||||||
Assets, other | (76) | 74 | (35) | |||||||||
Liabilities, other | 32 | 11 | 72 | |||||||||
Pension and other postretirement benefits | (7) | 5 | (20) | |||||||||
Operating cash flows provided by discontinued operations | 113 | 141 | 159 | |||||||||
Net cash provided by operating activities | 597 | 859 | 488 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (286) | (356) | (345) | |||||||||
Advances to ATXI for construction | (10) | (47) | (13) | |||||||||
Proceeds from intercompany note receivable – Genco | 45 | 42 | 39 | |||||||||
Other | - | - | (2) | |||||||||
Capital expenditures of discontinued operations | (6) | (91) | (256) | |||||||||
Net cash used in investing activities | (257) | (452) | (577) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | (133) | (98) | (60) | |||||||||
Dividends on preferred stock | (4) | (6) | (6) | |||||||||
Capital issuance costs | (4) | (13) | (6) | |||||||||
Short-term and credit facility borrowings, net | - | (62) | (353) | |||||||||
Redemptions, repurchases, and maturities: | ||||||||||||
Long-term debt | (40) | (250) | (460) | |||||||||
Preferred stock | (19) | - | (16) | |||||||||
Issuances of long-term debt | - | - | 880 | |||||||||
Generator advances for construction received (refunded), net of repayments | (23) | 56 | 20 | |||||||||
Capital contribution from parent | 6 | 272 | - | |||||||||
Net financing activities provided by (used in) discontinued operations | (107) | (50) | 104 | |||||||||
Net cash provided by (used in) financing activities | (324) | (151) | 103 | |||||||||
Net change in cash and cash equivalents | 16 | 256 | 14 | |||||||||
Cash and cash equivalents at beginning of year | 306 | 50 | 36 | |||||||||
Cash and cash equivalents at end of year | $ | 322 | $ | 306 | $ | 50 | ||||||
Cash Paid (Refunded) During the Year: | ||||||||||||
Interest (net of $1, $3 and $10 capitalized, respectively) | $ | 160 | $ | 167 | $ | 131 | ||||||
Income taxes, net | (39) | 129 | (80) | |||||||||
Noncash investing activity – asset transfer from ATXI | 7 | 29 | - | |||||||||
| (a) | Prior period has been adjusted to reflect the |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Common Stock | $ | - | $ | -�� | $ | - | ||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 2,223 | 1,951 | 1,951 | |||||||||
Capital contribution from parent | 6 | 272 | - | |||||||||
Contribution of Ameren owned preferred stock without consideration | 33 | - | - | |||||||||
Transfer of AERG to parent (Notes 1 and 16) | (310) | - | - | |||||||||
Other paid-in capital, end of year | 1,952 | 2,223 | 1,951 | |||||||||
Preferred Stock Not Subject to Mandatory Redemption: | ||||||||||||
Beginning balance | 115 | 115 | 115 | |||||||||
Redemptions | (19) | - | - | |||||||||
Contribution of Ameren owned preferred stock without consideration | (33) | - | - | |||||||||
Other | (1) | - | - | |||||||||
Preferred stock not subject to mandatory redemption, end of year | 62 | 115 | 115 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 709 | 566 | 539 | |||||||||
Net income | 252 | 247 | 93 | |||||||||
Common stock dividends | (133) | (98) | (60) | |||||||||
Preferred stock dividends | (4) | (6) | (6) | |||||||||
Transfer of AERG to parent (Notes 1 and 16) | (281) | - | - | |||||||||
Other | (1) | - | - | |||||||||
Retained earnings, end of year | 542 | 709 | 566 | |||||||||
Accumulated Other Comprehensive Income: | ||||||||||||
Deferred retirement benefit costs, beginning of year | 25 | 23 | 30 | |||||||||
Change in deferred retirement benefit costs | (4) | (4) | (1) | |||||||||
Change in accumulated other comprehensive income from discontinued operations | (1) | 6 | (6) | |||||||||
Deferred retirement benefit costs, end of year | 20 | 25 | 23 | |||||||||
Total accumulated other comprehensive income, end of year | 20 | 25 | 23 | |||||||||
Total Stockholders’ Equity | $ | 2,576 | $ | 3,072 | $ | 2,655 | ||||||
Comprehensive Income, Net of Taxes: | ||||||||||||
Net income | $ | 252 | $ | 247 | $ | 93 | ||||||
Pension and other postretirement activity, net of income taxes (benefit) of $(2), $(2), and $(1), respectively | (4) | (4) | (1) | |||||||||
Comprehensive income from discontinued operations | (1) | 6 | (6) | |||||||||
Total Comprehensive Income, Net of Taxes | $ | 247 | $ | 249 | $ | 86 | ||||||
| (a) | Prior period has been adjusted to |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME (LOSS)
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Operating Revenues | $ | 1,126 | $ | 1,148 | $ | 1,422 | ||||||
Operating Expenses: | ||||||||||||
Fuel | 522 | 415 | 509 | |||||||||
Coal contract settlement | - | - | (60) | |||||||||
Purchased power | 61 | 72 | 97 | |||||||||
Other operations and maintenance | 191 | 226 | 227 | |||||||||
Goodwill and other impairment losses | 170 | 6 | - | |||||||||
Depreciation and amortization | 98 | 81 | 75 | |||||||||
Taxes other than income taxes | 22 | 24 | 23 | |||||||||
Total operating expenses | 1,064 | 824 | 871 | |||||||||
Operating Income | 62 | 324 | 551 | |||||||||
Other Income and Expenses: | ||||||||||||
Miscellaneous income | 1 | 1 | 1 | |||||||||
Miscellaneous expense | 1 | 1 | 1 | |||||||||
Total other income | - | - | - | |||||||||
Interest Charges | 78 | 61 | 55 | |||||||||
Income (Loss) Before Income Taxes | (16) | 263 | 496 | |||||||||
Income Taxes | 20 | 101 | 182 | |||||||||
Net Income (Loss) | (36) | 162 | 314 | |||||||||
Less: Net Income Attributable to Noncontrolling Interest | 3 | 2 | 28 | |||||||||
Net Income (Loss) Attributable to Ameren Energy Generating Company | $ | (39) | $ | 160 | $ | 286 | ||||||
| (a) | Prior period has been adjusted to include EEI as |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
| December 31, | ||||||||
| 2010 | 2009(a) | |||||||
| ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 6 | $ | 6 | ||||
Advances to money pool | 25 | 73 | ||||||
Accounts receivable – affiliates | 126 | 129 | ||||||
Miscellaneous accounts and notes receivable | 19 | 26 | ||||||
Materials and supplies | 130 | 170 | ||||||
Mark-to-market derivative assets | 26 | 22 | ||||||
Other current assets | 4 | 2 | ||||||
Total current assets | 336 | 428 | ||||||
Property and Plant, Net | 2,248 | 2,337 | ||||||
Investments and Other Assets: | ||||||||
Goodwill | - | 65 | ||||||
Intangible Assets | 3 | 62 | ||||||
Other Assets | 24 | 28 | ||||||
TOTAL ASSETS | $ | 2,611 | $ | 2,920 | ||||
| LIABILITIES AND EQUITY | ||||||||
Current Liabilities: | ||||||||
Current maturities of long-term debt | $ | - | $ | 200 | ||||
Current portion of note payable – AIC | - | 45 | ||||||
Note payable – Ameren | - | 131 | ||||||
Accounts and wages payable | 62 | 85 | ||||||
Accounts payable – affiliates | 23 | 40 | ||||||
Current portion of tax payable – AIC | 8 | 9 | ||||||
Taxes accrued | 20 | 17 | ||||||
Interest accrued | 13 | 13 | ||||||
Mark-to-market derivative liabilities | 9 | 12 | ||||||
Mark-to-market derivative liabilities – affiliates | 5 | 1 | ||||||
Current accumulated deferred income taxes, net | 13 | 26 | ||||||
Other current liabilities | 12 | 19 | ||||||
Total current liabilities | 165 | 598 | ||||||
Credit Facility Borrowings | 100 | - | ||||||
Long-term Debt, Net | 824 | 823 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Accumulated deferred income taxes, net | 253 | 216 | ||||||
Accumulated deferred investment tax credits | 3 | 4 | ||||||
Tax payable – AIC | 72 | 82 | ||||||
Asset retirement obligations | 74 | 60 | ||||||
Pension and other postretirement benefits | 88 | 89 | ||||||
Other deferred credits and liabilities | 23 | 35 | ||||||
Total deferred credits and other liabilities | 513 | 486 | ||||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||||
Ameren Energy Generating Company Stockholder’s Equity: | ||||||||
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding | - | - | ||||||
Other paid-in capital | 649 | 620 | ||||||
Retained earnings | 393 | 432 | ||||||
Accumulated other comprehensive loss | (44) | (48) | ||||||
Total Ameren Energy Generating Company stockholder’s equity | 998 | 1,004 | ||||||
Noncontrolling Interest | 11 | 9 | ||||||
Total equity | 1,009 | 1,013 | ||||||
TOTAL LIABILITIES AND EQUITY | $ | 2,611 | $ | 2,920 | ||||
Unamortized Debt Discount, Premium, and Expense
Discount, premium, and expense associated with long-term debt are amortized over the lives
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of
|
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income (loss) | $ | (36) | $ | 162 | $ | 314 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Loss on goodwill and other impairments | 170 | 6 | - | |||||||||
Net mark-to-market (gain) loss on derivatives | (8) | (27) | 24 | |||||||||
Depreciation and amortization | 113 | 106 | 104 | |||||||||
Amortization of debt issuance costs and discounts | 3 | 2 | 1 | |||||||||
Deferred income taxes and investment tax credits, net | 19 | 64 | 22 | |||||||||
Other | 1 | - | (2) | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | 10 | (13) | (22) | |||||||||
Materials and supplies | 42 | (12) | (34) | |||||||||
Accounts and wages payable | (25) | (19) | 6 | |||||||||
Taxes accrued | 3 | - | 1 | |||||||||
Assets, other | 7 | 9 | 10 | |||||||||
Liabilities, other | (24) | (26) | (6) | |||||||||
Pension and other postretirement benefits | 5 | 1 | 3 | |||||||||
Net cash provided by operating activities | 280 | 253 | 421 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (95) | (316) | (353) | |||||||||
Proceeds from sale of property interests | 18 | - | - | |||||||||
Money pool advances, net | 48 | (73) | - | |||||||||
Other | - | - | (13) | |||||||||
Net cash used in investing activities | (29) | (389) | (366) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | - | (43) | (221) | |||||||||
Dividends paid to noncontrolling interest holder | - | (11) | (30) | |||||||||
Capital issuance costs | (4) | (7) | (2) | |||||||||
Short-term and credit facility borrowings, net | 100 | - | (100) | |||||||||
Money pool borrowings, net | - | (80) | 26 | |||||||||
Redemptions of long-term debt | (200) | - | - | |||||||||
Issuances of long-term debt | - | 249 | 300 | |||||||||
Notes payable – affiliates | (176) | 31 | (27) | |||||||||
Capital contribution from parent | 29 | - | - | |||||||||
Net cash provided by (used in) financing activities | (251) | 139 | (54) | |||||||||
Net change in cash and cash equivalents | - | 3 | 1 | |||||||||
Cash and cash equivalents at beginning of year | 6 | 3 | 2 | |||||||||
Cash and cash equivalents at end of year | $ | 6 | $ | 6 | $ | 3 | ||||||
Cash Paid During the Year: | ||||||||||||
Interest (net of $6, $12, and $10 capitalized, respectively) | $ | 77 | $ | 58 | $ | 51 | ||||||
Income taxes, net | 1 | 74 | 152 | |||||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Common Stock | $ | - | $ | - | $ | - | ||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 620 | 620 | 620 | |||||||||
Capital contribution from parent | 29 | - | - | |||||||||
Other paid-in capital, end of year | 649 | 620 | 620 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 432 | 315 | 250 | |||||||||
Net income (loss) attributable to Ameren Energy Generating Company | (39) | 160 | 286 | |||||||||
Common stock dividends | - | (43) | (221) | |||||||||
Retained earnings, end of year | 393 | 432 | 315 | |||||||||
Accumulated Other Comprehensive Loss: | ||||||||||||
Derivative financial instruments, beginning of year | (6) | (6) | (1) | |||||||||
Change in derivative financial instruments | - | - | (5) | |||||||||
Derivative financial instruments, end of year | (6) | (6) | (6) | |||||||||
Deferred retirement benefit costs, beginning of year | (42) | (61) | (12) | |||||||||
Change in deferred retirement benefit costs | 4 | 19 | (49) | |||||||||
Deferred retirement benefit costs, end of year | (38) | (42) | (61) | |||||||||
Total accumulated other comprehensive loss, end of year | (44) | (48) | (67) | |||||||||
Total Ameren Energy Generating Company Stockholder’s Equity | $ | 998 | $ | 1,004 | $ | 868 | ||||||
Noncontrolling Interest: | ||||||||||||
Beginning of year | 9 | 16 | 24 | |||||||||
Net income attributable to noncontrolling interest holder | 3 | 2 | 28 | |||||||||
Dividends paid to noncontrolling interest holder | - | (11) | (30) | |||||||||
Other comprehensive income (loss) attributable to noncontrolling interest holder | (1) | 2 | (6) | |||||||||
Noncontrolling interest, end of year | 11 | 9 | 16 | |||||||||
Total Equity | $ | 1,009 | $ | 1,013 | $ | 884 | ||||||
Comprehensive Income (Loss), Net of Taxes: | ||||||||||||
Net income (loss) | $ | (36) | $ | 162 | $ | 314 | ||||||
Reclassification adjustments for derivative gains included in net income, net of income taxes of $-, $-, and $3, respectively | - | - | (5) | |||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $5, $12, and $(29), respectively | 3 | 21 | (55) | |||||||||
Total Comprehensive Income (Loss), Net of Taxes | $ | (33) | $ | 183 | $ | 254 | ||||||
Comprehensive income attributable to noncontrolling interest holder | 2 | 4 | 22 | |||||||||
Total Comprehensive Income (Loss) Attributable to Ameren Energy Generating Company, Net of Taxes | $ | (35) | $ | 179 | $ | 232 | ||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY
AMEREN ILLINOIS COMPANY (Consolidated)
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2010
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.
| Ÿ | UE, |
| Ÿ | AIC, or Ameren Illinois Company, which does business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. AIC was created by the merger of
|
| Ÿ | Genco, or Ameren Energy Generating Company, operates a
|
in March 2000. Genco’s coal, natural gas and oil-fired electric
|
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger, pursuant to the terms of the agreement, dated as of April 13, 2010. Upon consummation of the AIC Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The AIC Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in AIC included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. AIC accounted for the AERG distribution as a spinoff. AIC transferred AERG to Ameren based on AERG’s carrying value. AIC determined that the operating results of AERG qualified for discontinued operations presentation; therefore, AIC has segregated AERG’s operating results and presented them separately as discontinued operations for all periods presented prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operation remain classified as continuing operations. See Note 16 – Corporate Reorganization and Discontinued Operations for additional information.
Ameren has various other subsidiaries responsible for the marketing of power, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. Effective January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior-period financial statements to be
retrospectively combined for all periods presented. Consequently, Genco’s prior-period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco. Ameren and Genco consolidate EEI for financial reporting purposes. See Note 14 – Related Party Transactions for additional information.
The financial statements of Ameren, AIC and Genco are prepared on a consolidated basis. UE does not have subsidiaries and therefore its financial statements are not consolidated. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
At December 31, 2010 and 2009, Ameren had immaterial investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership. Ameren has a variable interest in these investments as a limited partner. Ameren is not the primary beneficiary of these investments because Ameren does not have the power to direct matters that most significantly impact the activities of these VIE. The maximum exposure to loss as a result of these variable interests is limited to the investments in these partnerships. Ameren uses the equity method of accounting for its investments in these partnerships. See Note 14 – Related Party Transactions for information about AIC’s variable interest in ATXI.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires that Ameren management make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, the NRC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE and AIC defer certain costs as assets pursuant to actions of rate regulators or the expected ability to recover such costs in rates charged to customers. UE and AIC also defer certain amounts as liabilities pursuant to actions of rate regulators or the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on regulatory assets and liabilities. In addition, other costs that UE and AIC expect to recover from customers are also recorded as construction work in progress and property and plant, net. See Note 3 – Property and Plant, Net.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. AIC has a rate mechanism that adjusts rates for bad debt expense above or below those being collected in rates.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2010 and 2009:
| Ameren(a) | UE | AIC | Genco | |||||||||||||
2010: | ||||||||||||||||
Fuel(b) | $ | 255 | $ | 152 | $ | - | $ | 81 | ||||||||
Gas stored underground | 175 | 22 | 152 | - | ||||||||||||
Other materials and supplies | 277 | 167 | 46 | 49 | ||||||||||||
| $ | 707 | $ | 341 | $ | 198 | $ | 130 | |||||||||
2009: | ||||||||||||||||
Fuel(b) | $ | 315 | $ | 154 | $ | - | $ | 123 | ||||||||
Gas stored underground | 183 | 22 | 161 | - | ||||||||||||
Other materials and supplies | 284 | 170 | 51 | 47 | ||||||||||||
| $ | 782 | $ | 346 | $ | 212 | $ | 170 | |||||||||
| (a) | Includes amounts for Ameren registrant and |
| (b) | Consists of coal, oil, paint, propane, and tire chips. |
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Interest during construction is capitalized as a cost of merchant generation assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred by our merchant generation operations that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 – Property and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2010, 2009 and 2008 ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, as is the utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The following table presents the annual allowance for funds used during construction rates that were utilized during 2010, 2009 and 2008:
| 2010 | 2009 | 2008 | ||||||||||
Ameren | 8% - 9% | 6% - 9% | 3% - 7% | |||||||||
UE | 8 | 6 | 7 | |||||||||
AIC | 9 | 9 | 3 | |||||||||
Goodwill and Intangible Assets
Goodwill.Goodwill represents the excess of the purchase price of an acquisition over the fair value of the
net assets acquired. As of December 31, 2010, Ameren’s and AIC’s goodwill related to its acquisition of IP in 2004 and its acquisition of CILCORP in 2003.
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Ameren and Genco conducted an interim goodwill impairment test in the third quarter of 2010. That test resulted in the elimination of all goodwill associated with the Merchant Generation segment at Ameren ($420 million) and Genco ($65 million). This goodwill was associated with the acquisition of CILCORP and Medina Valley in 2003 and an additional 20% interest in EEI in 2004. See Note 17 –Goodwill and Other Asset Impairments for additional information.
Intangible Assets.We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s and Genco’s intangible assets at December 31, 2010, and 2009, consisted of emission allowances. During 2010, Ameren and Genco recorded a noncash pretax impairment charge relating to SO2 emission allowances of $68 million and $41 million, respectively. UE recorded a $23 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability related to the SO2 emission allowances, which had no impact to earnings. See Note 17 – Goodwill and Other Asset Impairments for additional information about the asset impairment charges recorded during 2010. See also Note 15 – Commitments and Contingencies for additional information on emission allowances.
The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were recorded as intangible assets at December 31, 2010. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.
| SO2 and NOx in tons | SO2(a) | NOx(b) | Book Value(c) | |||||||||
Ameren(d) | 3,061,914 | 21,284 | $ | 7 | ||||||||
UE | 1,587,663 | 15,850 | 2 | |||||||||
Genco | 1,102,744 | 5,139 | 3 | |||||||||
| (a) | Vintages are from 2010 to 2020. Each company possesses additional allowances for use in
|
| (b) | Vintage is 2010 and the |
| (c) | The book value represents SO2 and
|
| (d) | Includes amounts for Ameren registrants and nonregistrant subsidiaries. |
The following table presents amortization expense recorded in connection with the use of emission allowances, net of gains and losses from emission allowance sales, for Ameren, UE and Genco during the years ended December 31, 2010, 2009, and 2008.The table below does not include the intangible asset impairment charges referenced above.
| 2010 | 2009 | 2008 | ||||||||||
Ameren(a) | $ | 21 | $ | 29 | $ | 32 | ||||||
UE | (b | ) | - | - | ||||||||
Genco | 18 | 24 | 26 | |||||||||
| (a) | Includes allowances consumed that were recorded through purchase
|
| (b) | Less than $1 million. |
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value. In the period in which we determine an asset meets the held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. During 2010, Ameren and Genco recorded pretax asset impairment charges of $101 million and $64 million respectively, to reduce the carrying value of certain generating facilities to their estimated fair value. See Note 17 – Goodwill and Other Asset Impairments for information about Ameren and Genco’s impairments.
Investments
Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which UE believes would be recovered in electric rates paid by its customers. Accordingly, Ameren and UE recognize a regulatory asset on their balance sheets for losses on investments held in the nuclear decommissioning trust fund. See Note 9 – Nuclear Decommissioning Trust Fund Investments for additional information.
Excise Taxes
Excise taxes imposed on us are reflected on Missouri electric, Missouri natural gas, and Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses – Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on
the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses – Taxes Other than Income Taxes for the years ended 2009, 2008 and 2007:
| 2009 | 2008 | 2007 | |||||||
Ameren | $ | 168 | $ | 172 | $ | 166 | |||
UE | 112 | 109 | 110 | ||||||
CIPS | 15 | 16 | 15 | ||||||
CILCO | 11 | 13 | 11 | ||||||
IP | 30 | 34 | 30 | ||||||
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are calculated based on statutory tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded because of decreases in the statutory rate, were credited to a regulatory liability. A regulatory asset has been established to recognize the probable future recovery in rates of future income taxes resulting principally from the reversal of allowance for funds used during construction, that is, equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of the authoritative accounting provisions for income taxes.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 – Income Taxes.
UE, CIPS, Genco, CILCO, and IP are parties to a tax sharing agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax sharing agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution of capital to the party receiving the benefit.
Noncontrolling Interests
Ameren’s noncontrolling interests compriseTotal equity
TOTAL LIABILITIES AND EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income | $ | 151 | $ | 624 | $ | 644 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Loss on goodwill and other impairments | 589 | 7 | 14 | |||||||||
Net mark-to-market gain on derivatives | (15) | (23) | (3) | |||||||||
Depreciation and amortization | 783 | 748 | 705 | |||||||||
Amortization of nuclear fuel | 54 | 53 | 37 | |||||||||
Amortization of debt issuance costs and premium/discounts | 23 | 25 | 20 | |||||||||
Deferred income taxes and investment tax credits, net | 302 | 402 | 167 | |||||||||
Allowance for equity funds used during construction | (52) | (36) | (28) | |||||||||
Other | 40 | 17 | 14 | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | (85) | 21 | 12 | |||||||||
Materials and supplies | 78 | 67 | (100) | |||||||||
Accounts and wages payable | 27 | (42) | 57 | |||||||||
Taxes accrued | 9 | - | (30) | |||||||||
Assets, other | (109) | (66) | 83 | |||||||||
Liabilities, other | 71 | 99 | 110 | |||||||||
Pension and other postretirement benefits | (5) | (9) | (4) | |||||||||
Counterparty collateral, net | (73) | (17) | (25) | |||||||||
Taum Sauk insurance recoveries, net of costs | 54 | 107 | (149) | |||||||||
Net cash provided by operating activities | 1,842 | 1,977 | 1,524 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (1,031) | (1,704) | (1,896) | |||||||||
Nuclear fuel expenditures | (90) | (80) | (173) | |||||||||
Purchases of securities – nuclear decommissioning trust fund | (271) | (383) | (520) | |||||||||
Sales of securities – nuclear decommissioning trust fund | 256 | 380 | 497 | |||||||||
Other | 24 | (2) | (5) | |||||||||
Net cash used in investing activities | (1,112) | (1,789) | (2,097) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | (368) | (338) | (534) | |||||||||
Dividends paid to noncontrolling interest holders | (8) | (21) | (40) | |||||||||
Capital issuance costs | (15) | (65) | (12) | |||||||||
Short-term and credit facility borrowings, net | (121) | (324) | (298) | |||||||||
Redemptions, repurchases, and maturities: | ||||||||||||
Long-term debt | (310) | (631) | (842) | |||||||||
Preferred stock | (52) | - | (16) | |||||||||
Issuances: | ||||||||||||
Common stock | 80 | 634 | 154 | |||||||||
Long-term debt | - | 1,021 | 1,879 | |||||||||
Generator advances received for construction, net of repayments | (13) | 66 | 19 | |||||||||
Net cash provided by (used in) financing activities | (807) | 342 | 310 | |||||||||
Net change in cash and cash equivalents | (77) | 530 | (263) | |||||||||
Cash and cash equivalents at beginning of year | 622 | 92 | 355 | |||||||||
Cash and cash equivalents at end of year | $ | 545 | $ | 622 | $ | 92 | ||||||
Cash Paid (Refunded) During the Year: | ||||||||||||
Interest (net of $34, $40, and $41 capitalized, respectively) | $ | 494 | $ | 485 | $ | 409 | ||||||
Income taxes, net | (92) | 9 | 106 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Common Stock: | ||||||||||||
Beginning of year | $ | 2 | $ | 2 | $ | 2 | ||||||
Shares issued | - | - | - | |||||||||
Common stock, end of year | 2 | 2 | 2 | |||||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 5,412 | 4,780 | 4,604 | |||||||||
Shares issued (less issuance costs of $-, $17, and $-, respectively) | 80 | 617 | 154 | |||||||||
Stock-based compensation cost | 14 | 15 | 22 | |||||||||
Regulatory recovery of prior-period common stock issuance costs | 14 | - | - | |||||||||
Other paid-in capital, end of year | 5,520 | 5,412 | 4,780 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 2,455 | 2,181 | 2,110 | |||||||||
Net income attributable to Ameren Corporation | 139 | 612 | 605 | |||||||||
Dividends | (368) | (338) | (534) | |||||||||
Other | (1) | - | - | |||||||||
Retained earnings, end of year | 2,225 | 2,455 | 2,181 | |||||||||
Accumulated Other Comprehensive Income (Loss): | ||||||||||||
Derivative financial instruments, beginning of year | 10 | 48 | 9 | |||||||||
Change in derivative financial instruments | (10) | (38) | 39 | |||||||||
Derivative financial instruments, end of year | - | 10 | 48 | |||||||||
Deferred retirement benefit costs, beginning of year | (23) | (43) | 25 | |||||||||
Change in deferred retirement benefit costs | 6 | 20 | (68) | |||||||||
Deferred retirement benefit costs, end of year | (17) | (23) | (43) | |||||||||
Total accumulated other comprehensive income (loss), end of year | (17) | (13) | 5 | |||||||||
Total Ameren Corporation Stockholders’ Equity | $ | 7,730 | $ | 7,856 | $ | 6,968 | ||||||
Noncontrolling Interests: | ||||||||||||
Beginning of year | 204 | 211 | 218 | |||||||||
Net income attributable to noncontrolling interest holders | 12 | 12 | 39 | |||||||||
Dividends paid to noncontrolling interest holders | (8) | (21) | (40) | |||||||||
Redemptions of preferred stock | (52) | - | - | |||||||||
Other | (2) | 2 | (6) | |||||||||
Noncontrolling interests, end of year | 154 | 204 | 211 | |||||||||
Total Equity | $ | 7,884 | $ | 8,060 | $ | 7,179 | ||||||
Comprehensive Income, Net of Taxes: | ||||||||||||
Net income | $ | 151 | $ | 624 | $ | 644 | ||||||
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $(1), $78, and $65, respectively | (2) | 103 | 116 | |||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $5, $82, and $43, respectively | (8) | (112) | (77) | |||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $-, $18, and $-, respectively | - | (29) | - | |||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $6, $22, and $(45), respectively | 4 | 22 | (75) | |||||||||
Total Comprehensive Income, Net of Taxes | $ | 145 | $ | 608 | $ | 608 | ||||||
Comprehensive income attributable to noncontrolling interests | 10 | 14 | 33 | |||||||||
Total Comprehensive Income Attributable to Ameren Corporation, Net of Taxes | $ | 135 | $ | 594 | $ | 575 | ||||||
| Common stock shares at beginning of year | 237.4 | 212.3 | 208.3 | |||||||||
Shares issued | 3.0 | 25.1 | 4.0 | |||||||||
| Common stock shares at end of year | 240.4 | 237.4 | 212.3 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Operating Revenues: | ||||||||||||
Electric | $ | 3,030 | $ | 2,700 | $ | 2,756 | ||||||
Gas | 166 | 170 | 201 | |||||||||
Other | 1 | 4 | 3 | |||||||||
Total operating revenues | 3,197 | 2,874 | 2,960 | |||||||||
Operating Expenses: | ||||||||||||
Fuel | 635 | 593 | 672 | |||||||||
Purchased power | 162 | 124 | 160 | |||||||||
Gas purchased for resale | 91 | 97 | 123 | |||||||||
Other operations and maintenance | 931 | 880 | 922 | |||||||||
Depreciation and amortization | 382 | 357 | 329 | |||||||||
Taxes other than income taxes | 285 | 257 | 240 | |||||||||
Total operating expenses | 2,486 | 2,308 | 2,446 | |||||||||
Operating Income | 711 | 566 | 514 | |||||||||
Other Income and Expenses: | ||||||||||||
Miscellaneous income | 83 | 63 | 62 | |||||||||
Miscellaneous expense | 13 | 7 | 9 | |||||||||
Total other income | 70 | 56 | 53 | |||||||||
Interest Charges | 213 | 229 | 193 | |||||||||
Income Before Income Taxes and Equity in Income of Unconsolidated Investment | 568 | 393 | 374 | |||||||||
Income Taxes | 199 | 128 | 134 | |||||||||
Income Before Equity in Income of Unconsolidated Investment | 369 | 265 | 240 | |||||||||
Equity in Income of Unconsolidated Investment, Net of Taxes | - | - | 11 | |||||||||
Net Income | 369 | 265 | 251 | |||||||||
Preferred Stock Dividends | 5 | 6 | 6 | |||||||||
Net Income Available to Common Stockholder | $ | 364 | $ | 259 | $ | 245 | ||||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
BALANCE SHEET
(In millions, except per share amounts)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 202 | $ | 267 | ||||
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $6, respectively) | 217 | 154 | �� | |||||
Accounts receivable – affiliates | 6 | 22 | ||||||
Unbilled revenue | 159 | 127 | ||||||
Miscellaneous accounts and notes receivable | 116 | 199 | ||||||
Materials and supplies | 341 | 346 | ||||||
Current regulatory assets | 179 | 63 | ||||||
Other current assets | 55 | 50 | ||||||
Total current assets | 1,275 | 1,228 | ||||||
Property and Plant, Net | 9,775 | 9,585 | ||||||
Investments and Other Assets: | ||||||||
Nuclear decommissioning trust fund | 337 | 293 | ||||||
Intangible assets | 2 | 35 | ||||||
Regulatory assets | 694 | 683 | ||||||
Other assets | 421 | 395 | ||||||
Total investments and other assets | 1,454 | 1,406 | ||||||
TOTAL ASSETS | $ | 12,504 | $ | 12,219 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities: | ||||||||
Current maturities of long-term debt | $ | 5 | $ | 4 | ||||
Accounts and wages payable | 326 | 336 | ||||||
Accounts payable – affiliates | 75 | 132 | ||||||
Taxes accrued | 76 | 21 | ||||||
Interest accrued | 63 | 63 | ||||||
Current accumulated deferred income taxes, net | 43 | 12 | ||||||
Other current liabilities | 112 | 115 | ||||||
Total current liabilities | 700 | 683 | ||||||
Long-term Debt, Net | 3,949 | 4,018 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Accumulated deferred income taxes, net | 1,908 | 1,660 | ||||||
Accumulated deferred investment tax credits | 78 | 79 | ||||||
Regulatory liabilities | 766 | 865 | ||||||
Asset retirement obligations | 363 | 331 | ||||||
Pension and other postretirement benefits | 369 | 400 | ||||||
Other deferred credits and liabilities | 218 | 126 | ||||||
Total deferred credits and other liabilities | 3,702 | 3,461 | ||||||
Commitments and Contingencies (Notes 2, 10, 14 and 15) | ||||||||
Stockholders’ Equity: | ||||||||
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | 511 | ||||||
Other paid-in capital, principally premium on common stock | 1,555 | 1,555 | ||||||
Preferred stock not subject to mandatory redemption | 80 | 113 | ||||||
Retained earnings | 2,007 | 1,878 | ||||||
Total stockholders’ equity | 4,153 | 4,057 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 12,504 | $ | 12,219 | ||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income | $ | 369 | $ | 265 | $ | 251 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Net mark-to-market (gain) loss on derivatives | (1) | (29) | 29 | |||||||||
Depreciation and amortization | 382 | 357 | 329 | |||||||||
Amortization of nuclear fuel | 54 | 53 | 37 | |||||||||
Amortization of debt issuance costs and premium/discounts | 4 | 10 | 6 | |||||||||
Deferred income taxes and investment tax credits, net | 228 | 276 | 89 | |||||||||
Allowance for equity funds used during construction | (50) | (33) | (27) | |||||||||
Other | 20 | - | (5) | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | (56) | (58) | 60 | |||||||||
Materials and supplies | 7 | (2) | (32) | |||||||||
Accounts and wages payable | (17) | 16 | (89) | |||||||||
Taxes accrued | 55 | 1 | (61) | |||||||||
Assets, other | (145) | (58) | 42 | |||||||||
Liabilities, other | 77 | 69 | 63 | |||||||||
Pension and other postretirement benefits | (3) | (2) | - | |||||||||
Taum Sauk insurance recoveries, net of costs | 54 | 107 | (149) | |||||||||
Net cash provided by operating activities | 978 | 972 | 543 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (608) | (872) | (874) | |||||||||
Nuclear fuel expenditures | (90) | (80) | (173) | |||||||||
Proceeds from intercompany note receivable | - | - | 36 | |||||||||
Purchases of securities – nuclear decommissioning trust fund | (271) | (383) | (520) | |||||||||
Sales of securities – nuclear decommissioning trust fund | 256 | 380 | 497 | |||||||||
Other | 7 | - | 1 | |||||||||
Net cash used in investing activities | (706) | (955) | (1,033) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | (235) | (175) | (264) | |||||||||
Dividends on preferred stock | (5) | (6) | (6) | |||||||||
Capital issuance costs | (4) | (14) | (5) | |||||||||
Short-term debt, net | - | (251) | 169 | |||||||||
Intercompany note payable – Ameren, net | - | (92) | 92 | |||||||||
Redemptions, repurchases, and maturities: | ||||||||||||
Long-term debt | (70) | (4) | (382) | |||||||||
Preferred stock | (33) | - | - | |||||||||
Issuances of long-term debt | - | 349 | 699 | |||||||||
Capital contribution from parent | - | 436 | - | |||||||||
Other | 10 | 7 | 2 | |||||||||
Net cash provided by (used in) financing activities | (337) | 250 | 305 | |||||||||
Net change in cash and cash equivalents | (65) | 267 | (185) | |||||||||
Cash and cash equivalents at beginning of year | 267 | - | 185 | |||||||||
Cash and cash equivalents at end of year | $ | 202 | $ | 267 | $ | - | ||||||
Cash Paid (Refunded) During the Year: | ||||||||||||
Interest (net of $26, $23, and $19 capitalized, respectively) | $ | 213 | $ | 212 | $ | 177 | ||||||
Income taxes, net | (106) | (208) | 130 | |||||||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Common Stock | $ | 511 | $ | 511 | $ | 511 | ||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 1,555 | 1,119 | 1,119 | |||||||||
Capital contribution from parent | - | 436 | - | |||||||||
Other paid-in capital, end of year | 1,555 | 1,555 | 1,119 | |||||||||
Preferred Stock Not Subject to Mandatory Redemption: | ||||||||||||
Beginning balance | 113 | 113 | 113 | |||||||||
Redemptions | (33) | - | - | |||||||||
Preferred stock not subject to mandatory redemption, end of year | 80 | 113 | 113 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 1,878 | 1,794 | 1,855 | |||||||||
Net income | 369 | 265 | 251 | |||||||||
Common stock dividends | (235) | (175) | (264) | |||||||||
Preferred stock dividends | (5) | (6) | (6) | |||||||||
Dividend-in-kind to Ameren | - | - | (42) | |||||||||
Retained earnings, end of year | 2,007 | 1,878 | 1,794 | |||||||||
Accumulated Other Comprehensive Income: | ||||||||||||
Beginning of year | - | 25 | 3 | |||||||||
Change in derivative financial instruments | - | (25) | 22 | |||||||||
Accumulated other comprehensive income, end of year | - | - | 25 | |||||||||
Total Stockholders’ Equity | $ | 4,153 | $ | 4,057 | $ | 3,562 | ||||||
Comprehensive Income, Net of Taxes: | ||||||||||||
Net income | $ | 369 | $ | 265 | $ | 251 | ||||||
Unrealized net gain on derivative hedging instruments, net of income taxes of $-, $11, and $22, respectively | - | 17 | 36 | |||||||||
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $-, $8, and $9, respectively | - | (13) | (14) | |||||||||
Reclassification adjustment due to implementation of FAC, net of income taxes of $-, $18, and $-, respectively | - | (29) | - | |||||||||
Total Comprehensive Income, Net of Taxes | $ | 369 | $ | 240 | $ | 273 | ||||||
The accompanying notes as they relate to UE are an integral part of these financial statements.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Operating Revenues: | ||||||||||||
Electric | $ | 2,061 | $ | 1,965 | $ | 2,242 | ||||||
Gas | 953 | 1,015 | 1,265 | |||||||||
Other | - | 4 | 1 | |||||||||
Total operating revenues | 3,014 | 2,984 | 3,508 | |||||||||
Operating Expenses: | ||||||||||||
Purchased power | 965 | 1,048 | 1,405 | |||||||||
Gas purchased for resale | 578 | 642 | 914 | |||||||||
Other operations and maintenance | 635 | 590 | 653 | |||||||||
Depreciation and amortization | 210 | 216 | 219 | |||||||||
Taxes other than income taxes | 128 | 125 | 126 | |||||||||
Total operating expenses | 2,516 | 2,621 | 3,317 | |||||||||
Operating Income | 498 | 363 | 191 | |||||||||
Other Income and Expenses: | ||||||||||||
Miscellaneous income | 7 | 12 | 23 | |||||||||
Miscellaneous expense | 13 | 10 | 12 | |||||||||
Total other income (expense) | (6) | 2 | 11 | |||||||||
Interest Charges | 143 | 153 | 145 | |||||||||
Income Before Income Taxes | 349 | 212 | 57 | |||||||||
Income Taxes | 137 | 79 | 16 | |||||||||
Income from Continuing Operations | 212 | 133 | 41 | |||||||||
Income from Discontinued Operations, net of tax | 40 | 114 | 52 | |||||||||
Net Income | 252 | 247 | 93 | |||||||||
Preferred Stock Dividends | 4 | 6 | 6 | |||||||||
Net Income Available to Common Stockholder | $ | 248 | $ | 241 | $ | 87 | ||||||
| (a) | Prior period has been adjusted to reflect the |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET
(In millions)
| December 31, | ||||||||
| 2010 | 2009(a) | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 322 | $ | 306 | ||||
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $17, respectively) | 230 | 199 | ||||||
Accounts and notes receivable – affiliates | 73 | 105 | ||||||
Unbilled revenue | 205 | 189 | ||||||
Miscellaneous accounts and notes receivable | 44 | 51 | ||||||
Materials and supplies | 198 | 212 | ||||||
Current regulatory assets | 260 | 174 | ||||||
Other current assets | 106 | 63 | ||||||
Current assets of discontinued operations | - | 112 | ||||||
Total current assets | 1,438 | 1,411 | ||||||
Property and Plant, Net | 4,576 | 4,354 | ||||||
Investments and Other Assets: | ||||||||
Intercompany tax receivable – Genco | 72 | 82 | ||||||
Goodwill | 411 | 411 | ||||||
Regulatory assets | 743 | 944 | ||||||
Other assets | 166 | 91 | ||||||
Noncurrent assets of discontinued operations | - | 1,005 | ||||||
Total investments and other assets | 1,392 | 2,533 | ||||||
TOTAL ASSETS | $ | 7,406 | $ | 8,298 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities: | ||||||||
Current maturities of long-term debt | $ | 150 | $ | - | ||||
Accounts and wages payable | 182 | 192 | ||||||
Accounts payable – affiliates | 82 | 179 | ||||||
Taxes accrued | 26 | 15 | ||||||
Customer deposits | 83 | 85 | ||||||
Mark-to-market derivative liabilities | 82 | 38 | ||||||
Mark-to-market derivative liabilities – affiliates | 172 | 127 | ||||||
Environmental remediation | 72 | 80 | ||||||
Current regulatory liabilities | 76 | 57 | ||||||
Other current liabilities | 90 | 132 | ||||||
Current liabilities of discontinued operations | - | 334 | ||||||
Total current liabilities | 1,015 | 1,239 | ||||||
Long-term Debt, Net | 1,657 | 1,847 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Accumulated deferred income taxes, net | 724 | 554 | ||||||
Accumulated deferred investment tax credits | 8 | 10 | ||||||
Regulatory liabilities | 553 | 391 | ||||||
Pension and other postretirement benefits | 413 | 471 | ||||||
Other deferred credits and liabilities | 460 | 483 | ||||||
Noncurrent liabilities of discontinued operations | - | 231 | ||||||
Total deferred credits and other liabilities | 2,158 | 2,140 | ||||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||||
Stockholders’ Equity: | ||||||||
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | - | - | ||||||
Other paid-in capital | 1,952 | 2,223 | ||||||
Preferred stock not subject to mandatory redemption | 62 | 115 | ||||||
Retained earnings | 542 | 709 | ||||||
Accumulated other comprehensive income | 20 | 25 | ||||||
Total stockholders’ equity | 2,576 | 3,072 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 7,406 | $ | 8,298 | ||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income | $ | 252 | $ | 247 | $ | 93 | ||||||
Income from discontinued operations, net of tax | (40) | (114) | (52) | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 210 | 212 | 209 | |||||||||
Amortization of debt issuance costs and premium/discounts | 10 | 9 | 11 | |||||||||
Deferred income taxes and investment tax credits, net | 161 | 72 | 22 | |||||||||
Other | 2 | (11) | 6 | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | (41) | 142 | (25) | |||||||||
Materials and supplies | 14 | 85 | (37) | |||||||||
Accounts and wages payable | (44) | (3) | 74 | |||||||||
Taxes accrued | 11 | (11) | 11 | |||||||||
Assets, other | (76) | 74 | (35) | |||||||||
Liabilities, other | 32 | 11 | 72 | |||||||||
Pension and other postretirement benefits | (7) | 5 | (20) | |||||||||
Operating cash flows provided by discontinued operations | 113 | 141 | 159 | |||||||||
Net cash provided by operating activities | 597 | 859 | 488 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (286) | (356) | (345) | |||||||||
Advances to ATXI for construction | (10) | (47) | (13) | |||||||||
Proceeds from intercompany note receivable – Genco | 45 | 42 | 39 | |||||||||
Other | - | - | (2) | |||||||||
Capital expenditures of discontinued operations | (6) | (91) | (256) | |||||||||
Net cash used in investing activities | (257) | (452) | (577) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | (133) | (98) | (60) | |||||||||
Dividends on preferred stock | (4) | (6) | (6) | |||||||||
Capital issuance costs | (4) | (13) | (6) | |||||||||
Short-term and credit facility borrowings, net | - | (62) | (353) | |||||||||
Redemptions, repurchases, and maturities: | ||||||||||||
Long-term debt | (40) | (250) | (460) | |||||||||
Preferred stock | (19) | - | (16) | |||||||||
Issuances of long-term debt | - | - | 880 | |||||||||
Generator advances for construction received (refunded), net of repayments | (23) | 56 | 20 | |||||||||
Capital contribution from parent | 6 | 272 | - | |||||||||
Net financing activities provided by (used in) discontinued operations | (107) | (50) | 104 | |||||||||
Net cash provided by (used in) financing activities | (324) | (151) | 103 | |||||||||
Net change in cash and cash equivalents | 16 | 256 | 14 | |||||||||
Cash and cash equivalents at beginning of year | 306 | 50 | 36 | |||||||||
Cash and cash equivalents at end of year | $ | 322 | $ | 306 | $ | 50 | ||||||
Cash Paid (Refunded) During the Year: | ||||||||||||
Interest (net of $1, $3 and $10 capitalized, respectively) | $ | 160 | $ | 167 | $ | 131 | ||||||
Income taxes, net | (39) | 129 | (80) | |||||||||
Noncash investing activity – asset transfer from ATXI | 7 | 29 | - | |||||||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Common Stock | $ | - | $ | -�� | $ | - | ||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 2,223 | 1,951 | 1,951 | |||||||||
Capital contribution from parent | 6 | 272 | - | |||||||||
Contribution of Ameren owned preferred stock without consideration | 33 | - | - | |||||||||
Transfer of AERG to parent (Notes 1 and 16) | (310) | - | - | |||||||||
Other paid-in capital, end of year | 1,952 | 2,223 | 1,951 | |||||||||
Preferred Stock Not Subject to Mandatory Redemption: | ||||||||||||
Beginning balance | 115 | 115 | 115 | |||||||||
Redemptions | (19) | - | - | |||||||||
Contribution of Ameren owned preferred stock without consideration | (33) | - | - | |||||||||
Other | (1) | - | - | |||||||||
Preferred stock not subject to mandatory redemption, end of year | 62 | 115 | 115 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 709 | 566 | 539 | |||||||||
Net income | 252 | 247 | 93 | |||||||||
Common stock dividends | (133) | (98) | (60) | |||||||||
Preferred stock dividends | (4) | (6) | (6) | |||||||||
Transfer of AERG to parent (Notes 1 and 16) | (281) | - | - | |||||||||
Other | (1) | - | - | |||||||||
Retained earnings, end of year | 542 | 709 | 566 | |||||||||
Accumulated Other Comprehensive Income: | ||||||||||||
Deferred retirement benefit costs, beginning of year | 25 | 23 | 30 | |||||||||
Change in deferred retirement benefit costs | (4) | (4) | (1) | |||||||||
Change in accumulated other comprehensive income from discontinued operations | (1) | 6 | (6) | |||||||||
Deferred retirement benefit costs, end of year | 20 | 25 | 23 | |||||||||
Total accumulated other comprehensive income, end of year | 20 | 25 | 23 | |||||||||
Total Stockholders’ Equity | $ | 2,576 | $ | 3,072 | $ | 2,655 | ||||||
Comprehensive Income, Net of Taxes: | ||||||||||||
Net income | $ | 252 | $ | 247 | $ | 93 | ||||||
Pension and other postretirement activity, net of income taxes (benefit) of $(2), $(2), and $(1), respectively | (4) | (4) | (1) | |||||||||
Comprehensive income from discontinued operations | (1) | 6 | (6) | |||||||||
Total Comprehensive Income, Net of Taxes | $ | 247 | $ | 249 | $ | 86 | ||||||
| (a) | Prior period has been adjusted to reflect the AIC Merger as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to AIC are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME (LOSS)
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Operating Revenues | $ | 1,126 | $ | 1,148 | $ | 1,422 | ||||||
Operating Expenses: | ||||||||||||
Fuel | 522 | 415 | 509 | |||||||||
Coal contract settlement | - | - | (60) | |||||||||
Purchased power | 61 | 72 | 97 | |||||||||
Other operations and maintenance | 191 | 226 | 227 | |||||||||
Goodwill and other impairment losses | 170 | 6 | - | |||||||||
Depreciation and amortization | 98 | 81 | 75 | |||||||||
Taxes other than income taxes | 22 | 24 | 23 | |||||||||
Total operating expenses | 1,064 | 824 | 871 | |||||||||
Operating Income | 62 | 324 | 551 | |||||||||
Other Income and Expenses: | ||||||||||||
Miscellaneous income | 1 | 1 | 1 | |||||||||
Miscellaneous expense | 1 | 1 | 1 | |||||||||
Total other income | - | - | - | |||||||||
Interest Charges | 78 | 61 | 55 | |||||||||
Income (Loss) Before Income Taxes | (16) | 263 | 496 | |||||||||
Income Taxes | 20 | 101 | 182 | |||||||||
Net Income (Loss) | (36) | 162 | 314 | |||||||||
Less: Net Income Attributable to Noncontrolling Interest | 3 | 2 | 28 | |||||||||
Net Income (Loss) Attributable to Ameren Energy Generating Company | $ | (39) | $ | 160 | $ | 286 | ||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
| December 31, | ||||||||
| 2010 | 2009(a) | |||||||
| ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 6 | $ | 6 | ||||
Advances to money pool | 25 | 73 | ||||||
Accounts receivable – affiliates | 126 | 129 | ||||||
Miscellaneous accounts and notes receivable | 19 | 26 | ||||||
Materials and supplies | 130 | 170 | ||||||
Mark-to-market derivative assets | 26 | 22 | ||||||
Other current assets | 4 | 2 | ||||||
Total current assets | 336 | 428 | ||||||
Property and Plant, Net | 2,248 | 2,337 | ||||||
Investments and Other Assets: | ||||||||
Goodwill | - | 65 | ||||||
Intangible Assets | 3 | 62 | ||||||
Other Assets | 24 | 28 | ||||||
TOTAL ASSETS | $ | 2,611 | $ | 2,920 | ||||
| LIABILITIES AND EQUITY | ||||||||
Current Liabilities: | ||||||||
Current maturities of long-term debt | $ | - | $ | 200 | ||||
Current portion of note payable – AIC | - | 45 | ||||||
Note payable – Ameren | - | 131 | ||||||
Accounts and wages payable | 62 | 85 | ||||||
Accounts payable – affiliates | 23 | 40 | ||||||
Current portion of tax payable – AIC | 8 | 9 | ||||||
Taxes accrued | 20 | 17 | ||||||
Interest accrued | 13 | 13 | ||||||
Mark-to-market derivative liabilities | 9 | 12 | ||||||
Mark-to-market derivative liabilities – affiliates | 5 | 1 | ||||||
Current accumulated deferred income taxes, net | 13 | 26 | ||||||
Other current liabilities | 12 | 19 | ||||||
Total current liabilities | 165 | 598 | ||||||
Credit Facility Borrowings | 100 | - | ||||||
Long-term Debt, Net | 824 | 823 | ||||||
Deferred Credits and Other Liabilities: | ||||||||
Accumulated deferred income taxes, net | 253 | 216 | ||||||
Accumulated deferred investment tax credits | 3 | 4 | ||||||
Tax payable – AIC | 72 | 82 | ||||||
Asset retirement obligations | 74 | 60 | ||||||
Pension and other postretirement benefits | 88 | 89 | ||||||
Other deferred credits and liabilities | 23 | 35 | ||||||
Total deferred credits and other liabilities | 513 | 486 | ||||||
Commitments and Contingencies (Notes 2, 14 and 15) | ||||||||
Ameren Energy Generating Company Stockholder’s Equity: | ||||||||
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding | - | - | ||||||
Other paid-in capital | 649 | 620 | ||||||
Retained earnings | 393 | 432 | ||||||
Accumulated other comprehensive loss | (44) | (48) | ||||||
Total Ameren Energy Generating Company stockholder’s equity | 998 | 1,004 | ||||||
Noncontrolling Interest | 11 | 9 | ||||||
Total equity | 1,009 | 1,013 | ||||||
TOTAL LIABILITIES AND EQUITY | $ | 2,611 | $ | 2,920 | ||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Cash Flows From Operating Activities: | ||||||||||||
Net income (loss) | $ | (36) | $ | 162 | $ | 314 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Loss on goodwill and other impairments | 170 | 6 | - | |||||||||
Net mark-to-market (gain) loss on derivatives | (8) | (27) | 24 | |||||||||
Depreciation and amortization | 113 | 106 | 104 | |||||||||
Amortization of debt issuance costs and discounts | 3 | 2 | 1 | |||||||||
Deferred income taxes and investment tax credits, net | 19 | 64 | 22 | |||||||||
Other | 1 | - | (2) | |||||||||
Changes in assets and liabilities: | ||||||||||||
Receivables | 10 | (13) | (22) | |||||||||
Materials and supplies | 42 | (12) | (34) | |||||||||
Accounts and wages payable | (25) | (19) | 6 | |||||||||
Taxes accrued | 3 | - | 1 | |||||||||
Assets, other | 7 | 9 | 10 | |||||||||
Liabilities, other | (24) | (26) | (6) | |||||||||
Pension and other postretirement benefits | 5 | 1 | 3 | |||||||||
Net cash provided by operating activities | 280 | 253 | 421 | |||||||||
Cash Flows From Investing Activities: | ||||||||||||
Capital expenditures | (95) | (316) | (353) | |||||||||
Proceeds from sale of property interests | 18 | - | - | |||||||||
Money pool advances, net | 48 | (73) | - | |||||||||
Other | - | - | (13) | |||||||||
Net cash used in investing activities | (29) | (389) | (366) | |||||||||
Cash Flows From Financing Activities: | ||||||||||||
Dividends on common stock | - | (43) | (221) | |||||||||
Dividends paid to noncontrolling interest holder | - | (11) | (30) | |||||||||
Capital issuance costs | (4) | (7) | (2) | |||||||||
Short-term and credit facility borrowings, net | 100 | - | (100) | |||||||||
Money pool borrowings, net | - | (80) | 26 | |||||||||
Redemptions of long-term debt | (200) | - | - | |||||||||
Issuances of long-term debt | - | 249 | 300 | |||||||||
Notes payable – affiliates | (176) | 31 | (27) | |||||||||
Capital contribution from parent | 29 | - | - | |||||||||
Net cash provided by (used in) financing activities | (251) | 139 | (54) | |||||||||
Net change in cash and cash equivalents | - | 3 | 1 | |||||||||
Cash and cash equivalents at beginning of year | 6 | 3 | 2 | |||||||||
Cash and cash equivalents at end of year | $ | 6 | $ | 6 | $ | 3 | ||||||
Cash Paid During the Year: | ||||||||||||
Interest (net of $6, $12, and $10 capitalized, respectively) | $ | 77 | $ | 58 | $ | 51 | ||||||
Income taxes, net | 1 | 74 | 152 | |||||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
| December 31, | ||||||||||||
| 2010 | 2009(a) | 2008(a) | ||||||||||
Common Stock | $ | - | $ | - | $ | - | ||||||
Other Paid-in Capital: | ||||||||||||
Beginning of year | 620 | 620 | 620 | |||||||||
Capital contribution from parent | 29 | - | - | |||||||||
Other paid-in capital, end of year | 649 | 620 | 620 | |||||||||
Retained Earnings: | ||||||||||||
Beginning of year | 432 | 315 | 250 | |||||||||
Net income (loss) attributable to Ameren Energy Generating Company | (39) | 160 | 286 | |||||||||
Common stock dividends | - | (43) | (221) | |||||||||
Retained earnings, end of year | 393 | 432 | 315 | |||||||||
Accumulated Other Comprehensive Loss: | ||||||||||||
Derivative financial instruments, beginning of year | (6) | (6) | (1) | |||||||||
Change in derivative financial instruments | - | - | (5) | |||||||||
Derivative financial instruments, end of year | (6) | (6) | (6) | |||||||||
Deferred retirement benefit costs, beginning of year | (42) | (61) | (12) | |||||||||
Change in deferred retirement benefit costs | 4 | 19 | (49) | |||||||||
Deferred retirement benefit costs, end of year | (38) | (42) | (61) | |||||||||
Total accumulated other comprehensive loss, end of year | (44) | (48) | (67) | |||||||||
Total Ameren Energy Generating Company Stockholder’s Equity | $ | 998 | $ | 1,004 | $ | 868 | ||||||
Noncontrolling Interest: | ||||||||||||
Beginning of year | 9 | 16 | 24 | |||||||||
Net income attributable to noncontrolling interest holder | 3 | 2 | 28 | |||||||||
Dividends paid to noncontrolling interest holder | - | (11) | (30) | |||||||||
Other comprehensive income (loss) attributable to noncontrolling interest holder | (1) | 2 | (6) | |||||||||
Noncontrolling interest, end of year | 11 | 9 | 16 | |||||||||
Total Equity | $ | 1,009 | $ | 1,013 | $ | 884 | ||||||
Comprehensive Income (Loss), Net of Taxes: | ||||||||||||
Net income (loss) | $ | (36) | $ | 162 | $ | 314 | ||||||
Reclassification adjustments for derivative gains included in net income, net of income taxes of $-, $-, and $3, respectively | - | - | (5) | |||||||||
Pension and other postretirement activity, net of income taxes (benefit) of $5, $12, and $(29), respectively | 3 | 21 | (55) | |||||||||
Total Comprehensive Income (Loss), Net of Taxes | $ | (33) | $ | 183 | $ | 254 | ||||||
Comprehensive income attributable to noncontrolling interest holder | 2 | 4 | 22 | |||||||||
Total Comprehensive Income (Loss) Attributable to Ameren Energy Generating Company, Net of Taxes | $ | (35) | $ | 179 | $ | 232 | ||||||
| (a) | Prior period has been adjusted to include EEI as discussed in Note 1 – Summary of Significant Accounting Policies. |
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY
AMEREN ILLINOIS COMPANY (Consolidated)
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2010
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.
| Ÿ | UE, or Union Electric Company, which does business as Ameren Missouri, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 127,000 customers. |
| Ÿ | AIC, or Ameren Illinois Company, which does business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. AIC was created by the merger of CILCO and IP with and into CIPS. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. AIC supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3 million in an area of 40,000 square miles. AIC supplies electric service to 1.2 million customers and natural gas service to 811,000 customers. |
| Ÿ | Genco, or Ameren Energy Generating Company, operates a merchant electric generation business in Illinois and Missouri. Genco was incorporated in Illinois |
in March 2000. Genco’s coal, natural gas and oil-fired electric generating facilities, are expected to have capacity of 3,437, 1,553, and 169 megawatts, respectively, at the time of the 2011 peak summer electrical demand. |
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger, pursuant to the terms of the agreement, dated as of April 13, 2010. Upon consummation of the AIC Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The AIC Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in AIC included purchase accounting adjustments related to Ameren’s acquisition of CILCORP in 2003. AIC accounted for the AERG distribution as a spinoff. AIC transferred AERG to Ameren based on AERG’s carrying value. AIC determined that the operating results of AERG qualified for discontinued operations presentation; therefore, AIC has segregated AERG’s operating results and presented them separately as discontinued operations for all periods presented prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operation remain classified as continuing operations. See Note 16 – Corporate Reorganization and Discontinued Operations for additional information.
Ameren has various other subsidiaries responsible for the marketing of power, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. Effective January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco accounted for the transfer at the historical carrying value of the parent (Ameren) as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren’s historical cost basis in EEI included purchase accounting adjustments relating to Ameren’s acquisition of an additional 20% ownership interest in EEI in 2004. This transfer required Genco’s prior-period financial statements to be
retrospectively combined for all periods presented. Consequently, Genco’s prior-period consolidated financial statements reflect EEI as if it had been a subsidiary of Genco. Ameren and Genco consolidate EEI for financial reporting purposes. See Note 14 – Related Party Transactions for additional information.
The financial statements of Ameren, AIC and Genco are prepared on a consolidated basis. UE does not have subsidiaries and therefore its financial statements are not consolidated. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
At December 31, 2010 and 2009, Ameren had immaterial investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership. Ameren has a variable interest in these investments as a limited partner. Ameren is not the primary beneficiary of these investments because Ameren does not have the power to direct matters that most significantly impact the activities of these VIE. The maximum exposure to loss as a result of these variable interests is limited to the investments in these partnerships. Ameren uses the equity method of accounting for its investments in these partnerships. See Note 14 – Related Party Transactions for information about AIC’s variable interest in ATXI.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires that Ameren management make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, the NRC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE and AIC defer certain costs as assets pursuant to actions of rate regulators or the expected ability to recover such costs in rates charged to customers. UE and AIC also defer certain amounts as liabilities pursuant to actions of rate regulators or the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on regulatory assets and liabilities. In addition, other costs that UE and AIC expect to recover from customers are also recorded as construction work in progress and property and plant, net. See Note 3 – Property and Plant, Net.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. AIC has a rate mechanism that adjusts rates for bad debt expense above or below those being collected in rates.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2010 and 2009:
| Ameren(a) | UE | AIC | Genco | |||||||||||||
2010: | ||||||||||||||||
Fuel(b) | $ | 255 | $ | 152 | $ | - | $ | 81 | ||||||||
Gas stored underground | 175 | 22 | 152 | - | ||||||||||||
Other materials and supplies | 277 | 167 | 46 | 49 | ||||||||||||
| $ | 707 | $ | 341 | $ | 198 | $ | 130 | |||||||||
2009: | ||||||||||||||||
Fuel(b) | $ | 315 | $ | 154 | $ | - | $ | 123 | ||||||||
Gas stored underground | 183 | 22 | 161 | - | ||||||||||||
Other materials and supplies | 284 | 170 | 51 | 47 | ||||||||||||
| $ | 782 | $ | 346 | $ | 212 | $ | 170 | |||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| (b) | Consists of coal, oil, paint, propane, and tire chips. |
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Interest during construction is capitalized as a cost of merchant generation assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs incurred by our merchant generation operations that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 – Property and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2010, 2009 and 2008 ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, as is the utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The following table presents the annual allowance for funds used during construction rates that were utilized during 2010, 2009 and 2008:
| 2010 | 2009 | 2008 | ||||||||||
Ameren | 8% - 9% | 6% - 9% | 3% - 7% | |||||||||
UE | 8 | 6 | 7 | |||||||||
AIC | 9 | 9 | 3 | |||||||||
Goodwill and Intangible Assets
Goodwill.Goodwill represents the excess of the purchase price of an acquisition over the fair value of the
net assets acquired. As of December 31, 2010, Ameren’s and AIC’s goodwill related to its acquisition of IP in 2004 and its acquisition of CILCORP in 2003.
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Ameren and Genco conducted an interim goodwill impairment test in the third quarter of 2010. That test resulted in the elimination of all goodwill associated with the Merchant Generation segment at Ameren ($420 million) and Genco ($65 million). This goodwill was associated with the acquisition of CILCORP and Medina Valley in 2003 and an additional 20% interest in EEI in 2004. See Note 17 –Goodwill and Other Asset Impairments for additional information.
Intangible Assets.We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s and Genco’s intangible assets at December 31, 2010, and 2009, consisted of emission allowances. During 2010, Ameren and Genco recorded a noncash pretax impairment charge relating to SO2 emission allowances of $68 million and $41 million, respectively. UE recorded a $23 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability related to the SO2 emission allowances, which had no impact to earnings. See Note 17 – Goodwill and Other Asset Impairments for additional information about the asset impairment charges recorded during 2010. See also Note 15 – Commitments and Contingencies for additional information on emission allowances.
The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were recorded as intangible assets at December 31, 2010. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.
| SO2 and NOx in tons | SO2(a) | NOx(b) | Book Value(c) | |||||||||
Ameren(d) | 3,061,914 | 21,284 | $ | 7 | ||||||||
UE | 1,587,663 | 15,850 | 2 | |||||||||
Genco | 1,102,744 | 5,139 | 3 | |||||||||
| (a) | Vintages are from 2010 to 2020. Each company possesses additional allowances for use in periods beyond 2020. |
| (b) | Vintage is 2010 and the remaining unused prior years’ allowances. |
| (c) |
|
| (d) | Includes amounts for Ameren registrants and nonregistrant subsidiaries. |
The following table presents amortization expense recorded in connection with the use of emission allowances, net of gains and losses from emission allowance sales, for Ameren, UE and Genco during the years ended December 31, 2010, 2009, and 2008.The table below does not include the intangible asset impairment charges referenced above.
| 2010 | 2009 | 2008 | ||||||||||
Ameren(a) | $ | 21 | $ | 29 | $ | 32 | ||||||
UE | (b | ) | - | - | ||||||||
Genco | 18 | 24 | 26 | |||||||||
| (a) | Includes allowances consumed that were
|
| (b) | Less than $1 million. |
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the entity. This guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent
features in derivative agreements. The adoption of this guidance, effective for us in the first quarter of 2009, did not have a material impact on our results of operations, financial position, or liquidity because it required enhanced disclosure only. See Note 7 – Derivative Financial Instruments for additional information.
Employers’ Disclosures about Postretirement Benefit Plan Assets
In December 2008, the FASB issued authoritative guidance regarding additional disclosures related to pension and other postretirement benefit plan assets. Required additional disclosures include those related to the investment allocation decision-making process, the fair value of each major category of plan assets and the inputs and valuation techniques used to measure fair value and significant concentrations of risk within the plan assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value. In the period in which we determine an asset meets the held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. During 2010, Ameren and Genco recorded pretax asset impairment charges of $101 million and $64 million respectively, to reduce the carrying value of certain generating facilities to their estimated fair value. See Note 17 – Goodwill and Other Asset Impairments for information about Ameren and Genco’s impairments.
Investments
Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which UE believes would be recovered in electric rates paid by its customers. Accordingly, Ameren and UE recognize a regulatory asset on their balance sheets for losses on investments held in the nuclear decommissioning trust fund. See Note 9 – Nuclear Decommissioning Trust Fund Investments for additional information.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Unamortized Debt Discount, Premium, and Expense
Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.
Revenue
Operating Revenues
UE, AIC and Genco record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period.
Trading Activities
We present the revenues and costs associated with certain energy derivative contracts designated as trading on a net basis in Operating Revenues – Electric and Other.
Nuclear Fuel
UE’s cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and that cost is charged to expense.
Purchased Gas, Power and Fuel Rate-adjustment Mechanisms
Ameren’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs. See Note 2 – Rate and Regulatory Matters for the regulatory assets and liabilities recorded at December 31, 2010, and 2009, related to the rate-adjustment mechanisms discussed below.
In UE’s and AIC’s retail natural gas utility jurisdictions, changes in natural gas costs are generally reflected in billings to their natural gas utility customers through PGA clauses. The difference between actual natural gas costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.
In AIC’s retail electric utility jurisdictions, changes in purchased power costs are generally reflected in billings to their electric utility customers through pass-through rate-adjustment clauses. The difference between actual purchased power costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.
UE has an FAC that allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, greater or less than the amount set in base rates, subject to MoPSC prudency review. The differences between the cost of fuel incurred and the cost of fuel
recovered from UE’s customers are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to UE’s electric utility customers in a subsequent period.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, UE and AIC using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in Operating Expenses – Purchased Power and net sales in a single hour in Operating Revenues – Electric in our statements of income. On occasion, prior-period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof. In these cases, Ameren, UE and AIC recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date based on the fair value of the award. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period. See Note 12 – Stock-based Compensation for additional information.
Excise Taxes
Excise taxes imposed on us are reflected on UE electric and UE and AIC natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses – Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected on AIC electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses – Taxes Other than Income Taxes for the years ended 2010, 2009 and 2008:
| 2010 | 2009 | 2008 | ||||||||||
Ameren | $ | 189 | $ | 168 | $ | 172 | ||||||
UE | 130 | 112 | 109 | |||||||||
AIC | 59 | 56 | 63 | |||||||||
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are calculated based on statutory tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded because of decreases in the statutory rate, were credited to a regulatory liability. A regulatory asset has been established to recognize the probable future recovery in rates of future income taxes, resulting principally from the reversal of allowance for funds used during construction, that is, equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of the authoritative accounting provisions for income taxes.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 – Income Taxes.
UE, AIC and Genco are parties to a tax sharing agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax sharing agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution of capital to the party receiving the benefit.
Noncontrolling Interests
Ameren’s noncontrolling interests comprise the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of the Ameren subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. Genco’s noncontrolling interest comprises the 20% of EEI not owned by Genco. This noncontrolling interest is classified as a component of equity separate from Genco’s equity in its consolidated balance sheet.
Earnings per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2010, 2009, and 2008. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 16,841 shares in 2008. There were no assumed stock option conversions in 2009 and 2010, as the remaining stock options were not dilutive. All of Ameren’s remaining stock options expired in February 2010.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact the Ameren Companies.
Variable-Interest Entities
In June 2009, the FASB issued amended authoritative guidance that significantly changes the consolidation rules for VIEs. The guidance requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE and requires an ongoing reconsideration of the primary beneficiary. It also amends the events that trigger a reassessment of whether an entity is a VIE. The adoption of this guidance, effective for us as of January 1, 2010, did not have a material impact on our results of operations, financial position, or liquidity.
Disclosures about Fair Value Measurements
In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance requires disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also requires information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. Further, the FASB clarified guidance regarding the level of disaggregation, inputs, and valuation techniques. This guidance was effective for us as of January 1, 2010, with
the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which was effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only. See Note 8 – Fair Value Measurements for additional information.
Asset Retirement Obligations
Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. Ameren, UE and Genco have recorded AROs for retirement costs associated with UE’s Callaway nuclear plant decommissioning costs, asbestos removal, ash ponds, and river structures. In addition, Ameren, UE and AIC have recorded AROs for the disposal of certain transformers.
Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 – Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2010 and 2009:
| Ameren(a)(b) | UE(b) | AIC(d) | Genco | |||||||||||||
Balance at December 31, 2008 | $ | 411 | $ | 317 | $ | 5 | $ | 61 | ||||||||
Liabilities incurred | (e | ) | - | (e | ) | - | ||||||||||
Liabilities settled | (3 | ) | (2 | ) | - | (1 | ) | |||||||||
Accretion in 2009(f) | 24 | 18 | (e | ) | 4 | |||||||||||
Change in estimates(g) | 2 | (2 | ) | (e | ) | 1 | ||||||||||
Balance at December 31, 2009 | $ | 434 | (c) | $ | 331 | $ | 5 | $ | 65 | (c) | ||||||
Liabilities incurred | $ | 8 | $ | 5 | $ | (e | ) | $ | 3 | |||||||
Liabilities settled | (4 | ) | (4 | ) | (e | ) | (e | ) | ||||||||
Accretion in 2010(f) | 26 | 19 | 1 | 4 | ||||||||||||
Change in estimates(h) | 11 | 12 | (3 | ) | 2 | |||||||||||
Balance at December 31, 2010 | $ | 475 | $ | 363 | $ | 3 | $ | 74 | ||||||||
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| (b) | The nuclear decommissioning trust fund assets of $337 million and $293 million as of December 31,
Genco Asset Sale In June 2010, Genco completed a sale of 25% of its Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $18 million from the sale. The city of Columbia also holds two options to purchase additional ownership interests in the facility under two existing power purchase agreements. Columbia can exercise one option, as amended, for an additional 25% of the facility at the end of 2011 for a purchase price of $14.9 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other option can be exercised for another 25% of the facility at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5 million, or at the end of 2023 for a purchase price of $4 million. On an annual basis, the city of Columbia purchases a total of 72 megawatts of capacity and energy generated by the facility under the two existing purchase power agreements. If the city of Columbia exercises one of the purchase options described above, the power purchase agreement associated with that option would be terminated. Employee Separation and Other Charges In 2009, Ameren initiated a voluntary separation program that provided eligible management employees the opportunity to voluntarily terminate their employment and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management employees at Ameren’s subsidiaries, including UE, AIC and Genco. Additionally, in 2009, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. Ameren recorded a pretax charge to earnings of $17 million in 2009 (UE – $8 million, AIC – $3 million, Genco – $5 million) for the severance costs related to both the voluntary and involuntary separation programs as well as for Merchant Generation staff reductions announced in 2009. These charges were recorded in other operations and maintenance expense in the applicable statements of income. Substantially this entire amount was paid prior to December 31, 2009. The number of positions eliminated as a result of these separation programs, including the Merchant Generation staff reductions, was approximately 300. In addition to these programs, Genco recorded a $4 million pretax charge to earnings in 2009 in connection with the retirement of two generating units at its Meredosia power plant and for related obsolete inventory. In 2010, Ameren’s Merchant Generation segment initiated additional involuntary separation programs to reduce additional positions under the terms and benefits consistent with Ameren’s standard separation program. Ameren and Genco recorded a pretax charge to earnings of $4 million in 2010 for the severance costs related to 2010 involuntary separation programs. These charges were recorded in other operations and maintenance expense on Ameren’s and Genco’s statement of income and approximately $2 million was accrued in other current liabilities on Ameren’s and Genco’s balance sheet at December 31, 2010. Coal Contract Settlement In June 2008, Genco entered into a settlement agreement with a coal mine owner. The owner provided Genco with a lump-sum payment of $60 million in July 2008 because of the coal supplier’s premature closing of a mine and the early termination of a coal supply contract. The settlement agreement compensated Genco, in total, for higher fuel costs it incurred in 2008 ($33 million) and in 2009 ($27 million) as a result of the mine closure and contract termination.
NOTE 2 – RATE AND REGULATORY MATTERS Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity. Missouri 2009 Electric Rate Order In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. The rate changes necessary to implement the provisions of the MoPSC order were effective March 1, 2009. In February 2009, Noranda, UE’s largest electric customer, and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. The Stoddard and Pemiscot County cases were consolidated (collectively, the Stoddard Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard Circuit Court is expected to be the last contested amount deposited into the Stoddard Circuit Court’s registry relating to this 2009 electric rate order appeal. As of December 31, 2010, the aggregate amount held by the Stoddard Circuit Court was approximately $10 million. In August 2010, the Stoddard Circuit Court issued a judgment that reversed parts of the MoPSC’s decision. Also, upon issuance, the Stoddard Circuit Court suspended its own judgment. Therefore, the entire amount currently held in the Stoddard Circuit Court’s registry will remain in the Stoddard Circuit Court’s registry pending the appeal discussed below. In September 2010, UE filed an appeal with the Missouri Court of Appeals for the Southern District of Missouri. The Court of Appeals will conduct an independent review of the MoPSC’s order. UE believes the Stoddard Circuit Court’s judgment, which reversed parts of the MoPSC decision, will be found erroneous by the Court of Appeals; however, there can be no assurances that UE’s appeal will be successful. If UE prevails on all issues of its appeal, UE will receive all of the funds held in the Stoddard Circuit Court’s registry, plus accrued interest. If UE were to conclude that some portion of the funds held in the Stoddard Circuit Court’s registry becomes probable of refund to Noranda, a charge to earnings would be recorded for the estimated amount of refund in the period in which that decision is made. A decision by the Court of Appeals is not expected until at least the third quarter of 2011. See the 2010 Electric Rate Order section below for information about four industrial customers, one of which is Noranda, who have filed an appeal with the Cole County Circuit Court and also were granted a stay for their rate increases granted by the MoPSC’s 2009 electric rate order as they specifically apply to each of their electric service accounts. 2010 Electric Rate Order In May 2010, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside UE’s system. The revenue increase was based on a 10.1% return on equity, a capital structure composed of 51.3% common equity, and a rate base of approximately $6 billion. The rate changes became effective on June 21, 2010. The MoPSC order also included the following provisions, among other things:
In addition, the order implemented several stipulations previously agreed to by UE, the MoPSC staff, and other parties to the proceedings. One stipulation included UE’s agreement to withdraw its request for an environmental cost recovery mechanism in exchange for the ability to continue recording for ratemaking purposes an allowance for funds used during construction and to defer depreciation costs for pollution control equipment at the Sioux plant until the earlier of January 2012 or when the cost of that equipment is placed in customer rates. This treatment allows UE to defer these costs as a regulatory asset, which will be amortized upon their inclusion in rates. UE will have the ability to request the implementation of an environmental cost recovery mechanism in a future rate case proceeding. Another approved stipulation allows UE to recover its portion of Ameren’s September 2009 common stock issuance costs. The order also implemented the parties’ agreement to prospectively include the margins on certain wholesale contracts in UE’s FAC in exchange for an increase in the jurisdictional cost allocation to retail customers. In addition, the order implements the parties’ agreement to a mechanism that will prospectively address the significant lost revenues UE can incur due to future operational issues at Noranda’s smelter plant. This mechanism will permit UE, when a loss of service occurs at the Noranda plant, to sell the power not taken by Noranda and use the proceeds of those sales to offset the revenues lost from Noranda. UE would be allowed to keep the amount of revenues necessary to compensate UE for significant Noranda usage reductions but any excess revenues above the level necessary to compensate UE would be refunded to retail customers through the FAC. Approved stipulations also include the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs and the discontinuation of the SO2 emission allowance sales tracker, among other things. In June 2010, UE and other parties to the rate case filed for rehearing of certain aspects of the MoPSC order. The MoPSC denied all rate order rehearing requests filed by UE and other parties. UE appealed the return on equity included in the MoPSC order to the Circuit Court of Cole County, Missouri (Circuit Court). UE subsequently withdrew its appeal as the outcome of the pending electric rate case would supersede the result of this appeal. A group of industrial customers also appealed certain aspects of the MoPSC order to the Circuit Court. A decision is expected to be issued on the industrial customers’ appeal by the Circuit Court in 2011. On February 16, 2011, the Missouri Office of Public Counsel (MoOPC) made a filing with the MoPSC in which the MoOPC argued that the December 20, 2010 Order Granting Stay Pursuant to Section 386.520 (Stay Order), discussed below, of the Circuit Court should apply to all UE customers rather than to just the four UE industrial customers that requested the Circuit Court to grant these industrial customers’ request to stay the MoPSC’s 2010 Missouri electric rate order as to their billings. On that basis, the MoOPC requested the MoPSC to suspend UE’s currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with UE’s previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. If the requested suspension occurs, it would continue until the earlier of the time that a subsequent order is issued by the MoPSC, or an order reversing any such suspension is issued by a court of competent jurisdiction, but in no event beyond the implementation of new electric rates for UE. It is anticipated that new electric rates for UE will take effect by early August 2011, pursuant to an anticipated MoPSC rate order in UE’s currently pending electric rate proceeding. If the currently effective 2010 rate schedules are suspended for all customers such that UE is only able to charge customers under its previously effective rate schedules for service provided for the period March through August 2011, the reduced charges, which would reflect the difference between billings under the 2010 Missouri electric rate order and billings under the 2009 Missouri electric rate order, are estimated at approximately $100 million and would result in corresponding reductions in pretax earnings and cash flows. Also on February 16, 2011, the Missouri Industrial Energy Consumers (MIEC), of which the four UE industrial customers referred to above are members, made a filing with the MoPSC in response to the MoOPC filing discussed above. In its filing, MIEC supported the position set forth in the MoOPC filing that the Stay Order should apply to all UE customers, except that MIEC requested the MoPSC to suspend UE’s currently effective rate schedules, including its FAC, and replace them with UE’s rate schedules approved by the MoPSC in its 2007 electric rate order. If the requested suspension occurs, it would continue until the earlier of the time that a subsequent order is issued by the MoPSC, or an order reversing any such suspension is issued by a court of competent jurisdiction, but in no event beyond the implementation of new electric rates for UE. As noted, it is anticipated that new electric rates for UE will take effect by early August 2011. If the currently effective 2010 rate schedules (including the FAC) are suspended for all customers such that UE is only able to charge customers under its previously effective rate schedules for service provided for the period March through August 2011, the reduced charges, which would reflect the difference between billings under the 2010 Missouri electric rate order and billings under the 2007 Missouri electric rate order, including FAC billings, are estimated at approximately $300 million and would result in corresponding reductions in pretax earnings and cash flows. The filings by the MoOPC and MIEC relate to the December 20, 2010 Stay Order, in which the Circuit Court granted the request of four UE industrial customers to stay the MoPSC’s 2010 Missouri electric rate order and to require those customers to pay into the Circuit Court’s registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last UE rate order for which appeals have been exhausted. On February 15, 2011, the four UE industrial customers posted the bond required by the Stay Order and are expected to begin making the required payments into the Circuit Court’s registry. The Stay Order does not address the merits of the UE disagrees with the Stay Order, as well as the related filings made by the MoOPC and MIEC with the MoPSC. With respect to further proceedings regarding the Stay Order, the pending review proceedings regarding the 2009 and 2010 Missouri electric rate orders and the MoOPC’s and MIEC’s filings with the MoPSC, UE will continue to address the merits of those orders and filings through the judicial and regulatory review processes. There could be
Pending Electric Rate Case On September 3, 2010, UE filed a request with the MoPSC
As a
tracking mechanism for pension and postretirement benefit costs
2011 Natural Gas Delivery Service Rate Order In January 2011, the MoPSC approved a stipulation and agreement that resolved a June 2010 request by UE to increase annual natural gas revenues. The stipulation and agreement provided for an increase in annual natural gas delivery revenues of $9 million, which included approximately $2 million of annual revenues previously collected through the ISRS rider for the test year ended December 31, 2009. The new rates became effective on February 20, 2011. The stipulation and agreement approved a revised block-rate structure for residential customers that results in more certainty of margin revenue recovery regardless of weather conditions or conservation efforts, as recovery is less dependent on usage. The new residential structure is expected to allow UE to recover approximately half of its natural gas non-PGA residential revenues through a fixed monthly charge, with the remaining amount to be recovered based on sales. As part of the stipulation and agreement, UE will not file a separate natural gas rate increase request before December 31, 2012. However, UE can file a combined natural gas and electric rate case before that date. Further, this agreement does not prevent UE from filing to recover infrastructure replacement costs through an ISRS during this moratorium. The return on equity to be used by UE for purposes of an ISRS tariff filing is 10%. FAC Prudence Review Missouri law requires the MoPSC to complete prudence reviews of UE’s FAC at least every 18 months. In August 2010, the MoPSC staff completed a prudence review of the FAC from March 1, 2009, to September 30, 2009. The MoPSC staff contends that UE should have included in the FAC calculation all costs and revenues associated with certain contract sales that were made due to the loss of Noranda load caused by a severe ice storm in January 2009. UE disagrees with the MoPSC staff’s classification of these transactions and opposes their inclusion in the FAC calculation. UE recognized margin associated with these contracts of $17 million during the period reviewed by the MoPSC and an additional $25 million of margin subsequent to September 30, 2009. If the MoPSC were to agree with the staff position, and if the MoPSC’s order were to be upheld by the courts on appeal, UE would be required to pass through to customers the $42 million in margin associated with these contracts and record a charge to earnings. The MoPSC is expected to issue an order with respect to this prudence review in 2011. If UE were to conclude that some portion of these contested FAC amounts become probable of refund to UE’s customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that decision is made. UE cannot predict the outcome of this MoPSC prudence review. Renewable Energy Portfolio Requirement A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate In restrictions. This legislative action allows UE to comply with the law through its own generation or the procurement of renewable energy or renewable energy credits
Illinois
The ICC order confirmed the previously approved 80% allocation of fixed nonvolumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of fixed nonvolumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed nonvolumetric electric residential and commercial customer and meter charges increased from 27% to 40%. The ICC order also extended the amortization period of the integration-related regulatory asset for Ameren’s acquisition of IP, which was previously set to be fully amortized by December 2010. The new order extended the amortization for two years beginning in May 2010. The ICC order also created a $3 million regulatory asset for AIC’s costs incurred in 2009 for its voluntary and involuntary separation programs. These costs are being amortized over three years, beginning May 2010. AIC and certain intervenors were granted a rehearing with the ICC. In November 2010, the ICC approved an order on the rehearing issues, which authorized an increase in annual revenues of $25 million, in addition to the In Pending Electric and Natural Gas Delivery Service Rate Cases
$60 million. The electric rate increase
In an attempt to limit regulatory lag, AIC is also using a future test year,
2007 Illinois Electric Settlement Agreement In 2007, key stakeholders in Illinois agreed to avoid rate rollback and freeze legislation that would impose a tax on electric generation. These stakeholders wanted to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement included a comprehensive rate relief and customer assistance program. The 2007 Illinois Electric Settlement Agreement provided approximately $1 billion of funding from 2007 to 2010 for rate relief for certain electric customers in Illinois, including approximately $488 million for customers of
Ameren, AIC and Genco recognized in their financial statements the costs of their respective rate relief contributions and program funding under the 2007 Illinois Electric Settlement Agreement in a manner corresponding with the timing of the funding. As a result, Ameren, Other electric generators and utilities in Illinois
ICC Reliability Audit In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on
Federal
In In August 2010, Ameren announced the formation of ATX. In August 2010, Ameren, on behalf of UE, AIC, ATXI and ATX, filed a request with FERC seeking transmission rate incentives for four new
Regional Transmission Organization UE
As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s obtain FERC approval and to meet conditions imposed by FERC, in addition to obtaining
FERC Order – MISO Charges
In May 2009, FERC
MISO and PJM Dispute Resolution During 2009 and 2010, MISO and PJM discovered payment between the RTOs will be required, but financial settlement practices will be modified to ensure greater accuracy for transactions between the RTOs. The UE Power Purchase Agreement with Entergy Arkansas, Inc. In July 2007, FERC issued a series of orders addressing a complaint filed by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing UE for additional charges under a 165-megawatt power purchase agreement, and UE paid these charges. Additional charges continued during the remainder of the term of the power purchase agreement, which expired on August 31, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE
In 2009, UE
UE is considering filing an application to obtain an ESP from the NRC at the Callaway nuclear plant site. An ESP approves a specific location for a nuclear facility; however, additional licenses would be required for the specific type and All of Missouri’s major electric utility providers, including cooperatives, municipals, and other investor-owned utilities, are supporting the passage of this legislations. In addition, the governor of Missouri, labor and other key stakeholders are supporting this legislation. Should the Missouri legislation be enacted into law, UE plans to file an ESP application with the NRC in
As of December 31,
Pumped-storage Hydroelectric Facility Relicensing In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The Regulatory Assets and Liabilities In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE
Noncurrent regulatory liabilities: Income taxes(aa) Removal costs(bb) Emission allowances(cc) Vegetation management and infrastructure inspection(dd) MTM derivative liabilities(ee) Bad debt rider(ff) Pension and postretirement benefit costs tracker(gg) Total noncurrent regulatory liabilities 2008: Current regulatory assets: Under-recovered Illinois electric power costs(b)(d) Under-recovered PGA(b)(d) MTM derivative assets(e) Total current regulatory assets(f) Noncurrent regulatory assets: Pension and postretirement benefit costs(g) Income taxes(h) Asset retirement obligation(i) Callaway costs(b)(j) Unamortized loss on reacquired debt(b)(k) Recoverable costs – contaminated facilities(l) IP integration(m) Recoverable costs – debt fair value adjustment(n) MTM derivative assets(o) SO2 emission allowances sale tracker(p) FERC-ordered MISO resettlements - March 2007(q) Vegetation management and infrastructure inspection(r) Storm costs(s) Demand-side costs(t) Reserve for workers’ compensation liabilities(u) Other(w) Total noncurrent regulatory assets Current regulatory liabilities: Over-recovered Illinois electric power costs(d) Over-recovered PGA(d) Total current regulatory liabilities(z) Noncurrent regulatory liabilities: Income taxes(aa) Removal costs(bb) Emission allowances(cc) Pension and postretirement benefit costs tracker(gg) MISO resettlements(hh) Total noncurrent regulatory liabilities Current regulatory assets: Under-recovered FAC(b)(c) Under-recovered Illinois electric power costs(b)(d) Under-recovered PGA(b)(d) MTM derivative assets(e) Total current regulatory assets Noncurrent regulatory assets: Pension and postretirement benefit costs(f) Income taxes(g) Asset retirement obligation(h) Callaway costs(b)(i) Unamortized loss on reacquired debt(b)(j) Recoverable costs – contaminated facilities(k) IP integration(l) Recoverable costs – debt fair value adjustment(m) MTM derivative assets(e) SO2 emission allowances sale tracker(n) FERC-ordered MISO resettlements – March 2007(o) Vegetation management and infrastructure inspection(p) Storm costs(q) Demand-side costs(r) Reserve for workers’ compensation liabilities(s) Bad debt rider (t) Credit facilities fees(u) Employee separation costs(v) Common stock issuance costs(w) Construction accounting for pollution control equipment(b)(x) Other(y) Total noncurrent regulatory assets Current regulatory liabilities: Over-recovered FAC(z) Over-recovered Illinois electric power costs(d) Over-recovered PGA(d) MTM derivative liabilities(aa) Total current regulatory liabilities(bb) Noncurrent regulatory liabilities: Income taxes(cc) Removal costs(dd) Emission allowances(ee) Vegetation management and infrastructure inspection(ff) MTM derivative liabilities(aa) Bad debt rider(gg) Pension and postretirement benefit costs tracker(hh) Energy efficiency rider(ii) Total noncurrent regulatory liabilities
UE NOTE 3 – PROPERTY AND PLANT, NET The following table presents property and plant, net, for each of the Ameren Companies at December 31,
The following table provides accrued capital expenditures at December 31, 2010, 2009,
NOTE 4 – CREDIT FACILITY BORROWINGS AND LIQUIDITY The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit Agreement described below for the year ended December 31, 2010, and excludes letters of credit issued under the credit agreement:
The following table summarizes the borrowing activity and relevant interest rates under the 2010 Genco Credit Agreement described below for the year ended December 31, 2010:
Ameren and AIC did not borrow under the 2010 Illinois Credit Agreement during 2010. The following table summarizes the borrowing activity and relevant interest rates under the
The following table summarizes the borrowing activity and relevant interest rates under the 2009 $150 million Supplemental Credit Agreement,
The following table summarizes the borrowing activity and relevant interest rates under the $800 million 2009 Illinois Credit Agreement,
Ameren and certain of its subsidiaries entered into multiyear credit facility agreements with On September 10, 2010, UE entered into the $800 million 2010 Missouri Credit Agreement. On September 10, 2010, Ameren and Genco entered into the $500 million 2010 Genco Credit Agreement. Together, the 2010 Missouri Credit Agreement and the 2010 Genco Credit Agreement replaced the 2009 Multiyear Credit Agreements
The obligations of each borrower under the :
Ameren has the option and 2010 Illinois Credit Agreement – $1.0 billion. Each of the 2010 Credit Agreements will mature and expire on September 10, 2013. In February 2011, AIC received approval from the ICC to extend the expiration of its Borrowing Sublimit under the 2010 Illinois Credit Agreement to September 10, 2013. The
The obligations of
Loans are available on a revolving basis under each of the
Based on outstanding borrowings under the 2010 Credit Agreements (and also considering reductions of borrowing capacity for $15 million of letters of credit issued and $269 million of commercial paper borrowings), the aggregate available amount under the Other Agreements On June 2, 2010, Ameren entered into a $20 million revolving credit facility ($20 Million Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn since June 15, 2010. Borrowings under the $20 Million Facility bear interest at a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility. On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. The average annual interest rate for borrowing under the $20 million term loan agreement was 2.03% during the year ended December 31, 2009. This term loan agreement was repaid at maturity in January 2010.
The 2010 Credit Agreements are used to support Ameren’s and UE’s commercial paper programs. Ameren Indebtedness Provisions and Other Covenants The The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The The
The 2010 Credit Agreements contain default provisions. UE and Genco are no longer borrowers within the same credit agreement, as they were under the 2009 Multiyear Credit Agreement, and a default by one such subsidiary borrower will not trigger a default by the other under the applicable 2010 Credit Agreements. Defaults under the 2010 Credit Agreements apply separately to each borrower; except however, that a default by UE, AIC or Genco under any of the 2010 Credit Agreements will also constitute a default by Ameren under such agreement. Defaults include a cross default with respect to a borrower under the applicable 2010 Credit Agreements to the occurrence of a default by such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $25 million in the aggregate. Any default of Ameren under any 2010 Credit Agreement that exists solely as a result of a default by UE, AIC or Genco thereunder will not constitute a default under
The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of December 31, 2010, Ameren’s consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility was 50%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any None of Money Pools Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements. Utility Through the utility money pool, the pool participants may access the committed credit facilities. contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. pool for the year ended December 31, Non-state-regulated Subsidiaries Ameren Services, Resources Company, Genco, AERG, Marketing Company, See Note 14 – Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the years ended December 31, 2010, 2009, Unilateral Borrowing Agreement In addition, a unilateral borrowing agreement exists between Ameren, NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS The following table presents long-term debt outstanding for the Ameren Companies as of December 31,
CILCORP (Parent): Unsecured notes: 8.70% Senior notes due 2009 9.375% Senior bonds due 2029 Fair-market value adjustments Total long-term debt, gross Less: Maturities due within one year Long-term debt, net CILCO: First mortgage bonds:(a) 8.875% Senior secured notes due 2013(b) 6.20% Senior secured notes due 2016(b) 6.70% Senior secured notes due 2036(b) Environmental improvement and pollution-control revenue bonds:(a)(c) 6.20% Series 1992B due 2012 5.90% Series 1993 due 2023 Long-term debt, net IP: Mortgage bonds:(a) 7.50% Series due 2009 6.25% Senior secured notes due 2016(b) 6.125% Senior secured notes due 2017(b) 6.250% Senior secured notes due 2018(b) 9.750% Senior secured notes due 2018(b) Pollution control revenue bonds:(a)(c) 5.70% 1994A Series due 2024 5.40% 1998A Series due 2028 5.40% 1998B Series due 2028 Fair-market value adjustments Total long-term debt, gross Less: Unamortized discount and premium Less: Maturities due within one year Long-term debt, net Ameren consolidated long-term debt, net AIC: First mortgage bonds:(a) 6.625% Senior secured notes due 2011(b) 8.875% Senior secured notes due 2013(c) 6.20% Senior secured notes due 2016(c) 6.25% Senior secured notes due 2016(b) 6.125% Senior secured notes due 2017(b) 7.61% Series 1997-2 due 2017 6.25% Senior secured notes due 2018(b) 9.75% Senior secured notes due 2018(b) 6.125% Senior secured notes due 2028(b) 6.70% Senior secured notes due 2036(b) 6.70% Senior secured notes due 2036(c) Environmental improvement and pollution control revenue bonds: 6.20% Series 1992B due 2012(a)(d) 2000 Series A 5.50% due 2014(d) 5.90% Series 1993 due 2023(a)(d) 5.70% 1994A Series due 2024(a)(d) 1993 Series C-1 5.95% due 2026 1993 Series C-2 5.70% due 2026 1993 Series B-1 due 2028(e) 5.40% 1998A Series due 2028(a)(d) 5.40% 1998B Series due 2028(a)(d) Fair-market value adjustments Total long-term debt, gross Less: Unamortized discount and premium Less: Maturities due within one year Long-term debt, net Genco: Unsecured notes: Senior notes Series D 8.35% due 2010 Senior notes Series F 7.95% due 2032 Senior notes Series H 7.00% due 2018 Senior notes Series I 6.30% due 2020 Total long-term debt, gross Less: Unamortized discount and premium Less: Maturities due within one year Long-term debt, net Ameren consolidated long-term debt, net
UE 1992 Series UE 1998 Series A UE 1998 Series B UE 1998 Series C AIC 1993 Series B-1 The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31,
All of the Ameren Companies expect to fund maturities of long-term debt, short-term borrowings, credit facility borrowings and contractual obligations through a combination of cash flow from operations and external financing. See Note 4 – Credit Facility Borrowings and Liquidity for a discussion of external financing availability. In November 2008, Ameren, All classes of UE’s and AIC’s preferred stock are entitled to cumulative dividends and have voting rights. The following table presents
AIC: With par value of $100 per share, 2 million shares authorized 4.00% Series 144,275 shares 4.08% Series 45,224 shares 4.20% Series 23,655 shares 4.25% Series 50,000 shares 4.26% Series 16,621 shares 4.42% Series 16,190 shares 4.50% Series(b) 4.64% Series(b) 4.70% Series 18,429 shares 4.90% Series 73,825 shares 4.92% Series 49,289 shares 5.16% Series 50,000 shares 6.625% Series 124,273.75 shares 7.75% Series 4,542 shares Total Less: Shares of AIC preferred stock owned by Ameren Total Ameren
Pursuant to the AIC Merger: (i) every two shares of each series of IP preferred stock outstanding immediately prior to the AIC Merger were automatically converted into one share of a newly created series of AIC preferred stock having the same payment and redemption terms as the existing series of IP preferred stock, except to the extent that IP preferred stockholders exercised their dissenters’ rights in accordance with Illinois law; and (ii) each outstanding share of CIPS common and preferred stock remained outstanding, except to the extent that CIPS preferred stockholders exercised their dissenters’ rights in accordance with Illinois law. Stockholders holding 8,337 shares and 423 shares of CIPS and IP preferred stock, respectively, exercised their dissenter’s rights. In addition, the Ameren Companies have classes of preferred stock that are authorized but no shares of which are outstanding. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding. UE has 7.5 million shares of $1 par value preference stock authorized, with no such preference stock outstanding. AIC has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding. Ameren
Ameren is also selling newly issued shares of common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan, Ameren issued 3.0 million, 3.2 million, In May 2009, Ameren issued $425 million of 8.875% senior unsecured notes due May 15, 2014, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2009. Ameren received net proceeds of $420 million, which were used, together with other corporate funds, to repay borrowings under its $300 million term loan agreement and, by way of a capital contribution to CILCORP, In September 2009, Ameren issued and sold 21.85 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of equity capital contributions
In
In cancellation, fair-market value adjustments related to the senior bonds were reduced by $44 million during 2009. In February 2010, CILCORP completed a covenant defeasance of its remaining outstanding 9.375% senior bonds due UE In March 2009, UE issued $350 million of 8.45% senior secured notes due March 15, 2039, with interest payable semiannually on March 15 and September 15 of each year, beginning in September 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $346 million, which were used to repay short-term debt. In connection with this issuance of $350 million of senior secured notes, UE agreed that, so long as these senior secured notes are outstanding, it would not, prior to maturity, cause a first mortgage bond release date to occur.
In AIC In In August 2010, AIC (formerly CILCO) redeemed all of the 111,264 outstanding shares of its 4.50% Series preferred stock at $110 per share and all of the 79,940 shares of its 4.64% Series preferred stock at $102 per share, plus, in each case, accrued and unpaid dividends. These preferred shares were redeemed in connection with the AIC Merger. In September 2010, AIC (formerly CIPS) redeemed all $40 million of its 7.61% Series 1997-2 first mortgage bonds at a redemption price of 101.52% of the principal amount, plus accrued interest. These bonds were redeemed in connection with the AIC Merger. In September 2010, Ameren contributed to the capital of AIC (formerly IP), without the payment of any consideration, all of the IP preferred stock owned by Ameren ($33 million). IP cancelled these preferred shares. This transaction was in connection with the AIC Merger. See Note 16 – Corporate Reorganization and Discontinued Operations for additional information. Genco
In November 2009, Genco issued $250 million of 6.30% senior unsecured notes due April 1, 2020, with interest payable semiannually on April 1 and October 1 of each year, beginning in April 2010. Genco received net proceeds of $247 million, which were used to repay short-term debt, and for general corporate purposes.
In
Indenture Provisions and Other Covenants UE’s
Ameren’s indenture, pursuant to which Ameren’s 8.875% $425 million senior unsecured notes due 2014 were issued, does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period. UE, interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left
earned surplus.
Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make certain principal or interest payments, to make certain loans to or investments in affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of December 31,
Genco’s debt incurrence-related ratio restrictions In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable tests in effect at the time of any such issuances. Off-Balance-Sheet Arrangements At December 31, NOTE 6 – OTHER INCOME AND EXPENSES The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended December 31, 2010, 2009,
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause the following:
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross derivative volumes by commodity type as of December 31, 2010, and 2009:
Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 – Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense recorded in connection with NPNS contracts is recognized at the contract price upon physical delivery. If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting treatment. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting treatment are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. Regulatory assets or regulatory liabilities are amortized to the statement of income as related losses and gains are reflected in rates charged to customers. Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs. Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible financial instruments or other items.
The following table presents the carrying value and balance sheet
Derivative assets not designated as hedging instruments Commodity contracts: Heating oil Natural gas Power Derivative liabilities not designated as hedging instruments Commodity contracts: Heating oil Natural gas Power Uranium
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of December 31,
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management. We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Concentrations of Credit Risk In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of December 31, 2010, and 2009, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.
The following table presents the amount of cash collateral held from counterparties, as of December 31, 2010, and 2009, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:
The potential loss on counterparty exposures is reduced by
Derivative Instruments with Credit Risk-Related Contingent Features Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2010, and 2009, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2010 or 2009, respectively, and (2) those counterparties with rights to do so requested collateral:
Cash Flow Hedges The following table presents the pretax net gain or loss for the year ended December 31, 2010, and 2009, associated with derivative instruments designated as cash flow
Other Derivatives The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the
Derivatives Subject to Regulatory Deferral The following table represents the net change in market value associated with derivatives that qualify for regulatory deferral for the
UE
As part of the 2007 Illinois Electric Settlement Agreement and the
NOTE 8 – FAIR VALUE MEASUREMENTS Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels: Level Level To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Level sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors. We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3. In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31,
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31,
The following table summarizes the changes in the fair value
The following table summarizes the changes in the fair value
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable on electronic exchanges from the previous
See Note 11 – Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issues for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments. The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31,
NOTE 9 – NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS UE has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway nuclear plant. See Note Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities. The following table presents proceeds from the sale of investments in UE’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2010, 2009,
Net realized and unrealized gains and losses are deferred and recorded as regulatory assets or regulatory liabilities on Ameren’s and UE’s in lower or higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by UE’s customers. See Note 2 – Rate and Regulatory Matters. The following table presents the costs and fair values of investments in debt and equity securities in UE’s nuclear decommissioning trust fund at December 31,
The following table presents the costs and fair values of investments in debt securities in UE’s nuclear decommissioning trust fund according to their contractual maturities at December 31,
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund, recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for our nuclear facility expires. UE intends to submit a license extension application to the NRC to extend the Callaway nuclear plant’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in UE’s nuclear decommissioning trust fund. They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position at December 31,
NOTE 10 –
Under the Nuclear Waste Policy Act of such costs. UE has sufficient installed storage capacity for spent nuclear fuel at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. In March 2010, the DOE submitted a motion to withdraw the Yucca Mountain Repository license application it filed with the NRC. In anticipation of this action, the Nuclear Energy Institute (NEI) in July 2009 formally requested that DOE promptly perform the statutorily required annual fee adequacy review and immediately suspend collection of the NWF fee. The In 1984, the DOE entered into a contract with UE to dispose of nuclear waste from its Callaway nuclear plant. As a result of DOE’s failure to build a repository for nuclear waste or otherwise fulfill its contract obligations, UE and other nuclear power plant owners sued DOE to recover costs incurred for ongoing storage of their spent fuel. UE seeks to recover approximately $13 million in costs that it incurred through 2009. This amount includes the cost of reracking the Callaway nuclear plant’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that UE would not have incurred had DOE performed its contractual obligations. UE filed its claim in 2004, but its case was formally stayed by the United States Court of Federal Claims until 2010, pending developments in other cases that were more procedurally advanced. Discovery has been scheduled to be completed by July 28, 2011, and the trial is expected to be held in the fall of 2011 or the spring of 2012. In December 2010, UE and DOE began investigating settlement options. At this time, UE does not know nor can it predict the result of the ongoing settlement discussions between the parties. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license from 2024 to 2044. If the Callaway nuclear plant’s license is extended, additional spent fuel storage will be required. UE is evaluating the installation of a dry spent fuel storage facility at its Callaway nuclear plant. Electric utility rates charged to customers provide for the
CIPS: With par value of $100 per share, 2 million shares authorized 4.00% Series 4.25% Series 4.90% Series 4.92% Series 5.16% Series 6.625% Series Total CILCO: With par value of $100 per share, 1.5 million shares authorized 4.50% Series 4.64% Series Total IP: With par value of $50 per share, 5 million shares authorized 4.08% Series 4.20% Series 4.26% Series 4.42% Series 4.70% Series 7.75% Series Total Less: Shares of IP preferred stock owned by Ameren Total Ameren
NOTE 11 – RETIREMENT BENEFITS The primary objective of the Ameren retirement plan and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. The following table presents the benefit liability recorded on the balance sheets of each of the Ameren Companies as of December 31,
Ameren recognizes the underfunded status of its pension and postretirement plans as a liability on its balance sheet, with offsetting entries to accumulated OCI and regulatory assets, in accordance with authoritative accounting guidance. The following table presents the funded status of our pension and postretirement benefit plans as of December 31,
The following table presents the assumptions used to determine our benefit obligations at December 31,
Ameren determines discount rate assumptions by using an interest rate yield curve pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations. The yield curve is based on the yields of Funding Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plan is funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, The following table presents the cash contributions made to our defined benefit retirement plan and to our postretirement plans during
Investment Strategy and Policies Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, to the extent authority is delegated to it by the finance committee of Ameren’s board of directors, implements investment strategy and asset allocation guidelines for the plan assets. The investment committee is composed of members of senior management. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable, and second, to maximize total return on plan assets and minimize expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. As appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. The investment committee regularly monitors manager performance and compliance with investment guidelines. The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration, market capitalization, country, style (growth or value) and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk. The following table presents our target allocations for
In general, the U.S. large capitalization equity investments are passively managed or indexed, whereas the international, emerging markets, U.S. small capitalization, and U.S. mid capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed income vehicles. Debt security investments in high-yield securities, emerging market securities, and non-U.S. dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. Ameren’s investment in private equity funds consists of Fair Value Measurements of Plan Assets Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2010:
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2009:
For the year ended December 31, 2009, $183 million of previously classified Level 1 assets within the pension plan were recategorized to Level 2. The classification change primarily related to U.S. treasury securities and has been reflected in the above table. The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair value hierarchy for each of the
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2010:
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2009:
For the year ended December 31, 2009, $17 million of previously classified Level 1 assets within the postretirement benefit plans were recategorized to Level 2. The classification change primarily related to U.S. treasury securities and has been reflected in the above table. Net Periodic Benefit Cost The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit plans during 2010, 2009,
The current year expected return on plan assets is primarily determined by adjusting the prior-year market-related asset value for current year contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years. The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the UE,
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of December 31,
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2010, 2009,
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
Other Ameren sponsors a 401(k) plan for eligible employees. The Ameren plan covered all eligible employees of the Ameren Companies at December 31, The following table presents the portion of the 401(k) matching contribution to the Ameren plan attributable to each of the Ameren Companies for the years ended December 31, 2010, 2009,
NOTE 12 – Ameren’s long-term incentive plan for eligible employees, called the Long-term Incentive Plan of 1998 (1998 Plan), was replaced prospectively by the 2006 Omnibus Incentive Compensation Plan (2006 Plan) effective May 2, 2006. The 2006 Plan provides for a maximum of 4 million common shares to be available for grant to eligible employees and directors. No new awards may be granted under the 1998 Plan; however, previously granted awards continue to vest or to be exercisable in accordance with their original terms and conditions. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards. A summary of nonvested shares
Ameren recorded compensation expense of $14 million, $15 million, Performance Share Units Performance share unit awards were granted under the 2006 Plan each year since 2006. A share unit will vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified performance or market conditions have been met and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit will vary from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. For performance share units granted in 2006, 2007 and 2008, vested performance shares units are held for a The fair value of each share unit awarded in January 2010 under the 2006 Plan was determined to be $32.01. That amount was based on Ameren’s closing common share price of $27.95 at December 31, 2009, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total stockholder return for a three-year performance period relative to the designated peer group beginning January 1, 2010. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.70%, volatility of 23% to 39% for the peer group, and Ameren’s attainment of three-year average earnings per share threshold during each year of the performance period. The fair value of each share unit awarded in March 2009 under the 2006 Plan was determined to be $15.52. That amount was based on Ameren’s closing common share price of $22.20 at March 2, 2009, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2009. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.24%, volatility of 21.3% to 33.1% for the peer group, and Ameren’s attainment of earnings per share of at least $2.54 during each year of the three-year performance period.
Restricted Stock Restricted stock awards of Ameren common stock were granted under the 1998 Plan from 2001 to 2005. Restricted shares have the potential to vest over a seven-year period from the date of grant if
NOTE 13 – INCOME TAXES The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2010, 2009,
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2010, 2009,
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31,
Uncertain Tax Positions
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31,
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31,
As of January 1, Ameren’s State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their NOTE 14 – RELATED PARTY TRANSACTIONS The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. Below are the material related party agreements.
Electric Power Supply Agreements The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the years ended December 31, 2010, 2009,
In
Capacity Supply Agreements
AIC used RFP processes in early 2008, pursuant to the 2007 Illinois Electric Settlement Agreement, to contract for the necessary capacity requirements for the period from June 1, 2008, through May 31, 2009. Marketing Company and UE were two of the winning suppliers in
In 2010, AIC used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2010, through May 31, 2013. Both Marketing Company and UE were among winning suppliers in the capacity RFP process. In April 2010, Marketing Company contracted to supply some capacity to AIC for $1 million, $2 million, and $3 million for the 12 months ending May 31, 2011, 2012, and 2013, respectively. In April 2010, UE contracted to supply some capacity to AIC for less than $1 million for the period from June 1, 2010, through May 31, 2013. Energy Swaps As part of the 2007 Illinois Electric Settlement Agreement,
AIC, as an electric load-serving entity, must acquire energy sufficient to meet its obligations to customers. AIC used RFP processes in early 2008, pursuant to the 2007 Illinois Electric Settlement Agreement, to contract for the necessary financial energy swaps requirement for the period from June 1, 2008, through May 31, 2009. Marketing Company was one of the winning suppliers in
Interconnection and Transmission Agreements UE Generator Interconnection Agreement In 2008, Genco and In September 2009, Marketing Company and Company to fund the cost of certain upgrades to Joint Ownership Agreement
Support Services Agreements Ameren Services
Executory Tolling, Gas Sales, and Transportation Agreements Prior to 2009, under an executory tolling agreement, Under a gas transportation agreement, Genco acquires gas transportation service from UE for its Columbia, Missouri, CTs. This agreement expires in February 2016. Money Pools See Note 5 – Long-term Debt and Equity Financings for discussion of affiliate borrowing arrangements. Intercompany Borrowings On May 1, 2005, Genco issued to
outstanding borrowings directly from Ameren at December 31, 2009. The average interest rate on these borrowings was
Collateral Postings Under the terms of the
Operating Leases Under an operating lease agreement, Genco leased certain CTs at a Joppa, Illinois, site to its former parent, Development Company, for an initial term of 15 years, expiring September 30, 2015. Under an electric power supply agreement with Marketing Company, Development Company supplied the capacity and energy from these leased units to Marketing Company, which in turn supplied the energy to Genco. By mutual agreement of the parties, this lease agreement and this power supply agreement were terminated in February 2008, when an internal reorganization merged Development Company into Resources Company. Genco recorded operating revenues from the lease agreement of $2 million Intercompany Transfers On January 1, 2008, UE transferred its interest in Union Electric Development Corporation at book value to Ameren by means of a $3 million dividend-in-kind. On March 31, 2008, Union Electric Development Corporation was merged into Ameren Development Company, with Ameren Development Company surviving the merger. On February 29, 2008, UE contributed its 40% ownership interest in EEI, book value of $39 million, to Resources Company, in exchange for a 50% interest in Resources Company, and then immediately transferred its interest in Resources Company to Ameren by means of a $39 million dividend-in-kind. Also on February 29, 2008, Development Company, which formerly held a 40% ownership interest in EEI, merged into Ameren Energy Resources Company, which then merged into Resources Company. As a result, Resources Company had an 80% ownership interest in EEI. On January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% ownership interest in EEI to Genco, through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco recognized the assets and liabilities of EEI at their book value as of January 1, 2010. On October 1, 2010, AIC distributed AERG’s common stock to Ameren in connection with the AIC Merger. Ameren subsequently contributed the AERG common stock to Resources Company. The distribution of AERG common stock was accounted for as a transaction between entities under common control; therefore, AIC transferred AERG to Ameren based on AERG’s carrying value. See Note 16 – Corporate Reorganization and Discontinued Operations for additional information. The following table presents the impact on UE,
Gas purchases from Genco Ameren Services support services agreement CILCO support services Ameren Energy, Inc. support services agreement(e) AFS support services agreement Maintenance Insurance premiums(f) Total Other Operations and Maintenance Expenses Money pool borrowings (advances)
NOTE 15 – COMMITMENTS AND CONTINGENCIES We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 10 – Callaway Nuclear Plant and Note 14 – Related Party Transactions Callaway Nuclear Plant The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31,
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity. Leases The following table presents our lease obligations at December 31,
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. The following table presents total rental expense, included in other operations and maintenance expenses, for the years ended December 31, 2010, 2009
Other Obligations To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for
Genco: 2010 2011 2012 2013 2014 Thereafter Total CILCO: 2010 2011 2012 2013 2014 Thereafter Total IP: 2010 2011 2012 2013 2014 Thereafter Total
Also, as part of the 2007 Illinois Electric Settlement Agreement, Environmental Matters We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new significant capital expenditures such as new water intake structures or cooling towers at our power plants; NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units; and a MACT standard for the control of hazardous air pollutants such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our preliminary assessment of the potential impacts of the EPA’s proposed regulations for coal combustion byproducts, the CATR, and the revised ambient air quality standards for SO2 and NOx emissions as of December 31, 2010. The estimates in the table below assume that coal combustion byproducts will ultimately be regarded as nonhazardous. The estimates shown in the table below could change depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly ambient air quality standards or changes to existing standards for SO2 and NOx emissions, the requirements under a MACT standard for the control of hazardous air pollutants such as mercury and acid gases, the requirements under the finalized CATR, any new regulations under the Clean Water Act, a hazardous classification of coal combustion byproducts, new technology, and variations in costs of material or labor, or alternative compliance strategies, among other factors.
The following sections describe the more significant environmental rules that affect our operations. Clean Air Act Both federal and state laws require significant reductions in SO2and NOx emissions that result from burning fossil fuels. In In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method it used to remove electric generating In federal review of the proposed regulation is ongoing and, at this time, we cannot predict the estimated capital or operating expense for compliance with the CATR, assuming the CATR is adopted. The EPA expects the CATR to Separately, in January and June 2010, the EPA finalized a new The state of Missouri We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois in the near term. Under the MPS, as amended, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NOx and SO2 controls. This rule, when fully implemented, is expected to reduce mercury emissions by 90%, NOx emissions by 50%, and SO2 emissions by 70% by 2015 in Illinois. To comply with the rule, Genco EEI’s Joppa plant, but is also reviewing other options. Capital requirements for dry sorbent injection would be lower than for scrubbers. Several projects are planned to manage the solid and liquid wastes generated by the SO2 scrubbers at the Duck Creek and Coffeen plants. Additional facilities and upgrades are planned at all Merchant Generation coal-fired plants
Emission Allowances Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NOx Budget Trading Program, and the federal facilities See Note 1 – Summary of Significant Accounting Policies for the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that were classified as intangible assets as of December 31,
The allowances issued for each program. The
Global Climate Change Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. In
Potential impacts from climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for
emissions of greenhouse gases from motor vehicles contribute to that endangerment. Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA
Representatives and U.S. Senate that would delay the Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. NSR and The EPA is engaged in an enforcement initiative targeted In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. In January 2010, UE received a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V programs. In the Notice of Violation, the EPA contends that various
Clean Water Act In July 2004, the EPA issued rules under Section 316(b) of the Clean Water Act that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts on aquatic species. These rules In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under Section 316(a) of the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are developed based on the effectiveness of available control technology. The EPA is engaged in information collection activities in support of this rulemaking and has indicated that it expects to issue a proposed rule in July 2012 and finalize the rule in 2014. We are unable at this time to predict the impact of this development. Remediation We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. UE As of December 31, litigation costs associated with its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC. As of December 31,
The following table presents, as of December 31, 2010, the estimated probable obligation to remediate these MGP sites.
AIC is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of December 31, UE UE also has a federal agency mandate to clean up a site in Illinois. In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of December 31, In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine whether such practices will result in future environmental commitments or Ash Management There has been increased activity at both state and federal levels
costs associated with compliance with the proposed regulation of CCB impoundments In addition, the Illinois EPA has requested that Ameren, UE
Pumped-storage Hydroelectric Facility Breach In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. UE settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. UE In June 2010, UE sued an insurance company that was providing UE with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the U.S. District Court for the Eastern District of Missouri, UE claimed the insurance company breached its duty to indemnify UE for the losses experienced from the incident. In January 2011, the judge ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. In February 2011, UE filed an appeal of the January ruling to the U.S. Court of Appeals for the Eighth District, which seeks resolution outside of a dispute resolution process. UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk
Until Ameren’s remaining liability insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and UE’s results of operations, financial position, and liquidity beyond those amounts already recognized. reconstruction, expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that were not at that time reasonably foreseeable and costs that would have been incurred absent the Taum Sauk incident. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the in-service date of the rebuilt facility. As of December 31, Asbestos-related Litigation Ameren, UE, The claims filed against Ameren, UE, The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31,
At December 31,
Illinois Sales and Use Tax Exemptions and Credits InExelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court denied certiorari, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible applies to sales and use tax manufacturing exemptions and credits. While it is possible that Illinois will take the position that Genco and AERG do not qualify for the manufacturing exemptions and credits, we do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. During 2010, Ameren and Genco claimed manufacturing exemptions and credits of $11 million and $8 million, respectively. The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity. NOTE 16 –
In August 2010, prior to the AIC Merger, CILCO redeemed all of its outstanding preferred stock. CIPS redeemed all $40 million of its 7.61% Series 1997-2 first mortgage bonds in September 2010. Following the redemption of those CIPS’ mortgage bonds, a release date occurred with respect to CIPS’ senior secured notes, causing these notes to become unsecured, and CIPS’ mortgage indenture to be discharged. Also in September 2010, Ameren contributed to the capital of IP, without the payment of any consideration, all of the IP preferred stock owned by Ameren. IP cancelled those preferred shares. Upon the AIC Merger, the debt and other obligations of CILCO and IP under their mortgage indentures, senior note indentures, and pollution control bond agreements become debt and obligations of AIC. The property owned by CILCO and IP immediately before the AIC Merger that was subject to the lien of their respective mortgage indentures remained subject to such lien, which continued to secure the bonds outstanding under such mortgage indenture subject to the release and other provisions of such mortgage indenture. The senior secured notes of IP and CILCO remained secured by the mortgage bonds held by their respective senior note trustee, subject to the release and other provisions of the respective senior note indenture. The debt and other obligations of CIPS remained debt and obligations of AIC. AIC secured the senior notes issued by CIPS with the benefit of a lien under the IP mortgage indenture. AIC also encumbered substantially all of the fixtures and equipment owned by CIPS immediately before the AIC Merger with the lien of the IP mortgage indenture. At the time of the AIC Merger, the common stock of CILCO and IP, all of which was wholly owned by Ameren, was canceled without consideration. Then, pursuant to the merger agreement: (i) every two shares of each series of IP preferred stock outstanding immediately prior to the AIC Merger were automatically converted into one share of a newly created series of AIC preferred stock having the same payment and redemption terms as the existing series of IP preferred stock, except to the extent that IP preferred stockholders exercised their dissenters’ rights in accordance with Illinois law; and (ii) each outstanding share of CIPS common and preferred stock remained outstanding, except to the extent that CIPS preferred stockholders exercised their dissenters’ rights in accordance with Illinois law. Stockholders holding approximately 8,337 shares and 423 shares of CIPS and IP preferred stock, respectively, exercised their dissenters’ rights. In its application for the We received an IRS private letter ruling on July 16, 2010, stating that the AERG distribution qualified as a generally tax-free transaction. The AERG distribution occurred immediately after the AIC Merger. AIC determined that the operating results of AERG qualified for discontinued operations presentation; therefore, AIC has
The following table summarizes the
NOTE 17 – GOODWILL AND OTHER ASSET IMPAIRMENTS The following table summarizes the goodwill and other asset impairment pretax charges recognized in 2010:
Each of the
The goodwill and
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, a second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and Ameren has identified three reporting units, which also represent Ameren’s reportable segments. The Ameren reporting units are Ameren Missouri, Ameren Illinois, and Merchant Generation. Genco has one reporting unit, Merchant Generation. AIC has one reporting unit, Ameren Illinois. Ameren’s reporting units have been defined and goodwill has been evaluated at the operating segment level in accordance with authoritative accounting guidance. As previously disclosed, based on the results of the annual goodwill impairment test completed as of October 31, 2009, the estimated fair value of Ameren’s Merchant Generation reporting unit exceeded its carrying value by a nominal amount. During the
Accordingly, we performed interim goodwill tests of Ameren’s and Genco’s Merchant Generation reporting units as of August 31, 2010. The fair value estimate of Ameren’s and Genco’s reporting units was Ameren’s Merchant Generation reporting unit and Genco’s Merchant Generation reporting unit failed step one of the August 31, 2010, interim impairment test, The annual impairment test, conducted as of October 31, during the remainder of cash flows, an unfavorable change in forecasted operating results and cash flows, or a decline of observable industry market multiples may Ameren and
The following tables provide a reconciliation of the beginning and ending carrying amounts of goodwill by reporting unit, for Ameren, AIC and Ameren
Genco
Long-Lived Assets We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value. As a result of factors described in this note, Ameren and Genco evaluated their long-lived assets and recorded noncash, pretax asset impairment charges of $101 million and $64 million, respectively, to reduce the carrying value of certain generating facilities to their estimated fair value during 2010. Key assumptions used in the determination of estimated undiscounted cash flows of the generation assets tested for impairment included the forward price projections for energy and fuel costs, the expected life of the facility, environmental compliance costs, and operating costs. Those same cash flow assumptions were used to estimate the fair value of the long-lived assets whose carrying values exceeded their undiscounted cash flows. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted future cash flows, and the market approach, which considers market comparables within the electric generation industry. We used our best estimates in making these assumptions. Although the undiscounted cash flows exceeded the carrying value of certain of Ameren’s and Genco’s generating facilities, the estimated fair values of these generation facilities at August 31, 2010, which were not impaired, were below the carrying value of these assets. More stringent environmental regulations than anticipated or declines in market prices for energy would affect the assumptions used by Ameren and Genco, including the expected life of the facility, as the expected return from these generation assets might no longer justify additional capital expenditures or their continued operation. Changes in these assumptions could result in further asset impairments, if the estimated undiscounted cash flows no longer exceed the carrying values. In 2009, Genco recorded asset impairment charges of $6 million as a result of the termination of a rail line extension project at a subsidiary of Genco and to adjust the carrying value of an office building owned by Genco to its estimated fair value as of December 31, 2009. The charge related to the office building was based on the net proceeds from its sale in 2010. In addition, AERG recorded an asset impairment charge of $1 million to adjust the carrying value of its Indian Trails generation facility’s estimated fair value as of December 31, 2009. This charge was based on the net proceeds from the sale of the facility in January 2010. In 2008, asset impairment charges were recorded to adjust the carrying value of AERG’s Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008. AERG recorded an asset impairment charge of $12 million related to the Indian Trails generation facility as a result of the suspension of operations by the facility’s only customer. Ameren recorded a $2 million impairment charge related to the Sterling Avenue CT. The charge was based on the net proceeds generated from the sale of the facility in 2009. The 2009 and 2008 asset impairment charges were recorded in Goodwill and other impairment losses in the applicable statements of income and were included in Merchant Generation segment results. Intangible Assets We evaluate emission allowances for impairment if events or changes in circumstances indicate that they will not or cannot be used in operations. Previously, Ameren, UE and Genco expected to use their SO2emission allowances for ongoing operations. As discussed above, in July 2010, the EPA issued the CATR, which would restrict the use of existing SO2 emission allowances. As a result, Ameren, UE and Genco no longer expect all of their SO2 emission allowances will be used in operations. Therefore, during 2010, Ameren, UE and Genco recorded an impairment charge to reduce the carrying value of their SO2 emission allowances to their estimated fair value. Ameren’s and Genco’s noncash pretax impairment charge was $68 million and $41 million, respectively. UE recorded a $23 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to SO2 emission allowances. Therefore, the UE SO2 emission allowance impairment had no impact on earnings. The fair value of the SO2emission allowances was based on observable and unobservable inputs. Inputs for Fair Value Estimates Both observable and unobservable inputs were used in determining the estimated fair value of our long-lived assets, goodwill, and intangible assets. These assets are measured at fair value on a nonrecurring basis if triggering events require us to perform impairment tests, which are level 3 within the fair value hierarchy. NOTE 18 – SEGMENT INFORMATION Ameren has three reportable segments: Ameren Missouri, Valley and Marketing Company. The category called Other primarily includes Ameren parent company
The following Ameren
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
Operating Revenues Operating Income UE March 31, 2010 March 31, 2009 June 30, 2010 June 30, 2009 September 30, 2010 September 30, 2009 December 31, 2010 December 31, 2009
None.
Each of the Ameren Companies was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the
As of December 31,
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision of and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of each of the Ameren Companies’ internal control over financial reporting based on the framework inInternal Control Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that internal controls might become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures might deteriorate.
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.
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of
Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Executive Officers of the Registrants” in Part I of this report. UE, for their boards of directors. These companies have no securities listed on the NYSE and therefore are not subject to the NYSE listing standards. as members. The board of directors of Ameren has determined that Also, on the same basis as reported above, the boards of directors of UE, To encourage ethical conduct in its financial management and reporting, Ameren has adopted a Code of Ethics that applies to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the and employees of the Ameren Companies. It is referred to as the Corporate Compliance Policy. The Ameren Companies make available free of charge through Ameren’s Compliance Policy as it relates to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the controller and the treasurer of each of the Ameren Companies will be posted on Ameren’s
Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its
Equity Compensation Plan Information The following table presents information as of December 31,
UE, Security Ownership of Certain Beneficial Owners and Management The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its
Information required by Item 404 and Item 407(a) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of UE
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
AMEREN CORPORATION (parent company only) NOTES TO CONDENSED FINANCIAL STATEMENTS December 31, NOTE 1 – BASIS OF PRESENTATION Ameren Corporation (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes under Part II, Item 8, of this report. NOTE 2 – LONG-TERM OBLIGATIONS See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of long-term obligations of Ameren Corporation (parent company only). NOTE 3 – COMMITMENTS AND CONTINGENCIES See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of Ameren Corporation (parent company only).
NOTE
See Note
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; UE, 1-2967; *Compensatory plan or arrangement. **Attached as Exhibit 101 to this report is the following financial information from Ameren’s Annual Report on Form 10-K for the year ended December 31, Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
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